Origin Energy Limited (ORG) Earnings Call Transcript & Summary

Good morning, everyone, and welcome to the 2025 half year results for Origin Energy. I'm Frank Calabria, the CEO of Origin. And I am joined by Tony Lucas, today, our CFO; and the rest of the executive leadership team. You'll hear from Tony and I this morning as we work through the introduction financial results and the operational commentary and guidance and then what we'll do is we'll open up for questions as we normally do and have an opportunity to ask any question to any member of the team. So the outline set out on Page 2 and now really looking at Page 4, the summary of our results. Energy Markets is lower, but in line with guidance expectations that we said at the beginning of the year, financial year, that is APLNG's earnings are up 14%, driven by higher realized prices and increased sales volumes. The LNG trading business will -- has delivered $285 million in EBITDA that's obviously up significantly and is heading towards the top end of the range of the guidance. And Octopus continues to grow globally across both energy and technology. And from an earnings perspective, the growth has been in the U.K. retail business, that's been more than offset by investment scaling their Energy Services business. Think about the Origin business and the way we're setting ourselves up for the energy transition and the way we lead through that really through our asset portfolio and capabilities that we believe are differentiated and continuing to build both so that we can succeed in what is quite a dynamic market. When it comes to retail, we have a leading retail position and tech platforms. They are driving a focus on continuous improvement in customer experience and cost, and we're well on track for our guidance to the cost to serve reduction of $100 million to $150 million in 2026 financial year from 2024. With an advantaged flexible wholesale portfolio, you can see that extends right across our gas peaking VPP of 1.5 gigawatts and we have 1.7 gigawatts of batteries underway, which we'll talk about further. And obviously, that's in addition to our Eraring plant. APLNG continues to generate strong cash flow and following on from the commentary you would have seen in our quarterly is very much focused on continuing to do what it does well, which is optimizing production from existing wells and we'll expand further how we think about that. And clearly, we have a global growth opportunity through Octopus through both energy and technology. They are now the largest U.K. energy retailer and also closing in with Kraken having 100 million accounts on its platform ahead of its target date of 2027. The balance sheet remains strong. The cash flows are generating from across these businesses and that's enabled us to increase the dividend for the interim at the same time as investing in the energy transition, and Tony will take you through the financial profile of the organization, how to think about that. The financial highlights. You can see both statutory profit and underlying profit are both up. Underlying profit of $924 million is up $177 million from the equivalent half last year. Our underlying EBITDA of $1.926 million -- billion is down from $1.995 billion in the equivalent half. Our underlying EBITDA to adjusted net debt is at 1.5x. That's still well below our target of 2x to 3x but is up since June. The rolling 24 months return on capital employed is 16.4%. And you can see the interim dividend of $0.30 per share, fully franked, is up $0.025 per share. When we think about the net transition, it's a multi-decade challenge to achieve net 0. I'm on Slide 6 and what you can see is that new capacity in renewables, storage and consumer energy resources will increase by greater than 2.5x. And I should point out that this is under the IMO step change scenario. As the national electricity market transitions to renewables, the value of dispatchable capacity increases. As coal retires, it's primarily replaced by shorter duration storage. Now this storage is very important to manage over supply with the increase in energy coming from must-run renewables. It is the longer duration energy that become scarcer. And that's shown by the decline in those blue and gray bars on the chart there. And this is the energy source that will be critical to manage a wide range of scenarios. Those scenarios it could be either cold snaps, heat waves and renewable supply and storage shortages. So that really is the dynamic of how the energy supply market will change, particularly as you can see, there will be a lot of growing demand over the next couple of decades. And as we go through this transition, it's imperative that the policy is focused on energy security. And the reason for that is that market design, particularly on the left in relation to the national electricity market, will need to change to be fit for purpose in a world of a high penetration of variable renewable energy. And in our view, that very strongly requires a capacity mechanism design that does include gas which will be critical to support reliability and climate goals. And we should have energy security in mind, particularly as we go forward, and that's going to be critical to achieve that. We'll need to also make sure that as this changes that the contract market liquidity, particularly as coal retires and that we efficiently introduce our growing consumer energy resources, including through VPPs, with the right level of transparency and flexibility. There's been much commentary on gas and its role in the energy transition, and there is an urgent need to address gas supply challenges. There is a significant risk of shortfalls in the coming years, the declining production in the southern states, capacity constraints on pipelines at peak times between the north and south -- so storage, regasification pipelines and new supply are all needed and that's clearly a priority for policymakers in the industry right now. When we think about the Origin business and how we set ourselves up for today and in the future, it really is to lead the energy transition through differentiated assets and capabilities and over the coming slides, we'll talk about how we are set up and continue to invest and position ourselves across energy, supply, customer energy resources and Octopus. And when you step back from that, that shows both an integrated position all the way through in the domestic market and also a global growth opportunity beyond. When we turn to customer of the first of those, we have a leading customer position of 4.7 million customer accounts across homes and small business, a strong and trusted brand, world-class tech and analytics platforms in place. We have owned sales channels and strong partnerships that are going to an ability to compete in the market at a lower cost to acquire and capture more of the share in the right segments. And we continuously employ these and bring them together to improve, achieving lower cost, improved customer experience and also creating value. At the same time, we are growing our community energy services and broadband businesses as well. And in Origin Zero, we have over 25,000 sites, and we're combining energy supply with a range of efficiency, electrification and distributed energy services, where we are orchestrating distributed supply and demand via the VPP. That's a core component that's being introduced and deployed across this market segment, and growth in that business is occurring through e-mobility, embedded networks and community batteries. We continue to recognize the cost of living pressures that are being felt by many households, and we are supporting the most vulnerable customers through a range of initiatives, and we also continue to contribute to communities, including through our foundation, but also First Nation spend, community funds in communities such as Eraring and also volunteering by many of our employees. Turning to Energy Supply. I talked about an advantaged portfolio, particularly as a market that accelerates towards renewables and storage. And you can see on the left-hand side what we have today across a range of different supply sources and also -- so you can see that in terms of gas-fired generation pump hydro, the VPP and also Eraring, which continues to play a vital role over the coming years and combining that with a competitive fuel supply. And a good development pipeline as we target 4 to 5 gigawatts of renewables and storage by 2030. We have made very good progress this year with 1.7 gigawatts of batteries underway, in the 2- to 4-hour range. We'll talk through those. The 1.5 gigawatt Yanco Delta Wind Farm development project and a broader development portfolio of up to 3 gigawatts of wind and solar and storage developments. APLNG on the next Slide 11 is a world-class coal seam gas resource and LNG infrastructure. It's backed by strong operating capability. and it's making a valuable contribution to the domestic market. APLNG has over 15,000 peta jewels of resources and reserves with greater than 50% of those available beyond the current export contracts. It's underpinned by low cost of supply, long-term contracts. And as I said earlier, with a focus on the ramp-up of optimization activities, which we've been undertaking over many years, and that's our near-term focus today. And APLNG continues to play a very material and supportive role for customers on the Australia's East Coast with 25% of sales delivered to the domestic market. Turning to Octopus. It has significant global growth opportunities and leading energy technology. U.K. retail and Kraken continue to exceed expectations. They're rapidly growing, and they're now investing in growth of the non-U.K. retail and energy services business. You can see there, they're the largest energy retailer in the U.K. with 13.3 million accounts, they're up 10% since December '23. And they now have 1.8 million accounts in non-U.K. retail markets are doubling in the last 12 months. And the organic growth between 2 of those both U.K. and non-U.K. is about 200,000 customers -- 200,000 monthly organic customer account growth. In Kraken, they have 62 million customer accounts on the platform at December 24. That was up 22%. They are closing in, as I said, on the 100 million customer account target, and that would translate to greater than GBP 500 million of annual recurring revenue or ARR. Since December, they've now signed their first broadband customer adding a further $2.3 million accounts to that $62 million. Octopus is now spending a lot of its time investing into a broader energy ecosystem. And by that, we mean in low-carbon tech. They've got -- made significant advances in the EV business and the translation of that to flexibility revenue, but now really turning their attention to scaling up, really a heat pump business that's attacking the gas boiler market in the U.K., and we'll talk through that investment and also that opportunity. But that's where they are now focusing as a next limb of growth for the organization. So on that note, I'll come back to talk about operational review and bring that together, but I'll hand over to Tony, who will talk you through the financial review.

Thanks, Frank, and good morning, everyone. It's pleasing to be presenting such a solid first half of the year '25. I'll start with Slide 14, which is the profit bridge. As flagged in our guidance in August last year, the Energy Markets business was down on prior period with the wholesale component of the fin year '25 tariff stepping down and higher coal procurement cost this period with the ending of the coal price cap. Turning to Integrated Gas. We've seen higher profit in our share of APLNG driven by higher LNG volumes and higher prices, and a higher contribution as we flagged from our LNG trading, which is also in line with where we guided. Our share of Octopus earnings was down slightly in the half, a strong earnings from the U.K. retail and Kraken licensing business was offset by an increased investment in the manufacturing and installation capability in the Energy Services segment. As we foreshadowed APLNG now moves or has moved into tax paying, and this results in a lower tax expense at the Origin level, with those dividends now in that first half, we we're 100% franked. Turning to Slide 15. Operating cash flow saw a slight improvement compared to the prior period, how these 2 items I'd like to call out. The change in working capital was impacted by the unwind of the Queensland bill relief which was received, as you remember, June 2024, we've seen about $400 million of that unwind in the first half. And if I just Energy Markets operating cash flow for that, we have cash conversion at sort of around 100% for energy markets in the first half, so reasonably strong. Cash tax paid, as we flagged in the quarter is higher this period due to a true-up from the year '24 tax year. This really occurred due to higher energy markets earnings unfranked dividends from APLNG having a lagged effect on installments, where we forecast tax cash for fin year '26 to be materially lower. CAPEX is higher in the period, reflecting investment in the large-scale battery storage projects that Frank highlighted earlier. Slide 16. The first half, Origin received $612 million in fully franked dividends from APLNG as APLNG moved to tax paying in the second half of last financial year. Net of hedging, that amount was $562 million at 100% APLNG level, the joint venture experienced strong operating cash flow for the first half of $3.2 billion after $400 million of tax payments. APLNG also repaid USD 301 million of project finance during the period and held cash of $1.9 billion as at 31 December, and that's up slightly on the 30 June, 2024 level. Turning to net debt on Slide 17. That increased to $4 billion. That reflected higher cash tax paid this period, an increase in CapEx from those large-scale battery investment program. We've highlighted battery CapEx for all projects are tracking in line with the Fed cases. I'll just go to Slide 18, which is the dividend. The Board has increased the dividend to a fully franked interim dividend of $0.30 per share. This is up from $0.25 per share. This reflects a strong balance sheet, strong cash generation from 2 diversified businesses and a robust outlook. The dividend is fully franked and we expect dividends to be fully franked for the foreseeable future. If I just go to Slide 19, capital structure. Adjusted net debt to EBITDA has increased to 1.5x, up from 1x at the end of the June financial year last year '24. This reflects an increase in the net debt, which I discussed earlier. We expect net debt to continue to increase through '25 and peak in midyear as we deliver that battery investment project program, it probably will be probably, I'd say, around the middle of the range depending on, obviously, market conditions. Batteries are expected to start to contribute earnings in the second half of fin year '26 and subject to market conditions and further growth, we'd expect net debt to start to track down from that forecast peak. If I just go to capital allocation we have a rigorous investment evaluation process and we apply a disciplined approach to investment decisions. Our approach to capital allocation ensures there is strong competition between investing for growth and returns to shareholders. Consistent with this approach I outlined at our June 2024 investor briefing the decision on balance sheet funding versus utilizing third-party capital and we make this through either contracting tolling or offtake agreements. And it's really based on whether we can gain the same level of operational control or value, where we can replicate the operational control or benefit through contracting. We'll seek to utilize third-party capital and underpin that asset with a contracting arrangement. Evidence of that is in our 1.7 gigawatt large-scale battery commitment, 740 megawatts of this is off balance sheet, being super node 1 and 2 and the Summerfield project. For renewable assets such as Yanco Delta, we may acquire a development opportunity on balance sheet, but we'll move to utilize third-party capital prior to the construction phase. We would seek to underpin that asset with an offtake agreement and were shortlisted key contractors and commenced early-stage financing discussions on the Yanco Delta project consistent with this strategy. Turning to Slide 21. Energy Markets EBITDA decreased $306 million to $738 million for the first half. As previously indicated, the flow-through of lower wholesale allowance and a retail tariff and the higher procurement costs this period for coal as that market coal finished -- resulted in a reduction in electricity EBITDA of $196 million this period. Gas contribution also reduced. This is due to lower market prices flowing through to business customers and wholesale trading volumes reducing. We saw a partial offset through an increase in retail prices, which was recovering prior period cost increases. Cost to serve increased relative to prior period. However, this includes the commencement of the Kraken licensing fees and the prior period having the Kraken stabilization project costs sitting outside of underlying. Pleasingly, through the period, we're seeing bad and doubtful debts reduced by $36 million this period. We're well underway and confident of delivering the $100 million to $150 million cost out target for fin year '26 and we'd expect the full year '25 result to show an improvement in cost to serve on fin year '24. Turning to Integrated Gas. EBITDA it's up $250 million in prior period with $94 million coming from Origin's share of APLNG and that's on the back of those higher LNG volumes and prices I talked about. A further $156 million increase coming through integrated gas other, and that's primarily from the LNG trading gains of $285 million for the first half that's partially offset by a $50 million loss on oil and FX hedging. Turning to the contribution from Octopus Origin share of Octopus underlying EBITDA was a loss of GBP 24 million. U.K. retail business performed strongly, delivering positive EBITDA of $25 million for our share relative to the small loss we experienced in the prior period. As on the back of organic growth, full period of the Shell acquisition and lower Rego prices. Last financial year, you'll remember the seasonality of earnings in that U.K. retail business sees most of that contribution coming in the second half, and we'd expect the same in this financial year. Kraken Technology delivered EBITDA of $22 million. Our share live accounts, as Frank indicated, on that platform was $40 million with contracted sitting around $62 million and that's delivering at the moment on ARR in excess of GBP 300 million. Octopus increased its investment in Energy Services by $45 million, which was our share this period as a scale this business the Energy Service business, as Frank syndicated, encompasses EV, solar, batteries and heat pumps. Octopus has invested in proprietary IP and technology and manufacturing and install capability really to capture the value of the significant opportunity and electrification of the U.K. gas boiler to heat pump transition. The increased investment in the energy Service business results in a lower forecast for Octopus for the full year and you'll see we have adjusted guidance for Octopus supportingly. We still expect a strong contribution from both U.K. retail and Kraken Technology to deliver an overall positive contribution and Frank will touch on that in the guidance section. So with that, I'll hand back to Frank.

Thanks very much, Tony. Now we'll turn to the operational review and move through to energy markets. And you can see on Slide 26, just -- the way that we have grown the retail business substantially since 2020 and to position ourselves in this market. It's obviously overall translated to over 500,000 customer account growth, since 2020. But along that journey, you can see there, in addition to competing hard every day, we've grown the CES business both organically and inorganically to be the #1 residential Embedded Networks business. We've established Origin Zero. We've built and grown our own VPP, which now is 1.5 gigawatts. We made the Octopus investment, and we've completed our customer migration under Kraken. We've strengthened the channels by owning those through acquisition of aggregators and most recently, the solar quotes business, and we've grown our broadband business and have entered into a new agreement with Superloop. And that's all translating to value over that period, and we continue to focus on that in a market that I believe will continue to have value that moves towards the customer over time. We have a relentless focus on continuous improvement. You can see there on Slide 27 and improving customer experience, whether that's through the Trustpilot score customer happiness on average, is 67% for the half year. I can tell you over the last several -- over the last 2 months, I think that's been sitting around 73%. So we've got some momentum there. And we really are seeing the benefits of Kraken flowing through every day, not just in terms of cost, but also in terms of just servicing our customers, and we expect to see those benefits continue to flow forward. It's very much linked. A lot of people will talk about AI. I think the deployment we can see and our focus on use cases is very much in the customer service space. We've highlighted there what's now being managed through our Magic Inc, in terms of e-mail responses. And you can see what that's done in terms of response times, call transcription, but also just what it does to quality, and we're deploying it very much in terms of that high interaction. We also now have an AI voice agent that we're trialing, and we'll continue to develop that. It is certainly simplifying our user experience and enabling significant reduction in training time. So we can see some momentum and benefits to flow from that as we continue to deploy it. And then in terms of product development, you can see on the right-hand side, products that can orchestrate distributed customer assets like our EV power up, fastest speed to market. We'd expect to see that happening in terms of campaigns, app updates, innovation, the deployment of credit decision engines, which is also Tony said to you that, that's quite a key role in the improvement we've achieved over the last 6 months in bad doubtful debts and also payment channels, and we continue to focus on personalization when it comes to both products and pricing. On Slide 28, you can see the growing customer account base, 57,000 customer accounts across electricity, gas, LPG, broadband, home assist and that has continued into February. We're up another 20,000 over the last month or 2, translating to an improvement in customer lifetime value, and we're pleased in terms of where we're winning and retaining across the segments in the market. And we continue to have a meaningful churn below market on the right-hand side and certainly, multi-product bundling and customer service and experience to contribute to that, and we would expect to continue to perform better over time. Cost reduction on Slide 29, I mentioned earlier in terms of the target we've set ourselves, you can see that's driven by a variety of initiatives on the right-hand side, some of which I've already covered. It goes to the operating model that flows, and it really is continuously improving. License fees have come in. But overall, it's a much lower IT cost of running this platform. And we would continue to expect to see that momentum in the second half and also into the '26. I mentioned earlier, the businesses we were growing Community Energy Services, you can see the customer account growth and gross profit and that continues to happen, particularly as we go into high-density housing, medium density housing, which where we have a strong position and broadband, you can see the growth in customers, but at the same time, we moved on to the Superloop platform over the last 6 months. That's meant we've been able to integrate our customer experience to be much more seamless and obviously benefited from a strategic stake in Superloop. I've touched on those partnerships on the right-hand side, which are really all about improving our proposition to customers, our access to market and the quality of everything we do every day. Turning to Origin Zero. It's growing a broad suite of services to corporate customers. And you can see some of those strategic accounts on the left-hand side, the percentage of customers that are large customers that are on a broader suite of services, whether that's digital insight, subscription, solar, storage, VPP, embedded networks. And you can see that, that's now grown to over 20%. We're also very much focused on industrial electrification through Climatech Zero, in which we own 20% as well. We've continued to grow electric vehicles under management. You can see that's now greater than 1,100. We have over 150 business customers through leasing and subscription products. And we clearly are growing the number of corporate customers in which we now make that offering, and that continues to grow very well. Just turning to Energy Supply now. You can see here the battery portfolio. First thing is that the construction activity is progressing in line with our expectations, both on time and cost. And so the first thing to probably point out is that the Eraring Stage 1, which includes the expansion and Supernode Stage 1, we would expect to be making a contribution in the second half of the '26 financial year. You can also see that, obviously, that's now sort of 1.7 gigawatts by dividing the storage megawatt hours to the capacity you can tell which are 4 and 2 hours, clearly, stage 1s, 4 hours Stage 2 of our rigs also 4 hours, Mortlake 2, super node Stage 1, 2, and then you can see the last 2 SuperNode, Stage 2 and Summerfield are all 4 hours. You can see a trend towards 4 hours. And if you take that CapEx on the right-hand side and divided it by the megawatt hours, you can sort of see the average cost per kilowatt hour there. And you will see that as we've made those investments from the very first Eraring Stage 1, which is sitting at around $600 a kilowatt hour. You'll see that the Eraring Stage 2 and others are actually now moving down into the $400 kilowatt hour. That obviously does vary if you're in a 2 or 4 hour. But very pleased with how that's going and look forward to the contributions. And as Tony pointed out, the CapEx is really -- the CapEx cycle for this as strongly this calendar year and into the 26%, but we'll be over that soon. What we highlight on the next slide is the energy supply in response to clearly, what happens a lot in the energy market can be complex. So what we've highlighted are how under different conditions we run that portfolio and we've chosen 2 different dates. On the left-hand side, we've shown an oversupply day on the 26th of December. And here, you can see what we do is we run minimum generation. We maximize pool purchases during those negative prices. And that's what we're striving to do on those days where there is oversupply. There are many days, as you know, that are happening in that context. And we could even be pumping at our shell haven, which increases that short position. Then if you highlighted on the right-hand side, that's a very high demand day, and that's on the seventh of November in New South Wales. And in those days, we are seeking to maximize our generation that's Eraring gas peakers during those high prices. And on that particular day, we had 1 unit of Eraring unavailable based on planned outage just to highlight that sensitivity and also we'll have contractual protection in place. We'll have cap contracts that also took effect on that day. So you can see that length, if you looked at that supply bar even in excess of demand on that day. That just highlights, I mean obviously days dramatically differ all the way through, but that gives you a sense of what can be happening in the market and how we respond with that flexibility on a day-to-day basis. Turning to electricity gross profit. We are tracking in line with the medium-term target, and I'll start on the right-hand side. And so the medium-term target we provided of $25 to $40 a megawatt hour that target range includes the committed battery investments. We would have said previously that was based on the 4 to 5 gigawatts. Today, we would still -- we would see that we will achieve within that range even just based on the committed battery investments. It includes existing gas-fired generation. It includes the current retail margin, and it also includes exiting Eraring. What it doesn't include is any additional investments we might make in renewables and storage doesn't include any growth in retail or the VPP flexibility margin. So we continue to remain confident about that and execution over the last 6 months and market developments continue to support our views on that. If you went to the left-hand side, electricity prices, forward price is obviously a key driver of what happens year-to-year, you can see that the traded volumes to date indicate a moderate increase. But we do have several months to go for those wholesale prices feeding into the regulated tariff for '26, but you can see that indication. We would expect some of that to be offset any increase we received by some higher wholesale costs is just the normal swap and cap prices we'd be entering into. Then if we turn to the middle chart on coal prices, we have -- consistent with what we've said in the quarterly, we've contracted 55% of coal volume for FY '26 and those prices are broadly in line with the financial year '25. If you look at current forward prices for the '26 right now, they are broadly in line with expected 25 costs. So whilst we've still got more volume to contract, if they were contracted at the current forward price, we would expect that trend of what you've seen for the 55% to continue. If you turn to the gas margins, you can see the pattern of the -- on the left-hand side, this time, the prices have declined from the extreme highs in '23. There's a tighter domestic supply expected in the medium term, but we've seen prices come back off over the last 12 or so months. The medium-term target of $3 to $4 gigajoule remains our target range and confident of that. For FY '25, we expected we expect that to moderate, and that's largely played out in the first half. I think first half is more so than second. But you can see that's really lower market prices, but we remain within that range of $3 to $4 a gigajoule. And as you turn to FY '26. Clearly, we have a sale to GLNG that of 35 petajoules that frees up gas and should benefit -- the FY '26, we will have normal contract escalations as we buy more gas into the market that occurs that partially offsets that. We continue to have a good mix of long-term gas supply that enables us to operate in a market that has gas demand between customers, obviously, large and small, but also, I guess, fire generation fleet. Now turning to Integrated Gas. Turning to Slide 37. You can see that revenue has increased. Looking at the middle chart, it's higher LNG volumes and higher realized export prices and also short-term domestic prices. So that's driving a higher revenue overall. And on costs, unit costs have remained really around that $4 a gigajoule. We've had higher workover activity in power prices, and we've also invested in well optimization. But at the same time, we've had lower cyclical maintenance and lower exploration that's enabled us to keep those operated unit costs there, and we've had some higher power prices and development activity and nonoperated, but still holding that unit cost at around $4 a gigajoule. Then as we turn to production on Slide 38, you can see that production is up 3.5 petajoules or 1% on the equivalent half last year. There's no turn down this year, to be clear, which we really occurred through our LNG vessel power outage and we have had benefits from ongoing well and field optimization activities and cyclical maintenance in Reedy Creek and Reedy Creek is performing well. What we did highlight in the quarterly is exactly those same comments there that -- we've had lower fuel performance in Condabri, Talinga and Orana, really following the cumulative events of this cumulative turndown events. And there's been some lower production in the nonoperated fields due to underperformance and unplanned facility maintenance. You can really see on the right-hand side chart, the impact of that turndown and the operated production since then. There's a little bit more depth on that when you go on to Slide 39. So really recent production has been impacted by those. It's lower-than-expected optimization benefits -- we've got a good track record of strong production and low drilling and that's enabled us to be focused on field optimization. And I think you can really see that highlight -- on the left-hand side of the operated and nonoperated production, and the operated wells drilled since the 2019 financial year. That operated production since then has enabled us just to manage natural field decline and offset a reduction of 18 petajoules in the nonoperated assets. And we've done that through well availability of our workovers up to 90%. We've improved meantime to failure by 78%. We clearly have lowered flowing bottom hole pressure that's optimize those wells where debottlenecking surface infrastructure -- and the drilling program is therefore just focused on where we can utilize available capacity at the processing facilities. On the right-hand side, you can just see the turndown events in the Condabri, Talinga and Orana and the large event in November 23, and the production challenge is there following that. We have reduced the flowing bottom hole pressure, but it hasn't reduced to the target we would have liked based on the planned activity we were executing on our planned activity. And therefore, the relationship between the 2 has meant that it hasn't achieved the target. And as a result, we've got to ramp those activities up, and that's really what we're focusing on in the near term. Which then takes me to Slide 40, about the near-term focus, which is on those optimization activities to manage natural field decline. You can see there that, that is really driven by a ramp-up in optimization activities. What do we mean by that? It's really I believe artificial lift system conversions. These depending on the well types, there are different ALS conversions. We'll make this solid mitigation and then there's downhole design optimizations. And those will deliver short-cycle production at a low cost. So think about that as being the most NPV accretive opportunities, and that's why we focus on them, and that's why we've been doing that over the last several years. And then the sustained development drilling that will continue. And really, the timing of that is really just all associated with regulatory approvals, land access, and you would expect us to go through the joint venture and make good decisions around those drilling opportunities. In the medium term, sorry, the joint venture has choices around Reedy Creek in Combabula a lots of opportunities to drill there. To accelerate low-cost gas, and it's high performing those fields. So we've been very pleased with its performance. The one thing about that part of the APLNG area, if I could use that expression, is that its facility constrained today. So it's all around where we bring that drilling in and also the choice is available to us to increase processing capacity, if we choose to make that decision to invest. And then clearly, the other medium-term opportunities are drilling new your wells and tying them into existing facilities, noting that lead time from planning to production is over the next 2 to 3 years. And obviously, exploration and appraisal to convert more resources to reserves. When we provided our guidance at the quarterly day, that reflected the near-term focus that you can see above and maximizing facility throughput -- and that's the way you should see about our priorities right now and the benefits that flow from it. Just a commercial update on a few things, LNG price review. We previously disclosed it has a price review notice from Sinopec. The contract requires parties to use reasonable endeavors to agree a price competitive with the prevailing market price for comparable long-term LNG contracts either party can refer the matter to expert determination. It is effective from 1 January 2025. So we've got the notice, so you should expect that things are underway in that process. But I can't say anything further at this stage. And just gave a sensitivity below that -- or plus or minus 1%, that would mean a plus or minus AUD 110 million to AUD 130 million to EBITDA, and that's obviously after royalties. Just a reminder to investors, we had a cargo deferral in 2008, by APLNG buy, where they elected to defer cargoes for 6 years, but paid for those at that time. And the buyer can request make up cargoes from 2025 for the duration of the contract. So -- and as we progressively deliver those, that benefit or the liability -- sorry, the liability to deliver them will unwind. And a further reminder that we also, in 2018, entered into a gas purchase from QCLNG, that commenced in January 24 -- that's 350 petajoules over 10 years. It's an oil-linked deal in 2018. And you'll see that when purchases increased in January 24, -- but also when you look at our first half year sales volumes up, you can see we're getting the benefit of those volumes coming through to our results. I mentioned earlier, the LNG trading on Slide 42, I mentioned it. But you can see there, $400 million to $450 million range, expected to be the upper end. Half 1 delivered $285 million and in FY '26, clearly lower proportion hedged completely away, but it's expected to deliver a benefit between $50 million and $150 million in EBITDA -- and just to really highlight that this comes from the long-term nature of the Cameron contract, which does position us well at Henry Hub-linked volume that comes out of there. And we're finding that, that is a strong position as we think about those volumes, European, Asian prices and markets. Turning to Octopus. Clearly, I've talked about at least 2 businesses. They are world-class. Main point to note here is that the operational separation is complete. They are running as separate businesses. And during 2024, mid-2024, a new CEO was appointed to Kraken as it delivers on its growth ambitions. And so that demonstrates further evidence of the trajectory that these businesses are on their various parts. Some highlights on 45 just highlights just how strong they are seen by their customers in the U.K. compared to any other competitor by the YouGov survey, they are attracting greater than 40% of the markets, which is -- while they're competitive on price, they're certainly not the leaders of price in the market, and they certainly have a churn significant load than the rest of the market. It's driven by a whole range of things, just operating model brand, ability to compete, respond, speed and they currently have 25% market share, and it has grown -- it is growing at around 3% per quarter. The big thing today compared to several years ago, is that they really -- their acquisition costs are dramatically lower. They're greater than 30% lower than in the last 2 years and the prior 6 years, and that's really through the strength of the brand and internal channels growing over time. We're now seeking to replicate that scale on Slide 46 through to several deregulated markets outside the U.K. You can see in Europe, principally, but also Japan, where there's a joint venture with Tokyo Gas. They doubled those customer accounts in the last year. They have prudently allocated capital to invest in the growth. And they're really just focused on replicating those success factors in the U.K. which are really around customer service, their pricing, innovative products, that same efficiency and cost to serve. And you can see just the dynamics in those markets in terms of switch rates, smart meter penetration size of market share households and the growth that they've achieved in the last 12 months. Now turning to services. It's investing, as I said earlier, in the Energy Services to grow customer lifetime value through low carbon tech, heat pump EVs and charges, solar and batteries and smart meters. And really, the customer lifetime value comprises the margin on the businesses themselves. The equipment installation, the aftercare and then also the value of the flexibility and orchestration. And building on really the strong brand and scale in the U.K. market. Heat pumps is the big market here in terms of the gas boilers over 1.6 million are installed. You can see the government is supporting the conversion of heat pump installs and they've invested, as Tony said earlier, in a technology and installation network to address that opportunity. When it comes to EVs and charges, they've been in this market for a while, the largest EV fleet in the U.K. and largest installer and public charging network. That has translated through now to the fact that they have over 200,000 I think EV customers are translating to 1.5 gigawatts that they're managing under their equivalent of the VPP. And solar and batteries are growing, certainly growing in their market as more installations occur. That low carbon tech really on that customer lifetime value. You can see has really driven the services -- but if you thought about those 3 bars or 4 bars on the right-hand side, core business is energy supply, the energy services would be that sort of margin installation and that after care, if you're going to call that maintenance and flexibility and orchestration. They are what drive it overall. And clearly, they have a vertically integrated position, a highly engaged customer base, national coverage, proprietary hardware and software and ability to access those flexibility revenues. And to date, the customer experience has been very strong. Turning to Kraken. You can see that operating system. We've highlighted this slide really makes -- to sort of just really bring to life. We were a talked to customer previously, there was the flex, but now really that's moving into field and grid. And therefore, the number of utility types that it's supporting at the bottom of the screen is extended beyond electricity gas to in-water, wastewater and broadband. And really highlights the customer account growth. The difference between contracted and live very clearly as lives, when it starts driving revenue contracted is really when they win the customer, so there's a lag between the two, but certainly developing a track record of implementation. And you can see that getting to the 100 million accounts, which they're very confident of by 2027, that would translate in excess of GBP 500 million of ARR at strong margins. Clearly, things they're focused on now is landing customers in markets beyond the U.K. and Europe and the U.S. in particular. So then turning to the outlook and wrap up. What we have done here is just summarize the guidance. And in the appendix is all of the commentary you would have previously seen on this slide. We've unchanged. We're feeling good about the Energy Markets business for the 2025 year, but we've not changed the guidance to that. But based on first half, feeling good about the overall performance of that business. I've talked about the LNG trading EBITDA being up upper end. The investment in services will mean that the Octopus Energy EBITDA will be less than $100 million. And what we've included really is the total CapEx. Just so you've got an indication of what we expect that CapEx to be over the course of this year. Clearly, when you're actually doing big projects, you can always have timing of payments and everything, but that's -- if it all tracks the plan, we'd expect it to be there. And the APLNG guidance is consistent with what we updated on the 31st of January. And the last thing, which we won't cover today, but just for the benefit of all of you on the call, the strategy and ambition remain the same. The pillars of our strategy remain the same. And if you have a look in the appendix, you'll see how we're tracking towards all of our targets as medium-term targets and ambitions. And we continue to track that performance, but we felt that could be included in the appendix and available for your information. So on that note, I will now pause and we will open for questions.

[Operator Instructions] Your first question comes from Tom Allen from UBS.

So today's results, you can see that the balance sheet remains in good shape. You've been in the market expectations on the interim dividend. So I was hoping you could please provide a bit more color on the CapEx outlook for the next couple of years. So consider that over the last 6 to 12 months, you've accelerated investments in batteries. Are there additional battery investments expected? And do you see any upside risk to Origin's electricity portfolio margin and the consensus assumed earnings contribution from batteries over the next few years?

So firstly, we've not made any further commitments on batteries at the moment. We've really set ourselves up with having these batteries in each of the states. There's a lot happening in the battery market. I wouldn't have an expectation we'll make a another near-term investment, but we do assess it from time to time. I just say that. I mean you're seeing lithium prices come down, you're seeing durations increase. The move from 2 to 4 hours will continue to exercise our mines. But I think you should expect this is the investment expectation for batteries. We gave guidance for returns on batteries I think of the last results announcement. I'm going to get this, I think, 8% to 11%, but any messiness would skew that to the upside. I think if you reserve the market, we have no reason to change our view about the core returns. What we would highlight is that the market continues to be very dynamic, and I think you've all seen that over the last 6 months that it's actually tightness on key days, lots happening, aging coal plant and lower prices in the middle of the day. Those have all continued. So we continue to remain positive and constructive, I must say, towards the battery investments. And very pleased to date in terms of the cost and time frames in terms of the construction as well. I think on broader CapEx, if I step back, recognizing APLNG has its CapEx embedded within its cash flow distribution and I'm sure people might ask questions further about APMG and we can talk about that later. But outside of that, what really we have is, we've come out of a heavier period of time for Eraring because we had an ash dam to be -- and that's largely complete. So really, the run rate for generation, you should have that as in the maintenance and sustain being in a pretty steady flat contribution like nothing and that we've always, I think, guided overall would be in the $200 to $300 million, I think it was or something like that overall. And therefore, anything beyond that in our portfolio and might just check if Tony has got any further thoughts. But from our perspective, anything else would be just around growth opportunities. But I think what you heard from Tony earlier was that on the premise that we go through that on the premise that really that Yanco delta, depending on timing and how that process plays out is largely our balance sheet except for the early stage development. I'm not -- we're not flagging any other large CapEx in the sort of non APLNG outside what might be opportunities, and we would bring those forward at the right time. There's no shortage of opportunities. I think the key thing now what I'm talking about is growth opportunities. But we would have that. Last reflection is that Golden Beach is probably one of the key, the gas storage project, which we're working through, but not ready to commit to that at this point, but that's probably the key. Do you have anything else on CapEx?

Now I'll just sort of highlight that the CapEx for the battery spend is about $950 million this year. We did sort of expect that to tail of that in '26 to be around sort of maybe half of that Frank highlighted maybe some other things that we might be thinking about. But same business CapEx is the usual sort of level -- just on the battery contribution, the way to I think, think about that 8% to 11% is that a post-tax return. So if you're trying to think about EBITDA, just sort of make an adjustment for that. And as Frank's highlighted skewed probably in the front end to the upper range of it...

That's helpful. And just on APLNG, just recognizing the changes to guidance that came out of 31 January, update. How should we be thinking about changes going forward in those totex unit costs? So you've been through a period in the last couple of years to try and take those costs out. You're flagging now the more development work is required and the optimization work that you've been doing it. Is that the point of sort of at least maybe diminishing returns now at least in the Talinga and Orana area? What sort of scale of increase should we be planning for an increase in unit totex costs? And then the second part of the question is, how should we be thinking about modeling the treatment of the deferred cargoes and the cash distribution that comes back to larger over the next few years?

Yes. Okay. I'll kick this off, and I'll also get Andrew to make some comments. We still hold a $4 a gigajoule ambition based on the near-term optimization activities. I'm not saying that's going to be easy, but we certainly hold that based on what I would say is that well optimization. What we've highlighted between near-term and medium-term differences is that, it's therefore going to be most of the focus will be on those activities. So that will be near term. And then when drilling comes in, you could see there might be a lag for that if there's extended drilling or other facilities, if we decided to invest in those, they would happen a little further. So it depends on your time horizon. And I think on the cargo, it's probably just a little early, but on the deferred cargoes to us to give a certain view on the volume of those I might just ask Andrew to give some commentary, which will be a little further color on the fall and how to think about that, and we can open up on the cargo bid as well.

Yes, so building around the Frank's comments, so the $4 a giga real target or ambition that we released last year still holds. That's still our ambition. The change to the spend profile as you look forward, will be an acceleration of the well optimization activities that we've talked about, which that's really -- will be the response from not being able to fully offset the decline in CTO this financial year. So we'll ramp-up those activities to try and manage that decline as best as we can. I think then on the -- and as Frank said, there'll be no immediate -- we'll continue the kind of levels of drilling that we've done this year into next year. There will be no immediate ramp-up in development drilling. But we will there are some choices over the medium term, which are really joint venture decisions as we flagged in the slides there, particularly if we want to accelerate development drilling and production into Reedy Creek that's likely to take -- require some investment in processing capacity. We'll restart our exploration program next year. And so really, those are some medium-term decisions, which it's going to be the joint venture decision to make. And then part of that will be how successful we are in being able to manage that decline through what are clearly lower cost, well optimization activities.

And cargo is anything for just to join us..

Yes. So as a reminder, these are 30 cargoes that have been paid for that haven't been taken. We have an obligation over the life of the SPA to redeliver those cargoes. But the profile of the redelivery of those cargoes is to be determined and to be agreed. So no fixed profile, but we'll aim to redeliver those cargoes over the next decade.

If you're holding a view on that. I just can't be precise about it. I would not be back ending it to the end. I'd be sort of progressively doing it over a number of years, Tom, and you could put some sensitivity around that. That would be the way to think about it, not thinking it will be at the back end of the contract.

Your next question comes from James Byrne from Citi.

Congratulations on the results. I just wanted to pick up on that APLNG cargo deferral. Are you able to say perhaps how much flexibility the customer has in the annual delivery plan to call on those cargoes? Because obviously, we've got another 1 to 2 calendar years of a rather tight LNG market. And if they are lifting those cargoes effectively for free, having treating that prior cost is sunk, if I was at customer rationally I'm going to be calling as many cargoes as I can. So is there a limit there on how much on the phasing of that because it could be quite a material hit to earnings?

Yes, I can pick that one up. So you can think about it as a normal -- like a typical commercial agreement where, in particular, I can't ask for cargoes, we don't have or uncontracted gas we don't have. And so you would expect that to be a negotiated outcome each year but that liability is in place. And so we will have to discharge that over the period. But there's no intellectual right on one party or the other to be able to determine what that profile is.

Understood. And then also just following up on the APLNG production side of things, it kind of sounds like a lot of the CapEx it might put to work -- like obviously, there's an NPV optimal outcome on CapEx and production, right? But if some of these opportunities like Reedy Creek, maybe more medium-term choices as you put it is the right way to think about APLNG production is that we're actually going to see a little bit more decline beyond what you've already guided to that period before some of that CapEx starts to materialize as molecules?

Yes. So there are a number of moving parts. If you think about what's production going to be over the next few years, there are a number of moving parts, which make it challenging to provide specific guidance beyond the year ahead. And some of those things to consider are what's the natural level of field decline going to be, what level of -- what would the effectiveness of our optimization activities to try and offset that decline. And then you've got these other sort of bigger decisions, which are capital investment decisions with a joint venture needs to make on drilling and infrastructure. As far as if you just sort of look and sort of make a comment on the next couple of years, I think what we're trying to provide some context to is there's going to be no material contribution over and above what we've seen in the last couple of years from drilling. We're not going to have a material ramp-up in drilling, which we'll see a material ramp-up in production from that drilling. Drilling in addition to some of the constraints that we see to accelerate the drilling -- any drilling you do is a couple of years lead time before you see that production. So assessing next year and the year after is really an assessment of what's your natural decline and how much can you offset that through optimization activities and they're the activities that are going to be ramping up. We have been successful in offsetting a lot of that decline in the last few years. This year hasn't been as successful in Condabri, Talinga, Orana and really, that's there's some -- a couple of drivers we've called out for that. One is these unplanned outages and turndown, that's come that slowed us down from the ability to actually execute those activities and drop those long bottom hole pressures. And then as that part of the field has moved -- transitioned from facility constrained to field constrained is learning more about the extent of the optimization required. And our view is we're going to have to ramp-up those activities to manage the decline moving forward.

Perfect. I might switch just very quickly on energy markets. I was a bit surprised you left energy market guidance unchanged despite a strong first half, and you've described yourself feeling good about energy markets. I mean if someone is behind us now, right, that big risky period, you since you've gotten through those Eraring trips really well. What's that actually pertain for second half and beyond, if you're not lifting the bottom end of that guidance despite feeling good?

Just look, we're more comfortable with it. There's nothing out there. That's why I was giving you that. We -- you're right, we had choices whether you're narrowing them in and lifting bottom and all those things. from our perspective when we look at the guidance range and where we think we're sitting at, we feel just comfortable about it where we think consensus and all those are at, we think we feel comfortable about it. We've still got to operate over the next few months. There's nothing out there, James, and that's why I gave you the commentary we did. I just felt it was best to hold, where we were at the moment and do better than that rather than something else, but there's nothing we're worried on -- and there's still stuff going on every day. So nothing out there that I would call out specifically that's going to that. But overall message is more comfortable and just made a judgment that we would hold at the moment.

Your next question comes from Gordon Ramsay from RBC Capital Markets.

Coming back to the LNG deferred cargoes, just trying to understand how they will impact your existing sales volume. Is there any impact on the 3 to 4 spot cargoes you might make each quarter, if you're going to be selling or providing these cargoes to the buyer, they put up their hands. Does it mean less spot LNG sales?

Yes. Any redelivery to that customer would come out of our would be over and above what's already contracted. So it would come out of our uncontracted -- and uncontracted gas -- and we think about LNG is spot given our mandatory code requirements, we think about that as the swing customer. So if that's how you would think about it. If there's an extra, say, 1 cargo or 2 cargoes going to that customer, that would be 2 less spot cargoes all other things being equal.

And secondly, just on the retail side of your business. Yesterday, we heard about squeeze margins, their gross margins coming through and increased competition. You haven't said too much about that in your briefing. Can you just comment on how Origin is handling that?

Jon to make some comments. Jon Briskin here, who runs our retail business.

Yes. Sure, Gordon. So the market has been competitive and probably the first couple of months of the half were in particular, a high churning period. In terms of our performance, we've just had a modest increase in customers on a discount. And what we would look at our weighted average discount has really not changed particularly, like it's perhaps slightly higher. So we would call out probably more of a modest compression in retail electricity gross margins, probably mostly offset actually by gas gross margins improving as we recover to the prior period costs.

Next question comes from Dale Koenders from Barrenjoey.

Frank, Tony and team, I was hoping you could provide a little bit more color on the outlook for Octopus. Can you quantify the impact of the investment phase? Is that the $45 million in the waterfall sort of as a one-off hit or bigger? And how long will that run for?

Just give a sense for, and you can see it's obviously specifically to the services business. It's largely associated with the heat pump business where they've invested in manufacturing and installation capacity as they grow the volume into that market. So you would expect it to reduce over time because it's actually invested in sort of field force and proprietary tech and manufacturing installation and then it's around really the revenue that flows from that as they grow the revenue, and they've been growing it, the profile of that will be all around the ramping of the growth in revenue over time and the volumes that they drive. So whilst not one-off, you would expect over time -- but certainly, for this financial year, I would expect into the second half. The reason we provided the guidance we have is that we would expect to see that to occur in the second. We would expect to see a similar sort of contribution in the second half. But that's very much a profile, and that's why it's more difficult to predict beyond that because it's all about that ramping into growth. They'll continue. They've been very good allocators of capital. over the journey with them and so we'll be in dialogue with them, but that's the nature of it. So that's really how you should think about that profile.

And then in terms of the earnings contribution, do we assume given they're good allocated to capital, a decent return on that effective cost and investment may be ramping up in a year or 2 years?

You would expect that to be the case, yes. But it's a business that's obviously slightly different in profile. If that makes sense. There's quite an upfront investment associated with that, whereas you've seen with the retail businesses, they sort of really can ramp up and down activity. But you would expect that they're investing on the basis that they're going to generate those returns over time, and that's how we would expect that to flow through. They are very growth oriented, and you've seen that ambition through what they've done. And they have been prepared, as you could see in both U.K. retail and even the non-U.K. retail and Kraken to be able to -- they won't be shy in terms of investing in its growth profile with a high ambition. But when I say about allocations of capital, they've been -- if you look through all the way the retail business, it's been they've never overpaid on any customer acquisition inorganically or organically and haven't been tempted by it. And that's the comment I'm really making that they'll do that, but they are a growth business, and they are reinvesting. You can see at a higher rate into that growth for the big opportunity that sits there. But this one, it's just it's early days. And therefore, we're going to see it play out, and I'm sure they'll continue to They'll continue to respond to the market and what they need to do to succeed and make calls along the way.

And then I have a second question for Tony. Just on the dividend outlook. We've only had a very brief history of executing on the new dividend policy and briefly against yourself. Prior to flagged sort of FY '24 dividend level is being the right sustainable level for the business going forward. Just maybe some comments on how you're thinking about second half dividend relative to first and sort of the outlook into future years is sustainable at this level still the right comment?

Yes. So when we came out the new dividend policy, we really took away the, I guess, the cap on the paying a dividend on the free cash flow. And really, the purpose of that was to be able to look through the cycles. And I think you should think about that, when you think about the dividend as our intention is to hold or grow the dividend at a cents per share level and be able to look through the cycling of cash flow because the cash flow in this business does move around year-to-year. When the Board has considered the interim dividend in the first half, we're looking through the CapEx spend. We're looking at the outlook for the 2 businesses. And we just consider that when you look through those, the dividend payment as a percentage of free cash flow is probably reasonably high this half. It's obviously offset by the fact we had to pay a bit more cash tax. When we look through that, this is we sort of see this as more than sustainable.

Next question comes from Nik Burns from Jatin Australia.

Maybe another question back on APLNG and just the lower current production levels. What's the JV's current view on what's caused the more rapid production decline. Is there a feeling that it's a temporary impact? Or is it a permanent well issue? And just thinking through the consequence of this, whether there's any reserve implication from the more rapid decline rate?

Yes. Thanks for the question. So in terms of -- so maybe a starting point, of course, all unconventional wells are on decline after initial peak period of production -- and so what we try and do is manage to offset if we can, but manage that decline by lowering any back pressure on each one of those wells, such that even in a declining reservoir is still getting good production flows and the stable production flows as you can. And it's all we have. So as I said earlier, well, we've been very successful in doing that over the last few years, but this year, we're unable to do that. What will be required moving forward is more of that activity. So think about that as things like ALS conversions, debottlenecking, managing any constraints that exist in the system. So when you think then what does that mean for production on any given well on -- each well will be different, hopefully, and we would expect that some wells will increase production when we do an ALS conversion. Some will continue to decline. And then overall, we hope as a portfolio, that field -- that we can offset and manage as much of that decline as possible. As far as the impact on the overall reservoir or how we're feeling about it, no fundamental change in how we view the resource, whilst we need to go through the reserves process, of course, and that's independently assured nothing that we've seen so far indicates anything unexpected from a decline perspective. So it's just the way you would think about that is the optimization impacts just defers anything that we didn't realize in '25 into '26 and beyond. It doesn't change the amount of gas that's ultimately going to be recovered. So we don't, at this point, see anything that would impact reserves.

Got it. My understanding is a reasonable proportion of coals and gas reserves is based on really drawing down the bottom haul pressure to quite a low level, and that may require some type of nodal compression at some point? Is an outcome here that you would need to think about accelerating the investment in that type of means to really get bottom-up pressure down to the levels that you've feel is necessary to extract all of these reserves?

Yes, you're exactly right. The key to extracting all of these -- what we treat as reserves and resource will be to lower as low as possible the flowing bottom hole pressure over time, and you want to lower that sort of in parallel to the reservoir pressure dropping, we would expect that there will be some kind of additional compression required. There are different technical solutions to do it. You can have wellhead compression. You can have a nodal compression, you can adjust your existing GPS that we have. We we'll consider all of those alternatives and something will not be required over the life of the asset to continue to optimize those fields. And so, what we have flagged here is certainly relative to expectations previously, it's not that we'll need to do additional work that was prior to expectations but we'll certainly be accelerating that work into next year. So you'll see additional investment into those well optimization activities. Whether that includes nodal compression next year, not sure, but it will certainly be continuing the work that we have done at a faster rate.

There's been a few questions about APLNG appropriately. And I just wouldn't -- and there was a couple of comments earlier, so I thought I just might add a couple of things. So firstly, there was a reference earlier that the deferred cargoes would impact earnings. And just for abundant clarity, it's a cash flow impact rather than an earnings impact. And just -- because I heard that there, we should just be clear about that. The earnings recognition won't change, it will be cash flow, but it is cash flow. So that's what drives value as well. So we'll do that. The other thing to remind was, whereas people were starting to think about volumes and what is happening as a result is that the QCLNG deal, which was struck in 2018, and let me just say, fields have performed well and truly better than that ever since then. But we do have 350 petajoules of volumes that are coming in on oil linked. So when you're thinking about volumes available for spot markets and volumes available will be sold domestically and under contract, -- we will have those volumes available as well. So I just wouldn't want to make sure people are all linked to that between production versus sales versus what's available and how am I thinking about volumes overall.

Your next question comes from Ian Myles from Macquarie Research.

Maybe just start at the macro level. You reiterated that long or the medium-term guidance of energy markets at sort of $25 to $40 a megawatt hour, you're sort of sitting at the upper end of that range. The other question sort of emerged is -- when do you think you can start seeing actual volume growth in the system? Because you actually haven't really sold much more than 35 to 37 terawatt hours per annum for the last 5 or 6 years?

Yes. So firstly, and Tony here, just talk about $25 to $40. So that range, as Frank sort of highlighted, has the committed battery projects coming in and Eraring exiting. And so we would sort of think there will be probably where you get an overlap of those 2 things will probably be towards the upper end of that range? And then any additional investments that we made within perhaps drift us to the top of that. So yes, we're probably a bit stronger on that range in the medium term because of the batteries coming on and Eraring still providing a good contribution.

What about the volume? Because the other half of that is volume, which isn't really moving....

Yes, that's just about to address that. So on volume, we've seen a huge amount of -- in terms of -- on the system, we've seen a huge amount of PV solar on rooftops coming in offsetting most of that volume growth. If you look at the volume growth at AEMO's forecasting, whilst a reasonable chunk, 15%, 16% comes to 2030, a lot of that load growth in terms of electrification, perhaps data centers. I know have they got hydrogen there, but we've probably got a little less of a strong view on that. starts to come in sort of 2030, 2040 period. So we'll compete and not a lot yet, and it's coming at the residential level. We're seeing some uplift with EVs, et cetera, but that's still I think still forecast to be stronger uplift in the future. So a lot of it's coming in the C&I market will still compete heavily at that. We have in quite sort of, I'd say, deep discussions with data center, developers, et cetera, to compete in that market. So we're hopeful that some of that volume then starts to flow in the medium term.

Just a specific one. On your cost saves $100 million, $150 million per annum, is that inclusive or exclusive of the licensing fee now to pay the Kraken?

No, that's inclusive of the licensing fee.

So the underlying savings are probably again a bit larger than that as a whole.

That's right. We'll absorb that in that range.

And how are you tracking at this point in time? What sort of run rate are you actually locked in of that $100 million and $150 million.

We don't really want to sort of guide. I think we would say that we'll see a reasonable sort of reduction in fin year '25. I'd say maybe we would do 1/3 of that number in fin year '25, perhaps. But programs have been in place, they will see that we're pretty confident on that reduction into '26.

Just on Octopus Energy Services. Last year, that business is 100% owned, lost sort of GBP 50 million. Based on your slides, it would probably imply the businesses moving close to probably GBP 200 million this year. I was just sort of trying to get my mind around, is the large losses reflecting the cost of installation, getting people on smart meters, EVs, heat pumps, et cetera and that the profitability will come as all of this is installed and we moved to more of a service orientation like gas fire, heat pumps or gas boilers are done?

Yes. So -- and the ramp-up is really associated with, think about employee force, manufacturing capability and installation logistics and all of those things that come with that. And so therefore, that cost is in place to deliver and really it's the volume of -- and I would really be looking at the volume of heat pump installs is probably the key driver. When you think about the EV business and even the smart meter business and so forth, I would be in the business that existed for some time. So it is all about the pull-through volume and utilization and efficiency of that employee force that's actually going to drive the margin growth, recognizing it's a large market, national coverage and they've invested in that capability to deliver for it. So it's really going to be all about that volume pull-through and efficiency of installation.

And I couldn't not ask Thames Water and Octopus have been mentioned in the same breath. What's your attitude to that? And would that require more capital to be injected.

I don't -- Thames Water. Because I think we...

Just one thought because I know it speculate on it -- on there's a little bit of press around it.

Look the comment I have in response to that is this, is that -- you've got a U.K. retail business. I saw your research note last week, you talked about what it makes per customer and the reality is you look at the seasonalization and we're growing that business in U.K. retail, and it continues to grow our customer base. Kraken has healthy margins in an ARR that's contracted, and then you should still look at those and the pull-through of that execution of that from contracted to live. So 2 very strong businesses to do that. They have been good capital allocators -- they are ambitious on growth, and it's in a very strong position to be able to do that because it now has 2 engines that are driving that. It will all come down to the growth aspiration and shareholders having discussions around that. It's been well supported. So I feel very confident about its financial position. But I've never heard that comparison before and it's not something I would even entertain.

And one final question, you mentioned in aging markets, gas, the importance of gas, 2 elements. Firstly, you flagged previously, I'm not sure exactly when you're looking for new gas sites and positions. I'm interested in how that's progressed in developing those sites and the likes? And secondly is lots of high Eraring batteries and the profitability of batteries -- what is the corresponding offset to the profitability of gas plant, if batteries are far more active in the 2 to 3 hours every evening.

I might get Greg to talk about portfolio that's okay, and I'm happy to open up.

So firstly, on gas sites, we've got existing sites, which we're looking to go to the next level of detail, just giving us that option, if getting ready for the next round of gas. And I think just broadly, longer term, if you really want to take out more coal and Frank alluded to it many times, we really do need more that mid-merit, gas-fired power stations. So we're getting ready for that, and we're getting -- we've got the Mortlake side in Victoria the new site in New South Wales, and we've got Darling Downs in Queensland. So we've got pretty good sites we're looking at. Yes, just as batteries, I mean, you can see the volatility. We've just got renewables coming in all the time. We've got negative prices and you're getting volatility. I think batteries it's a good story. It's a very good story for Origin because I think our batteries will complement our existing gas-fired power stations. So what I mean by that is you're really you've got to be careful about just running your gas-fired power stations and having a start cost just to meet one hour of volatility -- batteries actually doing a better job of that. So they're very complementary. And quite frankly, if we -- if I think forward even further, ultimately, coal will come out of this market. It's baseload. Baseload is a very hard technology. It's very costly. You really do want flexibility and -- so I think the sustainability of gas and batteries with renewables is very much part of our strategy, and I think it's -- that's where we are at the moment.

I think, and probably the other thing to think about is -- when you look out sort of 2040 and AEMO's sort of forecast, they would say we need 6-7 gigawatts more of gas, they would have sort of, I guess, a total of about sort of 45 gigawatts of firming that has come into the market to meet that load growth that you talked about and also take care of that 16-odd gigawatts of coal that's coming out. So we sort of see batteries, as Greg has highlighted, and the OCGTs is complementary with the batteries dealing with the more frequent shorter volatility spikes and moving energy and OCGT running that sort of longer term.

So just to be clear, in the near term, as those batteries turn on, you don't see any financial impact from the gas fleet as a result of batteries being more active in the market?

Yes, I still think you'll see quite elevated cat prices. I mean, cap prices are what, Greg? $30, $39 a megawatt hour. I still think there will be demand for longer duration contracting cover in the market and majority of the revenue recovery for the peak is absorbed through the contract market and what's recovered in the tariff, there is the sort of the spot returns. I still think that we see significant periods of 4-plus hours where gas is going to be leaned on, particularly as coal exits and becomes less reliable. So we're not -- we're not seeing any sort of material decline in that outlook at all.

Your next question comes from Rob Koh from Morgan Stanley.

Congratulations on your first half results. May I first ask a question about APLNG. We've obviously had a lot of questions about the activity levels. There is a comment on Slide 40 about facility constrained today. Apologies if I missed this. Can you maybe just give some color on which facilities? Is that really Creek processing or is it Arrow or gathering or -- just some color there, please.

Yes. I think you're on to it, but I'll get Andrew to describe it in.

Yes. Thanks, Rob. So a couple of parts of the field of facility, what we call facility constraints. So in really Creek is gas processing. So that's a function of stronger-than-expected reservoir production and performance. And that's the -- when we talk about an investment required, that would be for additional processing capacity to augment what's there already. Then in Spring Gully, we're actually water constrained for the moment, and we've got some infrastructure to debottleneck, which will be -- which over the coming 12 months will be in place. And then we can still do some level of drilling that is planned in Spring Gully, but ultimately, that's -- that's expected to be quite close to maximum capacity from a gas perspective for quite a while. So the ability to ramp-up further than what's currently planned is constrained. So they're the 2 areas of I feel that we would say a facility constraint.

Much appreciated. Maybe switching over to energy markets and the progress on the cost-to-serve reductions. One of the issues that you'd encountered during the previous year was the ability to disconnect gas customers in a compliant manner. And can we maybe just ask Mr. Briskin for an update on that particular part of the project?

Yes. Good day, Rob. So as you are right, we have certainly reduced our volume of disconnections in part that's driven through sort of making sure that customers disconnection is the last result and in our regulatory requirements, we met all of the outcomes there. We have started to increase that. we've seen more across sort of November, December period in the United States and then in Victoria into the new half. So we're working very hard to get customers engaged, get them onto payment plans -- disconnection becomes a set the last resort to get them back engaged with us and what that's flowing through to is better collection outcomes that you're seeing overall, in particular, in the early part of our book as we work on those -- on all customers in debt.

And then a question on Octopus. I guess in years gone by the Octopus cost-to-serve advantage has been a big part of the thesis. I know it's a lot more than just that. The Octopus accounts suggested that the staffing numbers have shot up quite a lot back in April of 2024, up to about 7,500 FTE. Just can you give us any sense of how you're viewing the cost to serve in the retail part of the business? And is that still a key part of the advantage?

Yes, Rob, it's Jon again. So the number you're quoting includes the entire business. There's -- obviously, as Frank pointed out, a large field force in the services business, there's growing international presence, there's Kraken as well. Retail still maintains a strong cost-to-serve advantage, where you'd look at comparisons to its nearest competitors and across the industry average. And yes, no, it's certainly having -- holding our cost to serve advantage.

Sorry, 1 more question about Octopus. So obviously, the big growth push into Energy Services is one of the projects ongoing. This a 2-part question. So firstly, is energy services covered by the Origin NIM exclusivity deal i.e., can Origin bring any learnings from that into the NIM -- and then also, that business, I guess, I've conceptually been thinking of it a little bit like your community energy services business in that it's a little bit infrastructure like in how it operates. Is that fair?

Correct. So there is there's a lot of learnings that we can jointly share across the business. I think there's a real opportunity through the electrification of the homes as we're seeing to be able to orchestrate -- orchestrate those assets that also create value in its own right as an asset class that we can embed into our products and embed into our pricing constructs. So I think there's a lot of sort of opportunity to go down the track there. One of the great opportunities that we have is that we actually deal with a lot of customers now through our partnership with solar quotes that are looking to electrify their home. And we see that over time, that provides us with a bit of a distinct advantage, however, we decide to participate. But it is probably worth pointing out at this stage, we're not looking to build the field force, for example, in the Australian market because it's quite well established here in terms of the contract and technical expertise.

Your next question comes from Henry Meyer from Goldman Sachs.

I think, perhaps a final question on APLNG. Just understanding that the JV would need to approve plans for all the accelerated drilling activity, maybe more investment in capacity and compression -- it seems the decline in CTO has been fairly recent. So could you share how far progress and updated development plan is at the moment? And when we could have perhaps a more firm update on CapEx and production over the near term?

Henry, so the work program and budgets for APLNG are approved year ahead. And so we're going through that process over the coming months for FY '26. There's pretty good alignment with the joint venture on what's important and the best way to optimize and create value for the shareholding group, which does reflect the comments today around the best value and the highest value accretion is optimizing existing well fleet, well and infrastructure fleet within drilling -- development drilling and exploration being on top of that as required. And so that's just an ongoing discussion with the joint venture.

Got it. And within energy markets, we're looking at the current year gas margin remaining within the $3 to $4 targets, but also hiring that the GLNG contract will roll shortly. Is it fair to expect that even when that contract expires, we'd be looking at a portfolio margin below $4 next year?

Tony here. Yes. So yes, the decrease we saw in the gas gross profit this year, as we highlighted at the full year in '24, was those prices coming down and flowing through into the business and large sort of C&I customers, and then we also have some sort of trading deals. GLNG rolls off in '26 is Frank's. So we expect some uplift because that was signed at sort of lower prices. I think that -- and the balance of the portfolio will have escalation -- normal type escalation on some of the fixed price contracts. And then we've also had to do some recontracting of some oil slope there. So there will be some offset, I think, from the rest of the portfolio in terms of cost. But I think directionally, you're broadly right.

And Henry, just a follow-on just from Andrew's comments because we have got good alignment with the JV. We're not actually waiting for WP, but just for clarity, the ramp-up activity of the optimization activity is not waiting for WP&B. So the joint ventures aligned, they're moving the whole scaling of that is underway. And the planning for '26 is underway. And clearly, the WP&B would then consider the activities that might flow through to drilling over the next 2 years, if that makes sense or whatever the lag time might be. So I'd just flag into you, if I wouldn't want to leave you with the impression that we're not we're not ramping that activity now, the optimization activity.

Thank you. That does conclude our time for the questions. I'll now hand back to Mr. Calabria for closing remarks.

Yes. So thank you very much for your questions, and we look forward to seeing investors over the next couple of days. Just one slide to finish with, really feel we've got an advantaged portfolio. It is difficult to replicate and we are investing further and positioning ourselves for the transition. I feel like we really have the momentum now having gone through the Kraken implementation in all the platforms and continuing the growth engine of both our retail and Origin Zero businesses. We've talked about our gas-fired generation, talked about the scaling of the batteries and the wind development and really whilst we're going through some optimization activity that needs to be deeper and faster when we've gone to the fields now, we still have a world-class resource and assets and low cost of production for that supply of gas. So and clearly, the global growth opportunity for Octopus. I hope you've got a sense for today that whilst investing into that transition, and there's no shortage of opportunities, we feel very confident about the balance sheet strength and the cash flows and that confidence is expressed in the fact that we've actually declared a high dividend today and -- we will continue to take opportunities focused on shareholder returns as we invest further. So thanks very much for your time. I really do appreciate it, and we look forward to catching up with you soon.