Origin Energy Ltd Ord

Okay, good morning, everyone, and welcome to the Origin Energy 2023 full year results presentation. I'm Frank Calabria, and I'm here with the executive leadership team of Origin, and you'll hear from me and Laurie Tremaine, our CFO, as usual, and then we will follow that with questions. So on slide two is an outline of the presentation today, and hopefully for those of you who've been here before, it's a familiar format. Okay. I think the key messages on slide four are that it's been a strong earnings result and outlook for Origin. The operational performance right across the business has been strong, and we've had increased earnings contributions from energy markets, integrated gas, and also Octopus Energy in the U.K., The energy market's earnings improved following a period of under-recovery of wholesale energy costs, and we are expecting further earnings growth for energy markets into the financial year 2024. And with this, the returns will recover towards earning its cost of capital. We've had a step-change earnings growth in Octopus Energy, and Laurie will take you through that a little further. It's an underlying EBITDA gap. our share, our origin share for the 20% of $240 million, and that's up from a loss of $36 million last year. So clearly a step change. And APL&G production rebounded in the second half. We have delivered record revenue and cash distributions. It did benefit this year from the the elevated commodity prices, but very pleased to see the production performance over the last six months following the challenging first six months associated with La Nina. What you will see today is that we've taken the step to now report octopus results as a separate segment, and Laurie will explain that further. In relation to the proposed acquisition of Origin by a consortium that's consisting of Brookfield Asset Management and Mid Ocean Energy, that transaction continues to progress through the necessary regulatory steps. And in particular, the ACCC and the FIRB approval processes are underway. We continue to believe that Origin is very well placed to capture value from the energy transition. Through our advantage portfolio, being positioned for growth, and also with a platform for transition investment, and we'll talk through those as we go forward. We are executing our strategy at pace to capture this value and also to achieve our ambition, and the energy transition will require significant investment, and it's critical for government policy to support both investments and, most importantly, a successful and sustainable transition. So now just turning to the key financial highlights, you'll see that we've recorded a statutory profit of just over a billion dollars up from a statutory loss last year. That's been driven by the rise in underlying profit. And Laurie will take you through those drivers that have increased at $300 million to $747 million. And on the back of that earnings growth, the origin return on capital employed is 14.2%. And that's after adding back the impairment of goodwill that we recorded last year and explained in detail why we're required to do so. Our adjusted net debt remains flat. The ratio, clearly, of debt to EBITDA has improved, therefore, to 1.2 times. And you'll see that the adjusted free cash flow is down despite the growth in earnings, and that's really due to high working capital requirements, which Laurie will take you through in further detail. The board has declared a final fully frank dividend of 20 cents per share and reflects the strength of the recovery and performance and also our confidence as we look ahead. Page six is a slide you would see before. It sets out our ambition and strategy. Our ambition is to lead the energy transition through cleaner energy and customer solutions. And our strategies are across three pillars, unrivalled customer solutions, accelerate renewable and cleaner energy, and deliver reliable energy through the transition. And you'll see that we've set that framework up to continue to report against that. And it also highlights how we will create value from each of these strategies. And then turning to slide seven, you'll see how we are executing on that strategy. You'll recall that the ambitions on the right-hand side were those that we'd set out on a medium term when we launched our refresh strategy in early 22, and we've continued to stay focused on achieving those. And what you can see on the left-hand side is a number of the achievements to date. I think we will cover most of those items in some way as we go through the presentation, so I'll endeavour not to duplicate that now. Just a couple of things that may not come up. in great detail later. Obviously very pleased in the case of accelerating renewables and cleaner energy to advance the Hunter Valley hydrogen opportunity where we've been well supported by the federal government and in discussions with New South Wales government. So really advancing that through the feed phase and working with our partner, Orica, to advance that project. The other reason in terms of a simplified portfolio and focus, you'll see that in terms of delivering reliable energy through the transition, the exit of upstream exploration and appraisal, which we have now achieved the Beta Luce sale completion and the Canning and Cooper Aramanga Basin exits have been executed but are pending regulatory approval. So really highlighting I think those two because we may not come up with them later. Probably the other one, just we've made some advancement on wind development, New England RES acreage, and also the joint venture in the early feasibility licence process for the Gippsland offshore wind tender. So we continue to do that in addition to our storage and other opportunities. Focusing on why we believe we are well placed to capture value from the energy transition on slide eight, the advantage portfolio, I think it's worth mentioning. recognising that we have a leading retail business which will talk through a competitive gas supply, the largest thermal peaking fleet, which will be very important through the transition as we move away from coal towards renewables, a very high-quality APLNG gas resource, and just emphasising the point I just made before, that we continue to simplify the portfolio, which is enabling us to focus our capital allocation into the areas that are aligned to our strategy and continue to drive our growth. When it comes to being positioned for growth, we will cover the growth in the virtual power plant, including the value we create from that. the multiple product offerings, particularly the growth around broadband and EV, which you'll see evidence of, and also the growth businesses on Origin Zero and community energy services, all of which we'll touch on a little further on the slides. And we'll cover in more detail, given the materiality of what's emerging in Octopus as a driver of growth of earnings for us and talk about how you should think about that business. As a platform for transition investment, you can see there is a transition underway. It's a significant, in fact, staggering scale that needs to be delivered. And I think the way we've set up the business as a platform to enable that investment on the retail scale, having the firming generation with gas supply, the upcoming ARAR enclosure and the emergence of renewables and storage, large scale investment opportunities really does enable us to move into that transition. And in addition to that, advancing opportunities, carbon products more in the nearer term and obviously the hydrogen developments with the nearest term opportunity there being in the domestic market and the Hunter Valley. But we continue to also pursue export project as export projects as well. Now, turning to slide nine, and this slide, you may recall, for those of you that were on the half-year results, shows the targeted earnings trajectory, and this is a reproduction of that earnings trajectory for energy markets and octopus that we presented at the half-year results in February, but just with a few important updates, and I'd focus your eyes onto the four dot points at the top. The first one of which is that the trajectory for financial year 24 to 25 has now been superseded by the guidance we're providing today for the financial year 24 for energy markets. Those financial year 24 earnings guidance for energy markets are higher than previously expected. And with that higher expectation, the trajectory, therefore, between 24 and 25 that we expect today as we look forward is that there will be a reduction in electricity gross profit. And therefore, that's why you've got the dark shading on the left-hand side of the chart. What is important, I think, to remember is that we remain committed to the medium term earnings trajectory. And you can see all of those growth and value drivers on the right hand side. And since that update in February, we see further upside potential to the octopus earnings compared to the trajectory that's shown below. In relation to those growth and value drivers, I'm now going to just cover a few of the key number of them over the following slides. the thermal peaking fleet, the virtual power plant and octopus so that you can connect that through to strategy and value. And then there'll be further information when I come back and discuss the operational section. Turning to the next slide, the thermal peaking fleet. We've highlighted it. It is part of our Advantage portfolio. We're very proud of it. We have the largest peaking fleet in the market. It covers 50% of our retail load capacity. It's underpinned by fixed gas supply and transport flexibility, and it continues to perform very well. The capacity value, as measured by the forward capacity prices that you can see on the right, has continued to grow over the last several years and will grow into FY24. Those prices, we believe, reflect the higher cost to build capacity that's really underpinning, therefore, the market price for capacity. This fleet's very valuable as the energy market transitions away from coal and renewable energy supply grows. The second value driver, very pleased to see the progress that we've made in relation to our in-house virtual power plant, which we call Loop. And what you can see there is that we have grown the megawatts connected by over three times this year to 815 megawatts. So the team have delivered a lot of growth. We're on our way to a two gigawatt ambition that we set at the time of launching the strategy by the financial year 26. To put that into context, in the nature of our virtual power plant, that has now in excess of 270,000 connected assets or devices that are now being operated through that virtual power plant. And if you want to put 815 megawatts into context, it's bigger than the largest single unit of generation in the market. In terms of the way the value pools on the right-hand side, think about them as wholesale, which is moving low to times of lower prices, capacity in our ability to actually add supply and reduce demand at short notice, participating in the frequency control and ancillary service markets, and also has the opportunity to create value with networks by avoiding network augmentation costs, which are more expensive. And what's very important in the relation to a virtual power plant is its relationship with customers. And a critical component is how those benefits are shared with our customers over time. So not only does it represent a very cost-effective form of capacity, but it also increases the engagement we have with our customers and we believe delivers competitive advantage over time. So very good to see the progress we're making there. Now turning to Octopus, and it has grown significantly and has further growth potential that is also significant. I would like people to think about Octopus as the following. It's an energy retailer, largely in the UK, but emerging in other markets in Europe and the US. and Japan. It's also a technology platform business to utilities through its Kraken technology, which it licenses. And there is a third limb to the business, which is an energy services business, which is growing, which includes EV leasing, heat pumps, and also has a large amount of renewable assets that it manages on behalf of third parties. So it continues to grow that. When we talk about the retail business, it's now grown to be the second largest retailer by customer accounts, 9.7 million customer accounts and continuing to grow. The market, which we'll describe, I'll show you a little later, it obviously went through some of the similar challenges we did 12 months ago in its own winter. And you'll also see just the strength of the brand that exists. There are now 32 million accounts on Kraken, I should say, contracted to be on the platform. And so there's a lag from when they contract them to be on the platform when they're on. But you can see that that's also grown significantly and it's now operational in energy markets across 10 countries. And it has actually signed its first deal with water and broadband, so expanding into further utilities. To give a It's a private company, so we're just giving a sense for value and what's happened since the last, I think, benchmark or mark to market. The last time it raised equity, it was at a value of 3.5 billion pounds in December 21, at which time CPPIB invested. Since that time, it has doubled its customer accounts, including the bulb acquisition. It's delivered the earnings you're seeing today for the financial year 23, and it has grown contracted Kraken customer accounts by over 50%. It remains very important to us that we deliver for all stakeholders. When we turn to slide 13, you'll have seen this before, and it's very important that we continue to measure our progress and hold ourselves accountable. When we look at our customers, what we do see is that our strategic NPS has declined this year. We do see it overall in the market, but it does spur us on to actually continue to to improve customer experience. At the same time, it's very important for us to support those customers in hardship, and we have significantly increased our support this year on top of the $30 million we've spent in the financial year just gone by. For our communities, we've once again increased our regional and indigenous procurement spend. Our foundation continues to make a meaningful contribution to education. And importantly, as part of our transition away from Araring, we have launched an Araring Community Fund in addition to the many other initiatives that are underway in our preparation for the closure and transition of Araring. In relation to our planet, we received very strong support for our Climate Transition Action Plan last year. We did achieve our short-term target of reducing emissions by 9.1 million tonnes. They were Scope 1 emissions over the last three years. But the last year highlights just it won't always be a smooth trajectory on our way to achieving our medium-term goals, as we were required to increase electricity generation for Mooraring and to support the market. And as a result of that, you can see that our emissions for the last 12 months, Scope 1 and 2, are up by 4%. We remain very focused on our targets that we've set, and we continue to invest and advance our transition ambitions, as you can see through our strategy. And one of those is the investment in the Stage 1 Araring Battery, which is underway. We also reduced operational emissions, flaring emissions, by 35%, which is a great achievement by our integrated gas team. For our people, our safety performance improved, not where it needs to be, but has improved. Employee engagement improved. We grew female senior leaders. We launched our second reconciliation action plan, and 93% of our RRing employees now have individual support plans in place as part of our preparations for closure. Just turning to slide 14, the energy infrastructure challenge before us is staggering. It requires ambitious goals, coordination across governments, industry and market operators. It requires good policy and effective execution. And we also recognise it needs leadership from companies like Origin, and we certainly do relish that opportunity. It is critical, however, that policy supports the investment required and to deliver a sustainable energy transition. There will be substantial investment that's needed in renewables, transmission, short and long duration storage. And a capacity mechanism will be critically important to enable investment in gas fire generation, which will be needed as part of the mix in addition to the other storage technologies as we grow renewables. And it will also be important in ensuring the orderly transition away from coal. Just noting the comments there on the coal policy that were enacted during the energy crisis, they have placed downward pressure on electricity prices, and they also did ensure supply to O'Reilly during a critical period. So I will now pass over to Laurie, and then I'll come back, and we will go into a bit further depth on the operational review.

Thanks, Frank. Good morning, everyone. The underlying profit bridge on slide 16 shows an increase to $747 million, as Frank said, $340 million higher than the prior year, with a positive contribution from each of our businesses. The recovery of earnings in energy markets was a key driver, along with continuing strong commodity prices underpinning earnings at APLNG. Our share of net profit at Octopus was $139 million compared to a $88 million loss in the prior year. Tax on underlying earnings increased by $543 million due to the stronger energy markets earnings and tax on unfranked dividends from APLNG. So moving to cash flow on slide 17. Operating cash flow for the year reflects the unwind of the impacts extremely high commodity and pool prices at the end of the last financial year had on working capital and collateral balances. Very high pool prices in June 2022 resulted in large creditor position with AEMO, reducing net working capital. Very high commodity prices at June 22 also resulted in high futures exchange collateral inflows in that year. These working capital and collateral cash flow benefits in 2022 have unwound in 2023 with lower pool and commodity prices. Capital expenditure was $139 million higher, mainly due to early spend on the 460 megawatt battery investment at Araring, investment in renewable development opportunities and ash dam stabilisation and related expenditures at Araring. We made further equity contributions to Octopus Energy of 173 million to maintain our 20% ownership. And finally, we received 70 million net proceeds in the year for the sale of our Beetaloo equity interest. Slide 18 further demonstrates the impact of working capital, futures collateral, and also the LGC shortfall charge on energy markets cash conversion. This chart shows energy markets EBITDA, the black line plotted against cash flow. Over time, operating cash flow in red should approximate EBITDA, but there can be timing impacts from year to year. The chart shows relatively low operating cash in 2023, despite higher earnings. This is mostly a function of the unwind of June 22 high pool and commodity prices mentioned just now. The prior year's results also benefited from high futures exchange collateral inflows shown here in yellow, which also went unwound in 2023. In blue is the $65 per certificate shortfall charges we've paid for under delivery of LGCs. The shortfall payment made in 2023 is likely to be the last, and we now expect refunds in the coming years. And just to be clear about that, we're expecting gross non-tax accessible refunds of around $600 million. And at the same time, we'll pay the cost of the forward certificate purchases of around $180 million. And so we're expecting a net inflow of $420 million across financial years 2024 to 2026. We expect improved cash conversion in 2024, assuming the current more stable price environment. The slide 19 shows how distributions from APLNG have grown over recent years and also the form of these distributions. In 2023, we received record distributions of $1.78 billion, despite this being the first full year of the reduced 27.5% equity participation. 2023 was also the first year all distributions were in the form of unfranked dividends. This has resulted in increased reported tax expense in origins results for the year. We expect APLNG carried forward losses to be fully utilised in financial year 2024 and for them to commence paying tax and franking dividends in the following year. The cash generation performance of APLNG was once again outstanding. On a 100% basis, $8.2 billion of cash was generated after paying Queensland royalties of $930 million. Investment spend was only $400 million and debt servicing just over $1.2 billion, allowing total distributions of a very impressive $6.5 billion. On slide 20, the board has determined a fully frank final dividend of $0.20 per share, taking full-year dividends to $0.365 per share. The full-year dividend represents an adjusted free cash flow payout ratio of 66% above our policy range of 30% to 50%. The higher dividend payout this year reflects the strength of the recovery and financial performance and the Board's confidence in the future. In support of this point, our balance sheet leverage is currently well below our target range at 1.2 times debt to EBITDA. Turning now to energy markets earnings on slide 21. Energy markets EBITDA was $637 million higher, driven almost equally by electricity gross profit up $366 million and gas gross profit up $379 million. Slightly offsetting this, costs to serve were up $89 million, largely due to higher bad and doubtful debt expense with higher bill sizes and rising customer cost of living pressures. The increased electricity gross profit arises from higher wholesale prices, mostly incurred in prior periods, being flowed into both business and mass market regulated tariffs. The benefit of higher tariffs was partially offset by higher fuel costs in the current year, primarily coal and higher net pool costs. Gas customer tariffs also repriced, reflecting higher current and prior year purchase costs. Energy markets exposure to JKM index prices were largely hedged, but at prices higher than the prior year. On slide 22, we've reported octopus energy as a separate segment for the first time. We will do this going forward given its increasing materiality. Origin's share of Octopus EBITDA was $240 million, up from a loss of $36 million in the prior year and an $83 million loss in the first half. There are two main drivers of this improved performance. Firstly, losses from the prior year and first half resulted from sharply higher costs of energy that were unable to be passed through to customers due to the lag in the regulated tariff reset. The change to quarterly tariff resets during 2023 allowed high costs incurred in the half one to be recouped in half two. And secondly, the increase in customer accounts with a six month contribution from the two and a half million additional customers via the bulb energy acquisition and also continuing organic growth. Kraken licensing revenue was slightly lower as the prior year included higher one-off milestone and performance payments. Recurring revenue will increase as customer accounts go live on the Kraken platform, but typically only when the full migration of projects is complete. Turning lastly to integrated gas earnings on slide 23. Excluding the impact of the equity sell-down, our share of APLNG earnings were up $355 million, with continuing strong global oil and gas prices the major driver. APLNG continues to benefit from good field performance, enabling the deferral of development activity. However, the cumulative impact of three years of La Nina-related wet weather negatively impacted production and sales volume and operating costs in 2023. LNG volumes were lower, impacting spot sales with seven spot export cargoes delivered in the year compared to 15 in the prior year. The domestic gas market was prioritised in the year given this lower production. Operating costs were $176 million higher, with higher royalties associated with higher prices, the commencement of a multi-year cyclical maintenance program, and the impacts of wet weather, including higher gas purchases and increased workover activity. Our LNG trading activities generated a gain of 58 million compared to a loss of 23 million in the prior year. This was largely a result of locking in favourable hedging during the period of disruption in global gas prices. Substantial gains from LNG trading are also forecast over the coming three years, again, as a result of this timely hedging activity. So with that, I'll hand you back to Frank for our operational performance update.

Okay, thanks very much, Laurie. And now turning to the operational review and starting with energy markets, you'll see on slide 26 really a timeline of events over the two halves of the financial year we've just been in and just how much has changed between those two halves and then also how that flows through to the outlook for the 24 financial year. I think the key points to note really coming through the second half and into the outlook was for the second half, really, we've seen lower electricity and gas spot prices. It was a milder summer. And then in addition to that, the coal price cap was introduced in December 22, which did moderate fuel costs. There's no change to mass market tariffs that occur in the half. They all occur really around 1 July or 1 August. So there's no impact for that in the second half. But as you look forward to FY24, and these will sit as key drivers, I think, for the growth in our earnings, you have got the tariffs increasing that are recovering the higher costs we did incur through 23. The coal price cap continues to 30 June 24, and then from 25 we'll be purchasing coal at market prices. And on the basis of where we see the forward price curve today, recognising there's a lot more to happen in relation to that to set prices, we're seeing a moderation in tariffs expected in 25. The next slide really does highlight, I think, that analytically so that you can see it in terms of prices and contribution. You can see, therefore, the forward curves in New South Wales on the left-hand side highlighting what happened over the various years and how that's forming into the tariffs. You can also see through the yellow there just where we see FY25 at this point. Coal prices moderated. They did moderate in market, but you can see the introduction of the cap and its impact there. And also when you then see the error in contribution, it just shows the margins that have therefore that really disappeared, in fact, to be loss making in the first half of 23 and therefore the recovery of that into the second half. Turning to gas margin, there is a higher gas gross profit unit margins. There was the combination here of two things, really the repricing of tariffs as we recover those wholesale costs, but also there were trading gains in FY23 that we don't expect to fully repeat in 24. And those trading gains are really around the timing of hedge execution associated with JKM. And we now are sitting in a position where the majority of our JKM exposure is set for FY24. And therefore, we'd expect unit margins, as you can see on that left-hand chart in the red there, to come back to the long-term trend of closer to $3 a gigajoule. The gas supply continues to be a source of strength and that we have a balanced supply and demand. It's really underpinned by fixed price, I should say, with CPI indexation on those contracts and transport flexibility. Clearly, the key event for gas pricing this year is the beach price review, which is ongoing. It is effective from 1 July, but has not been concluded. Turning to retail competition on slide 29, you can see just how much it was muted during FY23 and that it's actually returned with stronger headline discounts as we approached the last quarter of the financial year, 23 quarter four financial year. And also, as we've come into the first month, origins churn continues to be below market. And overall market churn is definitely lower over the course of the year than FY22. You can recall that it's not that long ago that we saw those events that led to 10 retailer of last resort failures that really occurred over this financial year. We continue to grow our customer base. We continue to adopt a value-based approach with products, pricing, channels, and renewals. We're rated 4.6 stars on Trustpilot. And we utilize the Customer Happiness Index now that we'll continue to measure going forward. And you'll see that that's sitting at 65%. System migration to Kraken or customer migration to Kraken on slide 30, they're big projects. I'm very pleased to say that we have all of our customers migrated and we're in that period of stabilisation. We're very confident in the Kraken platform and the unique operating model that delivers both customer experience and lower cost. And we're in the midst of actually operationally betting that down. We continue to support our customers through cost of living pressures. I mentioned earlier through the support to vulnerable customers of 30 million in the last financial year. You will see our bad and daffled debts that have risen by 74 million. And that's on the back of cost of living. It's also on the back of larger bills coming through. We remain very focused on our targeted cost savings of 200 to 250 million, but what you will note here is we've moved the achievement of that from 24 to 25. It is really all driven by just the time it'll take us to stabilise and the run rate of those savings, but the destination and the target remain the same. And if you were looking on a bad and debtful, if you excluded the rising bad and debtful debts, just to give a context to that, we're $150 million on the way through to that turn on $250 million. We've set up growth opportunities on slide 31. You can see our community energy services business, the contribution that's come in a full year from WinConnect now means we have services there provide to 442,000 customer accounts and a good growth profile there. It's a very good business and the team are doing a good job of continuing to deliver. Broadband, where now I think it's since the results of we've ticked over 100,000 customers, continuing to get good customer service ratings, very important for the brand for us that we grow that and we grow a good customer experience along the way and remain very focused on how we can continue to accelerate that growth. And then you can see on the right hand side what I touched on earlier in relation to the growth for the virtual power plant. Origin Zero was established, I think, somewhat about 18 months ago, probably less than 18 months ago, which really is serving our business customers not only for their core commodity product, but actually taking them on the decarbonisation journey to net zero. We are gaining momentum in new products and services, and you can see the percentage increase of customers that are now getting services broader than the core commodity. We've launched several new products. We're getting good, strong early demand. One of those is through EV subscription, solar PPA, and we've also enhanced the digital tools for customers to be able to engage with us, including the upgrade to our My Business account. In terms of the core commodity market, it certainly was a challenging time with commodity prices moving around. We were able to keep our electricity volume stable. We grew our gas volumes by six and a half petajoules. And through that period, pleased to see the progress we're making on customer experience as measured by customer satisfaction and strategic NPS. We all know we've got a way to go there, but it's been great progress to see the team make that over the last 12 months. Now turning to Octopus Energy, we've dedicated more material this year. Firstly, just turning to what played out in terms of the UK market. And the left-hand side of the chart shows you what forward prices did since July 21 through to just to now. and also how that's actually played out through to the tariffs observed. The one thing to note in the UK is they have moved to a quarterly tariff reset during the 23 financial year, and that's actually enabled them, particularly from a half one to half two, to recover those higher wholesale costs that Laurie mentioned earlier in the first half have been able to be recovered. And what you've seen in that market was a significant market consolidation as a result of the volatility in the underlying commodity prices. And as you'll all be aware, Europe experienced very significant gas shortages and energy price shocks towards the end of last calendar year. Octopus has navigated that condition very well, those conditions well. Good risk management on the way through. They've actually grown their customer base through that time by 150% to the 9.7 million accounts. That included two acquisitions, Avro Energy and Bulb Energy. Bulb took place in December 22. The one thing that has happened in that market is that, for people not familiar, is they did set a fixed limit on prices towards the back end of the year when they saw escalation. It meant most customers are on now a variable tariff with a quarterly reset. And what Octopus does is they price those as a discount to the regulator called Ofgem's price cap. And that was following a decision made to protect customers from those rising prices. I'll talk a little further about the brand positioning going forward. Through this time, they've also maintained that cost-to-serve advantage. Turning to the next slide, slide 35, the left-hand side really repeats that customer account growth earlier, but you can see the revenue. I think the next two charts, though, on slide 35 highlight just how... unique and how strong the brand and customer focus of this business is. And when you really focus on the middle chart, what their NPS differential is to all of their competitors in the UK energy market, it is significant and being 39 points higher than the industry average. And on the right-hand side, you will see through the YouGov site there just how they are seen as a trusted brand relative to the rest of the market. And so you see this is a business that not only has scale technology, but I think you should also think about the operating model and not only that, the brand and the strength of the brand and the market. In relation to Kraken, I'm just highlighting once again the licensing. It highlights the countries in the middle chart. It recently signed contracts with Plenitude. Plenitude is the international arm of ENI or ENI, as you may know them, the Italian energy business. And they now are running retail operating systems. Kraken is for 50% of the UK market. And with our migration now, 30% of the Australian market by customer accounts. They have built a VPP, which they know as Crack and Flex, on the right-hand side. They've contracted to third parties over 5 gigawatts of dispatchable power. And in relation to their own business, they've now got 380 megawatts of flexible EVs, recognising that EVs have a high penetration in the UK, but they're now managing 380 megawatts of those batteries. So it is one of Europe's largest virtual power plants that they're building at the same time. Turning to integrated gas, the resource base continues to be strong. We continue to have confidence in it. And there have been net positive reserves revision before reduction again. And you'll see that's happened in the non-operated area, reflecting better than expected performance from those operators that we're flowing through to ours. And clearly with 1p remaining at 60% of 3p, we are significantly de-risking that reserve base. It's worth noting there continues to be a large contingent resource base, and it is near infrastructure that exists, and it does provide an opportunity for us to tie in at a low cost new wells, and the plays that are being targeted are close to Condabri Peat and the Spring Gully Fields. So a very good resource base that continues to give us great confidence. The production on the next slide, clearly down by 3%. It's not where we would have liked to start the year and we wouldn't normally start with any explanation with weather. But the significance of La Nina, I couldn't understate given the flooding that did occur in Queensland over months that really had an issue on access. This is not just rain. This is just accessing wells. So what I am pleased to see is that we've been able to rebound on the right-hand side to get back. Once we had that drier weather, it has increased activity and the team have really responded. And we are now very much focused on optimisation activities that are driving those lower well pressures and higher gas flow rates. And we have ramped full capacity for some of the infrastructure, some of the pipelines, the Talinga-Condebrae. And we've also started up the Orana South Loop line. That's just enabled us to sort of increase greater operational flexibility of moving gas to where it's needed in terms of capacity available. I talked earlier, highlight record revenue. Clearly, oil price has driven that. You can see on the left-hand side the profile of those commodity prices, where a large portion of our revenue is driven by long-term LNG export contracts that are linked to the oil price. And you can see that realised oil price this year was $103 a barrel compared to $74 in the previous financial year. Spot cargoes were down this year, not only due to production, but also a prioritisation of domestic market sales. And you continue to see the average realised domestic sale price is well below international net back price. And what we'll do is, on the next slide, just highlight those domestic sales, because you can see a number of those are legacy domestic contracts, but you can also see the short-term domestic contracts highlighted in yellow. I'm now on slide 41. As a percentage of total sales, we've kept that constant. And what you can see is really we've continued to sell in excess of 150 petajoules of gas each year for the last three years to the domestic market. And the slightly lower amount this year is really a reflection of that lower production. Costs are up this year due to a number of things. We certainly have seen increased work over activity and we've been reducing an inventory backlog. The final year of that elevated work over program will be the financial year we're going into now. We're in the middle of a multi-year upstream gas processing maintenance program that will continue and be completed in the financial year 25. And we have increased operator and non-operated well development activity. And there have been some impacts of costs from that, as well as inflation impacting operating costs. We do focus, and we'll expand on this in the next slide, prioritising low cost of supply. And you'll see the way we think about the hierarchy of that, and it's supported by a cultural evolution in our business that the team are making progress on. So just touching on that on slide 43, you can see the way we think about this. The strategy starts with the lowest cost short cycle opportunities to deliver low cost supply. And then as you go down, those levers to production become higher cost and longer cycle. So firstly, we focus on optimising existing wells, and that's all about optimal pressures, downhole pressure, and improving flow rates and there's a continual improvement that's going on and certainly in the second half of the year we've seen good progress. That higher workover activity has increased wells online by 5%, but we've got more of that to come, and clearly getting more wells online through that workover activity and reducing the workover unit cost is a key driver, and also installing optimal pumps for each of the well types that increases well availability, and we continue to learn in that respect. Talked about the infrastructure bottlenecking being those two pipelines that have been brought online, and there will be a suite of additional debottlenecking projects and infrastructure development that enables capacity to be utilised higher. And then what you then come to of the highest cost longer cycle is really the drilling of wells. And the strong field performance and all of the optimisation I've just talked about above has enabled the deferral. of future operating drilling program ramping up. And we have seen at the same time, non-operated development deliver 104 wells. So they've been ramping up some of that activity, but we've been able to defer that. And that's what we're really focused on. Bottom of the slide really just talks about the next evolution in the culture and operating model and performance that we're driving through our organization. And I'd have you focus really just on frontline ownership and an asset-led model that become the key focus of those points. Okay, now turning to outlook. I'm now on slide 45, starting with energy markets and octopus. Energy markets, we give guidance, and I should say, for all of the businesses based on the fact that market conditions and the regulatory environment do not materially change. For FY24 energy markets, EBITDA is expected to be between $1.3 and $1.7 billion. That does exclude octopus energy. And you'll see that that earnings guidance on the right-hand side returns us to recovering towards our cost of capital. It will be through a growth in electricity gross profit as those tariffs reprice. to reflect those costs and as capacity prices have increased and also the continuation of purchasing coal at the prices within the arrangements that have been set up by the government in New South Wales. The gas profit I talked about earlier will moderate based on not repeating the trading gains this year and as our procurement costs increase with supply contracts repricing. In relation to Octopus Energy, it's a business that continues to rapidly grow and continues to invest in its growth, both internationally, the technology platform and its energy services business. We expect that the share of Origins, share of Octopus Energy's EBITDA will be lower in FY24, but it is in a wide range of possible outcomes and does reflect the competition, particularly in the UK retail market, that's a key driver of those range of outcomes. It will be that this year, though, is going to have a full year contribution from Bulb as part of that as well. In FY25, I mentioned at the outset when we were looking at that original one of the slide nine that we expected a reduction in electricity growth profit in FY25 compared to 24. And it really is just assuming the current forward energy prices are maintained and priced into the tariffs. We will get the additional benefit from our cost reduction in FY25 associated with the implementation of our platform. Turning to the guidance for integrated gas, and you can see there the production guidance is between 680 and 710 petajoules. It reflects a return to the stable operations that I think I've highlighted that have been building momentum over the last six months. Unit CAPEX and OPEX will... be between $3.90 and $4.40 a gigajoule in 2024. That is higher. It reflects higher power costs. It reflects the continued workover program to reduce the inventory backlog. And there is higher non-operated development we will have a lower cyclical maintenance cost and that we will continue to deliver benefits through the base production optimization programs. To put that into context, what we've done is given you a unit capex and opex guidance for 25, 26, which are expected to be lower in the range of $3.60 to $4.10, and that will be delivering those initiatives we've talked about on the earlier slides, the production optimisation, the cost of supply initiatives, and also completing that cyclical maintenance program and also lower power costs as we see the forward curves. Now, before any hedging, and the hedging is included on slide 55, we have approximately 41% of our 17 million barrels share of APLNG's oil production exposure already set, and we have 23%. of the JKM price exposure priced in. And they're at, respectively, US$84 a barrel and US$11 at MMBTU, respectively. And then you would have to look at the slide 55 to understand then hedging is in addition to that. And then in relation to our LNG trading business, we've given guidance that we expect that to deliver earnings of $40 to $60 million in FY24. And over the two years of 25 and 26, so the combined two years, a guidance of $450 to $650 million earnings as well there. I'm sure you've absorbed a lot of information. We will now turn to questions, and thank you for your attention as we've gone through those slides.

Thank you. If you wish to ask a question, please press star 1 on your telephone and wait for your name to be announced. If you wish to cancel your request, please press star 2. If you're on a speakerphone, please pick up the handset to ask your question. Your first question comes from Tom Allen from UBS. Please go ahead.

Good morning, Frank, Laurie and the board of team. Congratulations on a strong four-year result. First question is just on the outlook for the Araring Power Station. So you have the option to take the entire plant down from August 25. You commented, Frank, that you've been busy developing support plans for the large workforce that are employed at the plant. Are there any preparations underway to keep all or some of the plant capacity going beyond August 25? And when does that decision need to be made?

Thanks, Tom. There's no change to our plans to exit Araring as early as 2025 August, and that's our base plan. So we don't have any different plan to that. Clearly, we've said and continue to say that we would assess the market over time we're doing that. We also clearly said that we would need to think in advance of closure and the preparations associated with people and local community and a number of other things. But that's our plans at the moment, Tom, so there's no real change to what we've previously said.

Okay, thanks, Frank. And with your coal price caps concluding at the end of FY24, how should we interpret your coal supply arrangements in terms of your current stockpile? What volume of the higher-priced coal will you need to procure to see you through to the planned closure date?

Okay. So firstly, the coal price cap goes through to 30 June 24. We don't have an expectation it continues beyond that date. The arrangements of purchasing that are well set out in terms of procurement arrangements between those suppliers and with the New South Wales Government guidance. And we're doing that and effectively we secure that essentially on a sort of quarterly cycle is the way that works. So think about that between now and 30 June 24. We therefore will be buying coal in market from 1 July 24, and the team are in market and will be layering that in, recognising that we purchased that coal and really need to manage that against how tariffs will be set in that financial year. So they'll be laying that in. And therefore, there will be discussions going on with suppliers at the moment. So therefore, when you think about FY25, We will be buying coal on market from now to set that supply up for that financial year, and that would be reaching close to the closure date. It would be a month or two short of the closure date.

And their current stockpile, Frank?

Greg, I'll let Greg talk coal stockpiles.

Tom, yeah, currently we have a 750,000 tonne stockpile, so quite healthy. The arrangements with the New South Wales government are working well. I think probably the only addition to add here is that Logistics, we've really made some headway here. So most of our coal now comes from the Hunter Valley. So we are training in most of our coal and we are not just relying on the local coal mines via conveyor belts. So we really have sort of spread our coal sources now, which is very pleasing.

Thanks, Ray. Thanks, Frank. If I can sneak another one over in APLNG. I'm keen to just understand... You spoke to the drivers of higher year-on-year production, but what proportion of that uplift is sort of weather-related compared to the optimisation activities and the stronger flow rates? And the second part to that question is, given the policy pressure in Australia to put more gas into the domestic market, how should we expect the uplift in production to be directed between Spot LNG and East Coast domestic gas sales, recognising that... those sales are likely to be capped to the $12 gigajoule cap price.

Okay, thanks, Tom. Just on the first question, just so I'm clear, I assume the question was in relation to the fact that we're guiding the production in 24 to be above what we delivered in 23. Is that the difference you're focusing on, just so I'm clear? Correct. Yeah, okay. Correct. So how much of that is driven? Well, if you looked at the second half run rate, and I'll get Andrew to add some comments, if you looked at that second half run rate, we would be certainly moving towards the middle of that range just based on the fact that we've been able to get back to daily production. So I think that's a bigger drive, and I'll get Andrew just to add some layers to that, and then he'll take you through how the marketing of gas works for APLNG under the various mechanisms so you can put that into context.

Yeah. Hi, Tom. So just dealing with that first question to start with. So, yeah, as Frank said, we're already at a run rate. We've been producing at a run rate in the second half of 23 that allows us to continue that into 24. And so there's no required uplift on a run rate basis to hit the 24 numbers. What we will continue to do in 24, though, is and this is reflected in the costs, there's still an inventory or a backlog of inventory of work over wells that are required to be brought online. We'll do that. That'll help support production. And then beyond that, what we'll do is continue to optimise the wells that are online in the way that we normally do through optimising pressures, et cetera. So just the one thing, though, probably if you're trying to draw the record production run rate into 24, just note that some of the... At the time we were doing the record production in 23, there's obviously no planned maintenance or unplanned maintenance. So the thing to remember into 24 is we do have still some major turnarounds of our GPFs that have to be factored into that.

And then on the second?

Yeah. So on the way we'll market gas, we are operating and in compliance with the heads of agreement that exist today. And so what that means is we offer all of our uncontracted volume into the domestic market first. And so that's what we have been doing. That's what we'll continue to do. And really domestic demand will determine how much of that volume goes in the domestic market versus accessing spot cargoes. Thanks, Andrew. Thanks, Frank. That's clear.

Okay. Thanks, Tom.

Thank you. Your next question comes from Dale Conders from Baron Joey. Please go ahead.

Morning, guys. I was wondering if you could provide any colour on expectations for the independent expert report timeframe.

Did you say independent expert report?

Yeah, correct.

Yeah, look, the independent expert process is underway, but the Finalisation of that independent expert report will need to be very close to the time when you are sending out scheme booklets for purpose of vote. So I can't give you certainty on time because we're in the midst of ACCC and FIRB approvals, and therefore that timetable will drive, I think, overall transaction timetable, and therefore the independent expert's timing will need to fit in with that timetable. So hopefully that makes sense. That's the reason why we can't give you a definitive date because it'll all have to match up on transaction timetable.

Is there anything you can say about ACCC or CERB that's going according to plan or any concerns or any watch points?

Well, it's really a matter for the consortium, and they're the ones that are engaging with ACCC. So I can't really add more to that. It's actually their application. You know, I get the information that you get in terms of the letters that are issued and the progress, but they've requested a 30-day extension, the ACCC, and the consortium's engaging with them. But I really can't add more than that. It really is a matter for the consortium, though.

Okay. And then maybe just, secondly, on Octopus, It's an incredible result. I think you made the comment your interest would be lower going forward. Is that a signal that they're likely to raise equity and you might not participate? Or how are you thinking about that equity call from Octopus going forward?

No, sorry. Our interest is 20%. And if I've left an impression that I was talking our interest going forward would be lower, it's actually the earnings contribution in 24%. If it was in the guidance section, I was saying our expectation at the moment, within a wide range of outcomes, I should say, because it's leveraged to the retail market based on competition, is that it would have a lower contribution to origin. Nothing to do with our equity holding. Our equity holding, you should work on the basis it's always been 20% and would continue to be 20%. So I apologise if I've not been clear to people when I raised that earlier.

How should we think about the value of that asset? You've done an amazing job. It's really shot the lights out. Profits are enormous. Do we put it on a utilities multiple to think about the value for that?

Well, I'll tell you the way we think about it, and then maybe that will be helpful. And we haven't done an amazing job. I think the Octopus team have done an amazing job, but I'm sure there's people around the table who love to take credit for the amazing job we all do here. But if anything, it's been a good relationship and we have been supportive from early days. So I do feel that the relationship is strong. So firstly, it's a retailer. It's not a vertically integrated retailer, Dale. So it purchases energy in the market. But as you probably appreciate, the UK is a much deeper wholesale market. So you've got to think of them as a retailer that does use good analytics to actually predict load and everything, but it is actually making the retail margin. And that's the way to think about it. But at 9.7 million accounts, the dynamics in that market do go to the unit margins. They do have a cost to serve advantage relative to the regulated cap, and that's their key advantage. but the brand is also meaning that they're requiring customers at a low cost relative to what you would see in a normal dynamic, and that's where the brand does play out. So think about a non-integrated, large-scale retailer, and I think if you went and looked at the work that's been done by competitors and the Ofgem about margins allowance and competitive dynamics, you could come up with a range of views around that, and that's one of the reasons why there still can be a lot playing out in the market. It does look a bit more... stabilize that market today. But, you know, it goes through another winter and another summer just like us. The second business is a platform that's Kraken. And the Kraken platform, they license. So to be very clear, the 9.7 million accounts, they're also included in the 32. So the energy business pays a licensing fee to them. And then there are a number of other customers globally, including us, that are paying a license fee. The licence fee has been a little lumpy because some of the early deals like ours weren't all on just a cost per customer account. Some of them had milestone payments and that's why there's a little bit of lumpiness. And there's also a lag from when you sign them on to when they get implemented on. But they've got a number of implementations going on globally. But I would think about a monolithic platform that has high gross margin that's being implemented. And one of the advantages of now having it live on 10 countries is that they know they've got them now operational, including Australia. Because as you know, there's always localization of regulatory arrangements. And so that's a think about a licensing business per customer account at reasonably high or very high gross margins and with a CapEx profile. I think it's earlier days on the services businesses and I'll probably focus on the first two, but the service business are growing. We probably haven't given you enough information and it's probably less mature, but they're the two ways I'd look at those businesses. They're increasingly, you know, serving much more than themselves. That's why you should think of them as two businesses today. Okay. Thanks, Frank. That's helpful. Yep. Thanks, Dale.

Thank you. Your next question comes from Ian Miles from Macquarie. Please go ahead.

Hi, guys. Just further on the Octopus side, are you actually paying an annual licence fee to Octopus Energy for the use of your customers, or are you just like E.ON paid a one-off payment to get access to the platform?

I'll just get John Briskin to describe our arrangement with them so that you have an understanding, OK?

Yeah, g'day, Ian. So all customers will pay an ongoing licence fee. The one-off or the implementation fees are sort of different arrangements that were included, especially in the early ones like us and Aon. In terms of our own fees, we have just completed migration, so we're yet to actually pay those licence fees, but we will start to pay them in due course.

So it's a mixture of the two, Ian, with the second yet to commence. And because there'll be some milestone payments, you'd expect the commercial arrangement we have is therefore... a lower ongoing rate on a per customer account basis. I think as time's gone on, they're into more per customer account basis. And you would probably appreciate the logic about that. When they were a small business, that was how they were managing cost implementation growth. And now they're getting into a much more recurring revenue model. Is that right, John?

Yeah, that's right. And maybe just picking up that point you made earlier in the presentation, they do have a lot of contracted customers. Now they're going through, I think it's something like six or seven migrations right now. So those customers won't be paying licence fees, but over time that revenue licensing line that you see will continue to increase.

Yeah. Okay. And then in terms of the profitability aspect, In the UK, like I went and quickly looked it off, Gemma, and you're not actually offering any discount relative to the market. How much of the EBITDA improvement is actually the volume element of the business being surprisingly favourable to you as opposed to just making that spread by providing the services? It was a remarkably warmer winter in the UK. Did that have a positive impact on the results? Yeah.

No, the result was really is driven by that sort of spread between EBIT and Headroom. You'll see in the off-gem tariff plus their cost to serve advantage. Their existing customer base has are on a slight discount to that price cap. Right now, acquiring new customers is it's a dynamic of the market in the UK right now where they are being acquired at the price cap. So, yeah, so it wasn't a huge factor, both the volume and the lower wholesale costs over that summer period.

But volume as it relates to – I wasn't sure if you were referring to volumes consumed, but volume customer account numbers has been a big driver.

Customer account numbers have definitely been a big driver. Big driver, yeah.

And from a funding point of view, does Octopus – Your accounts don't provide a lot of detail, but does Octopus have a large cash balance still in its books that it can actually go and fund all these other programs it's trying to do at the moment? So it's actually an internally funded business now?

So it does have a strong positive cash balance, and it is self-funding its growth at the moment. Clearly, it's been on a trajectory of rapid growth. And so the options available to it, you know, we'll continue to discuss across the board there and make decisions as we go forward. But you should take that, you know, right now it is a self-funding business. Yeah.

The other thing to note about the UK, Ian, is that the bills are the same throughout the year, but the consumption profile is different. So the working capital draw on the UK businesses is high through the winter period. And so, therefore, you need to have the strength of balance sheet. In fact, that was one of the key features always about it growing was that it kept downside scenario capital, you know, call it, available to make sure that if there were any downside scenarios in a winter that they could withstand. And so they are sitting with a strong balance sheet today.

Okay. And on the energy markets business, you talk about electricity sort of reaching maybe a peak earnings. Is the gas side of the business likely to suffer the same situation or are you comfortable that you can maintain that sort of $3 spread over time?

Yeah.

Greg, do you want to?

Sure. And yes, look, we had a very good year this year, but margins will probably come down to that range of $3 to $4. So that's what we expect. We did place in some very cheap hedging some years ago, and that's why this year the margin was higher. But we do expect to go back to trend of that $3 to $4 GJ range.

And the combination of that, Ian, is really that we've obviously had legacy long-term purchase contracts that contribute some of that. And then the balance is really contributed through the portfolio that Greg's described of both supply contracts that have been entered into some time ago combined with transportation, and it's the mix of those as well as the ability to, as you know, have both customer, power station, transport – enabling us to actually manage very dynamically the supply-demand balance throughout year and year on year. That enables us to capture the balance of that margin. And that does come with some, as you know, that comes with us having to also manage quite a bit of risk in that gas market. But we do believe we can sustain the unit margins that we're sort of guiding to in FY24. Okay.

And then finally, I just saw a raring account. I'm sorry to labour the point. Can you maybe give us some colour on how far through you are to try and hedge the, you're going effectively from being very long in New South Wales to quite short, that you've got cover in that baseload? Because it's not like we've got huge amounts of additional volume coming in. Everything seems to be getting delayed. How do you actually hedge that without shedding large amounts of volume?

I'm not prepared to share more of that on the call today, Ian. I understand the question, but it's also a, as you know, it's a market that's pretty dynamic and we're a key player in that market. Sure. I'm sorry, but that's insensitive. Yeah, so sorry about that. Yep. Thanks very much, Ian.

Thank you. Your next question comes from Rob Coe from Morgan Stanley. Please go ahead.

Good morning. Congratulations on the result. May I ask a question about the octopus? I guess you've clarified there the earnings steer for this financial year. Is it fair to say that the FY23 result included recoveries of the extraordinary period so that the number that we'll see in FY24 is a little bit more like the starting point from an underlying position from growth?

I think you're right. Well, the markets will always be dynamic, Rob, but you saw they were quite extraordinary. And there was an element, because it moved from 22% to 23%, There was even a catch-up in 23. Then there was the events of 23 in the first half that masked that. Then there was the move to a quarterly tariff. So there's an element of all of that in those numbers as well. But you're right, if you went to where markets are today and therefore where bills are and wholesale costs are and everything like that, that's a reasonable statement to make. The one thing that we can never perfectly predict, Rob, is the retail dynamic that John talked about earlier, because you've gone through a time where the prices have been capped. Everyone's had to operate within that. There's been some regulatory shift there. And that's the only thing that I could never perfectly predict. And that's why we do say there are a wide range of outcomes. And now with such a large customer account basis, they're just more leveraged to that. And so... But I think your opening statement is a fair one.

Great. Thank you. And then maybe just to clarify, thank you for the partial financial statements for the octopus. That also is very helpful. Just can I confirm, how is the company accounting for cost to acquire? Do they just OPEX that or is there an element of capitalisation?

Rob, it's John here. They do account for that under capital. So there is a capital allocation there, yeah.

Okay. All right. Thank you, Mr. Briskin. May I ask a question to, I guess, Mr. Tremayne, because I'm sure you'd be on top of this, but having a look at the annual report and the cash from operations for energy markets had the very big swings in working capital there, so that's got to be something that you're right on top of. Can I just maybe get your perspective on how you'd expect that report cash conversion to play out over the next little while.

Yeah, thanks, Rob. Yeah, I did cover it in one of my slides. Essentially, very, very high pool prices and commodity prices, but particularly in June 2022, meant that 22 cash conversion was very, very high. and that unwound in 23. Like, that's pretty much the whole story. And so what you get in 24 is more like what you would normally expect. And again, when you make a forward-looking statement, there's always a whole bunch of assumptions around that, and clearly the assumption is, you know, a more stable price environment. The biggest, for just a little more granular detail, the biggest impact is actually because of our short to the pool position. And so you end up with, in a period of high pool prices, you end up with a very high impact. AEMO payable balance. And so that's what happened at the end of 22. And of course, in 23, you've got to pay the bill. And so that's why you get that outflow in 23. But of course, then pull prices move lower through the year. And so that all righted itself by the end of 23.

Okay, thank you. That's super helpful. And just a final question here. There's a lot of commentary on your developments in renewables and Origin Loop, the VPP, which all looks exciting. Can you comment, is there any opportunity to collaborate with TNSPs on these things?

I'll get Tony to talk. Yes, there is. But I'll get Tony to give a little bit of colour to that.

Hi, Rob. Tony here. Yeah, so obviously with the VPP, we're putting assets into distribution networks. So from their perspective, it's quite important that they understand the implications of that. So we work with all of the distribution networks in terms of getting what we'd call an operating envelope of how those assets can operate, and we incorporate that into the algorithm within the virtual power plant. The second probably area of collaboration has really been around community batteries where we're actually dealing correctly with some of those distribution networks to install batteries in their substations and pole mount where we can then provide a service to customers and also capture value from lowering their cost of energy and sharing that with those customers as well.

Okay, cool. It might have come across a little funny. I actually said TNSP, Transmission Network Service Providers, but thanks, Mr Lucas, for the DNSP part. That's helpful too. That's what I thought you said, Rob.

Is there anything? Yeah, that's probably the key opportunity with the VPP is with the distribution companies right now. Okay, many thanks. Thanks, Rob.

Thank you. Your next question comes from Gordon Ramsey from RBC. Please go ahead.

Well, thank you. I'm just interested in the outlook for the cost to serve. You're still targeting $200 million to $250 million. You've worked it out to FY25. You are not netting that expense out of that guidance. Is that right? Yes.

Yeah, it's our intent to deliver those cost savings, which would be inclusive of our doubtful debt expense. Clearly, we've got a period with higher energy bills that have in part caused us to have a higher provision, but there's also both cost of living challenges. We have got a large focus on improvement across our collection processes. We've got a lot of sophistication in functionality built into our systems, and we're working through policies and procedures to get that back in line. Recognising, again, 24 is going to have higher bills again. More broadly, though, we are targeting labor costs. We're targeting call deflection, automation. We've got efficiency across our processes. And the operating model that we work under with Kraken certainly allows better first call resolution and resolution of customer inquiries quicker as well.

Okay, but just to confirm, that excludes that indulge with that guidance.

Is the $200,000 to $250,000 going to include bound novel debts or will you normally be targeting it to include?

To include. To include is our target.

Okay. This one's for you, Frank. The lattice contract negotiations the last time I think extended out to something like 11 months. Where is that sitting at the moment?

Really, well, those discussions are commercial incompetence under the nature of the contract, but they are ongoing. And it's probably not appropriate for me to say more than that based on our obligations under those contracts. If it was to go to full arbitration, though, you could be many months away without a result. But the discussions are ongoing, Gordon, and that's probably the best guide I can give you right now.

Yeah. And again, just to clarify, it's not in full arbitration right now. Is it in some form of arbitration or is it just... company to company discussion?

It's in arbitration at the moment. But in that arbitration process, there is periods where you negotiate. And those negotiations are going on. you know, strong. I mean, it's cordial, is what I would say.

Yeah, there's a timetable process that gets triggered, but there are then negotiations even within that timetable process, and they're ongoing, they're constructive, but not finalised. And that's, so that's the way, so it's a bit more nuanced than saying you're just in arbitration, because I think there's a fair bit of discussion between the organisations as well.

Got it. And last one from me, just on the timing of the takeover proposal. You previously said it would settle in early 2024. There's been a one-month extension for the ACCC. There's no change to that timeframe?

Still focusing on that timeframe, Gordon. Okay. Thank you. Thanks.

Thank you. Your next question comes from Mac Vickerson from Morgans. Please go ahead.

Good morning, Tim. Can I just follow on maybe from Gordon's question on the latest contract? Obviously, we've noticed that the nominations are significantly down at the plant. You can see that in Beaches Outlook and in the AMO data. Can I just ask, how are you covering that position in Victoria at the moment if you're relying less on that contract? Is demand down? I know we've had a milder winter, but is it demand-driven? Have you got adequate... other backup arrangements in place or are you using the spot market to cover? Could you just give us a bit more colour on that, if you could? Yeah.

Max, it's Greg here. Look, we have a number of contracts in place, but the first point is that gas demand has been, you know, a lot lower than certainly last winter. You know, and that's predominantly driven by certainly weather, but actually more importantly, coal-fired fleet in the market has operated very, very well this winter, which has really taken off the demand for gas intergeneration, into gas generation. So that's the first thing. So demand's well down. So what we do in our portfolio is, you know, we have contractual obligations with all those contracts. So we have flex on those contracts and then we just... nominate accordingly. So we are covering our whole position with all the contracts that we have in our portfolio. And just the other point too is, you know, even gas storages are probably at the highest levels we've seen for many winters. So Iona, which is in Victoria, is probably at the highest gas storage levels I've seen in this market for some time. So that just tells you how much surplus gas is available at this point in time.

Excellent. Thanks, Greg. And this might be another question for you then, just on ARARing and how that sits with the expectation of declining tariffs in FY25. As we get closer and it becomes more and more clear that the base case plan of closing in August 25 is going to be what happens in reality, do you expect that that position might change, the futures market might react, or is that more an FY26 story?

Yeah, look, you know, the market is already looking at a number of factors in the market, quite frankly. It looks at certainly the prospects that are already coming out, but it also looks at all the other renewables and other gas-fired power stations coming in as well. So it is being factored into the market, and I expect that will change over time as well.

The timing of the notice for Araring is for August 25, Max. So it's in the FY26 financial year, but it is August 25 just to have that focus.

And Max, probably at that point, there's not a lot of liquidity out there at this point in time either.

Excellent. If I could just ask one more just on the VPP. Look, that is some really impressive volume growth. Are you able to give us any indication of, where your program sits relative to the other tier one retailers, either listed or unlisted?

Yeah, Tony here. So we're concentrating quite a lot on both segments, so on residential and the Oregon Zero segment. So we probably have, you know, a couple of hundred megawatts in sort of the origin zero segment and the balance coming from residential. I would say that that's probably a little bit stronger than others perhaps in the residential space.

Excellent. Thanks very much. Very understated.

Thank you. Your next question comes from Mark Boostertill from JP Morgan. Please go ahead.

Hi, everyone. Just a few things from me, if I could. Just in terms of the fiscal 25 comments that you made, can you give us an indication of how much of your forward electricity you've already sold into fiscal 25, if at all?

Yeah, Mark, we haven't... CNI, you know, they're not... Typically, they don't trade or contract into that period at this point. So not a whole lot. It remains relatively open. Again, not much liquidity out there at this point in time, so from a CNI point of view. So, yeah.

James, did you want to add anything more to the CNI market?

The C&I portfolio that we have, you know, on average you'd expect customers to be contracting between two and three years. It's slightly shorter now. So, you know, the next 12 months you'd expect between a third and a half to renew. So it kind of supports what Greg's saying there.

Okay. Got it. And then just switching to Octopus, just in terms of the guidance you provided in 24. So you did 240 million in EBITDA in 2023, and you're saying it's going to be, lower in 24 but my understanding was that business made nothing if not negative in the first half so all of that contribution came in the second half so for all of the factors you've talked about are you saying it's going to be more than a 50 drop uh on a half on half basis into 24. yeah i'm happy john yeah um

Mark, no, really, I think you need to think about FY23 as a full-year contribution. It was a catch-up. Of course, you saw the high wholesale prices that we talked about. When you think about FY24, We have guided that there is a wide range of outcomes possible. Really the biggest factor here is the return of a more competitive market in the UK. So I think you can sort of look at the Ofgem price cap and you'll see the sort of headroom allowance and the EBIT allowance and there is a cost to serve advantage. But that would assume more customers sit at that rate. Now, in a competitive market, that is going to change and more customers will move to discounts. And so really your call is how competitive is that market going to be?

Okay. And while I have you, John, just one last thing in terms of the broadband accounts that you've managed to achieve so far. So 96,000 is pretty good growth from the prior year. but still well short of your $600,000. So was that in line with expectations, or do you think there's some downside risk to that $600,000 you've put out there?

Yeah, I mean, we're certainly happy with a few things. We're happy with the service that we're providing to customers, and we won some awards around that. And we're really happy that we've started getting our external third-party channels We've also gone through this period of migration where our focus has been making sure our customer service reps or energy specialists that we call them are very focused on learning the new system and supporting customers through that. So we haven't really pressed, what I'm trying to say is we haven't really pressed all of our channels the way which we think we can. So we certainly sort of see over the next couple of years that much larger ramp up. You know, looking today, I think we're just over 100,000 today and I've got 600,000 target there. So it is ambitious, no doubt, but we are, you know, very, very focused to achieve that.

Excellent. Thank you. That's all I've got. Thanks, Mark.

Thank you. We have a follow-up question from Rob Coe from Morgan Stanley. Please go ahead.

Thank you. I was just wondering, I probably should know this from reading the scheme implementation deed, but you are allowed to make some asset divestments, and I'm just wondering if it is theoretically possible to monetize the origin investment, sorry, the octopus investment, and in some way maybe realize some profit there.

Look, you're right, the scheme does have... It enables us to invest. I think any large-scale divestment of that, and I'd have to go back and check this one particularly, but if you're doing something of a scale of that size, I'm sure, because it's a significant business change, we would need to, at the very minimum, consult and likely consent from the consortium. I'm pretty sure that's going to be the answer on that particular scenario. I know we've got quite, you know, if we acquire anything greater than $50 million into an acquisition, we would need consent. So I'd be pretty confident at the disposal. So I think you should take that as the answer that we would need consent. If there's any change to that, I'll let you know. But that's what I believe it to be. That's correct. Yeah. That's right. I've just been told. Okay, great. Thank you so much. Thanks very much. All right. Thank you very much for your attention. We appreciate it. And we look forward to catching up with investors over the next week or so. Have a good day. Thanks very much, everyone.