Okay, 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 two, and now really looking at page four, the summary of our result. Energy markets is lower in line with guidance expectations that we set 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 has delivered AUD 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 for the cost to serve reduction of AUD 100 million-AUD 150 million in 2026 financial year from 2024. We have 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.
That's obviously in addition to our Eraring plant. APLNG continues to generate strong cash flow. Following on from the commentary you would have seen in our quarterly, it's 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. Clearly, we have a global growth opportunity through Octopus, through both energy and technology.
They are now the largest UK 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. Tony will take you through the financial profile of the organization and how to think about that.
The financial highlights, you can see both statutory profit and underlying profit are both up. Underlying profit at AUD 924 million is up AUD 177 million from the equivalent half last year. Our underlying EBITDA of AUD 1,926 million is down from AUD 1,995 million in the equivalent half. Our underlying EBITDA to our adjusted net debt is at 1.5 times.
That's still well below our target of two to three times, but is up since June. The rolling 24-month return on capital employed is 16.4%. And you can see the interim dividend of AUD 0.30 per share, fully franked, is up AUD 0.025 per share. When we think about the energy transition, it's a multi-decade challenge to achieve net zero. I'm on slide six. And what you can see is that new capacity in renewables, storage, and consumer energy resources will increase by greater than two and a half times.
And I should point out that this is under the AEMO 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 oversupply with the increase in energy coming from must-run renewables.
It is the longer duration energy that becomes 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 that 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 policies focus 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.
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. 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 a 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 a 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 give us the 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 Nations spend community funds in communities such as Eraring, and also the volunteering by many of our employees. Turning to energy supply, I talked about an advantaged portfolio, particularly as a market that accelerates towards renewable and storage. 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, pumped 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.
have a good development pipeline as we target four to five gigawatts of renewables and storage by 2030. We have made very good progress this year with 1.7 gigawatts of batteries underway in the two to four-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 three 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 petajoules 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 that we've been undertaking over many years, and that's our near-term focus today. APLNG continues to play a very material and supportive role for customers on 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 2023, and they now have 1.8 million accounts in non-U.K. retail markets, a doubling in the last 12 months.
The organic growth between two of those, both U.K. and non-U.K., is about 200,000 monthly organic customer account growth. In Kraken, they had 62 million customer accounts on the platform at December 2024. 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 £500 million of annual recurring revenue or ARR.
Since December, they have 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 have made significant advances in their EV business and the translation of that to flexibility revenue, but now are really turning their attention to scaling up really a heat pump business that is attacking the gas boiler market in the U.K.
We'll talk through that investment and also that opportunity, but that's where they're 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'll talk you through the financial review.
Okay, thanks, Frank, and good morning, everyone. It's pleasing to be presenting such a solid first half of the year 2025. 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 a prior period, with the wholesale component of the year 2025 tariff stepping down and higher coal procurement costs 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. 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 were 100% franked. Turning to slide 15, operating cash flow saw a slight improvement compared to the prior period. However, there's two 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 AUD 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 2024 tax year. This really occurred due to higher Energy Markets earnings, unfranked dividends from APLNG having a lagged effect on installments. We forecast tax cash for 2026 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 AUD 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 AUD 562 million. At 100% APLNG level, the joint venture experienced strong operating cash flow for the first half of AUD 3.2 billion after AUD 400 million of tax payments. APLNG also repaid $301 million of project finance during the period and held cash of AUD 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 AUD 4 billion. That reflected higher cash tax paid this period and increase in CapEx from those large-scale battery investment program we've highlighted. Battery CapEx for all projects are tracking in line with the FID cases.
If I just go to slide 18, which is the dividend, the board has increased the dividend to a fully franked interim dividend of AUD 0.30 per share. This is up from AUD 0.25 per share. This reflects a strong balance sheet, strong cash generation from two 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 one and a half times, up from one times at the end of the June financial year last year 2024. This reflects an increase in the net debts, which I discussed earlier. We expect net debt to continue to increase through 2025 and peak in mid-financial year 2026 as we deliver that battery investment program.
It probably will be, 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 financial year 2026, 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. We make this through either contracting, tolling, or off-take 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 SuperNode One and Two and the Summerfield project. For renewable assets such as Yanco Delta, we may acquire the 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 off-take agreement, and we've 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 AUD 306 million to AUD 738 million for the first half.
As previously indicated, the flow-through of lower wholesale allowance in the retail tariff and the higher procurement costs this period for coal, as that market coal cap finished, resulted in a reduction in electricity EBITDA of AUD 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 included 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've seen bad and doubtful debts reduced by AUD 36 million this period.
We're well underway and confident of delivering the $100 million-$150 million cost out target for fin year 2026, and we'd expect the full year 2025 result to show an improvement in cost to serve on fin year 2024. 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. And that's partially offset by a $50 million loss on oil and FX hedging. Turning to the contribution from Octopus, Origin's share of Octopus' underlying EBITDA was a loss of $24 million.
UK retail business performed strongly, delivering positive EBITDA of GBP 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 UK 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 GBP 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 an ARR in excess of GBP 300 million. Octopus increased its investment in energy services by GBP 45 million, which was our share this period. As they scale this business, the energy service business, as Frank's indicated, 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 in electrification of that UK 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've adjusted our guidance for Octopus accordingly.
We still expect a strong contribution from both UK 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.
Okay, 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 number one residential embedded networks business. We've established Origin Zero. We built and grown our own VPP, which now is 1.5 gigawatts. We made the Octopus investment, and we've completed our customer migration onto Kraken.
We've strengthened the channels by owning those through acquisition of aggregators and most recently the SolarQuotes 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 an 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 two 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 Ink in terms of email 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 certainly is 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, faster 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 played a key role in the improvement we've achieved over the last six months in bad and doubtful debts and also payment channels. 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 two, 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 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 2026. 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 is 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 six 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 insights, subscriptions, 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 one, which includes the expansion and SuperNode stage one, we would expect to be making a contribution in the second half of the 2026 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 four and two hours.
Clearly, stage one's four hours. Stage two at Eraring's also four hours. Mortlake two, SuperNode stage one two. And then you can see the last two SuperNode stage two and Summerfield are all four hours. You can see a trend towards four hours. And if you take that CapEx on the right-hand side and divide it by the megawatt hours, you can sort of see the average cost per kilowatt hour there.
You will see that as we've made those investments from the very first Eraring stage one, which is sitting at around $600 a kilowatt hour. You'll see that the Eraring stage two and others are actually now moving down into the $400 kilowatt hour. That obviously does vary if you're in a two or four 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 is strongly this calendar year and into 2026, 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 two 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 Shoalhaven, which increases that short position.
Then if you highlight it on the right-hand side, that's a very high demand day. And that's on the 7th of November in New South Wales. And in those days, we're seeking to maximize our generation. That's Eraring, gas peakers during those high prices. And on that particular day, we had one 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 on that 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-$40 a megawatt hour, that target range includes the committed battery investments. We would have said previously that was based on the four to five gigawatts. Today, 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. It 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 six months and market developments continue to support our views on that. If you went to the left-hand side, electricity prices, forward prices, 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 2026. But you can see that indication.
We would expect some of that to be offset any increase we receive by some higher wholesale costs, 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'd said in the quarterly, we've contracted 55% of coal volume for FY26. And those prices are broadly in line with the financial year 25. If you looked at current forward prices for the 26 right now, they are broadly in line with expected 25 costs. So while we've still got more volume to contract, if they were contracted at the current forward price, we'd 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 on the left-hand side this time. The prices have declined from the extreme highs in 2023. 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-$4 a gigajoule remains our target range and confident of that. For FY25, we expect that to moderate. That's largely played out in the first half. I think first half is more so than second. You can see that's really lower market prices. We remain within that range of $3-$4 a gigajoule. As you turn to FY26, clearly we have a sale to GLNG of 35 petajoules that frees up gas and should benefit the FY26.
We will have normal contract escalations as we buy more gas into the market 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 our gas-fired 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 and 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 non-operated, but still holding that unit cost at around AUD 4 a gigajoule. Then as we turn to production on slide 38, you can see that production is up three and a half petajoules or 1% on the equivalent half last year. There's no turndown this year, to be clear, which really occurred through an 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's performing well.
What we did highlight in the quarterly is exactly those same comments there that we've had lower field performance in Condabri, Talinga, and Orana, really following the cumulative events of those cumulative turndown events. And there's been some lower production in the non-operated 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 into slide 39, so really recent production has been impacted by those. It's lower than expected optimization benefits. We've had 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 non-operated 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 non-operated assets, and we've done that through well availability via workovers up to 90%. We've improved meantime to failure by 78%.
We clearly have lowered flowing bottom hole pressure that's optimized those wells where deep bottlenecking 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 2023. 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 two 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 artificial lift system conversions. Depending on the well types, there are different ALS conversions we'll make.
There's solids 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 there's sustained development drilling that will continue. And really, the timing of that is really just all associated with regulatory approvals, land access.
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 and Combabula. 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 it's 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 wells and tying them into existing facilities, noting that lead time from planning to production is over the next two to three 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 can't say anything further at this stage.
We just gave a sensitivity below that if for ±1%, that would mean a ± AUD 110 million-AUD 130 million to EBITDA. That's obviously after royalties. Just a reminder to investors, we had a cargo deferral in 2008 by an APLNG buyer where they elected to defer cargoes for six years but paid for those at that time. The buyer can request makeup cargoes from 2025 for the duration of the contract. As we progressively deliver those, that benefit or the liability, sorry, the liability to deliver them will unwind. A further reminder that we also in 2018 entered into a gas purchase from QCLNG. That commenced in January 2024. That's 350 petajoules over 10 years. It's an oil-linked deal in 2018.
You'll see that when purchases increased in January 2024, 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 AUD 400 million-AUD 450 million range, expected to be the upper end.
Half one delivered AUD 285 million. And in FY2026, clearly lower proportion hedged completely away, but it's expected to deliver a benefit between AUD 50 million and AUD 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. It's a 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 these two 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 paths.
Some highlights on 45 just how strong they are seen by their customers in the UK 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 significantly lower than the rest of the market. It's driven by a whole range of things, just operating model, brand, ability to compete, respond, speed.
They currently have 25% market share. It is growing at around 3% per quarter. The big thing today compared to several years ago is that really their acquisition costs are dramatically lower. They're greater than 30% lower than in the last two years and the prior six years. That's really through the strength of the brand and internal channels growing over time. They'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've doubled those customer accounts in the last year. They have prudently allocated capital to invest in the growth. They're really just focused on replicating those success factors in the U.K., which are really around customer service, fair pricing, innovative products, that same efficiency and cost to serve.
You can see just the dynamics in those markets in terms of switch rates, smart meter penetration, size of market through 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 pumps, EVs and chargers, solar and batteries, and smart meters.
And really, the customer lifetime value comprises the margin on the businesses themselves, the equipment, the 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.
They've invested, as Tony said earlier, in a technology and installation network to address that opportunity. When it comes to EVs and chargers, they've been in this market for a while. They're 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 translating to 1.5 gigawatts that they're managing under their equivalent of the VPP. 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 by, if you thought about those three bars or the four bars on the right-hand side, core business is energy supply.
The energy services would be that sort of margin, installation, and that aftercare, if you want 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 to talk 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, and then water, wastewater, and broadband, and really highlights the customer account growth.
The difference between contracted and live, very clearly, is live is 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 at the upper end. The investment in services will mean that the Octopus Energy EBITDA will be less than GBP 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 dealing with grid 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.
Thank you. If you wish to ask a question, please press star one on your telephone and wait for your name to be announced. If you wish to cancel your request, please press star two. And 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. Tony and the board team. So today's results, you can see that the balance sheet remains in good shape. You've beaten 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 you can see that over the last 6-12 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 to 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 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 two to four hours will continue to exercise our minds. But I think you should expect this is the investment expectation for batteries. We gave guidance for returns on batteries. I think the last results announcement, I'm going to get this, I think 8%-11%, but any messiness would skew that to the upside. I think if you observe 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 six 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 APLNG, 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, I think it was, or something like that overall. And therefore, anything beyond that in our portfolio, and might just check if Tony's 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 and on the premise that really that Yanco Delta, depending on timing and how that process plays out, is largely off balance sheet except for the early stage development. 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?
No, I'll just sort of highlight that I think CapEx for the battery spends is about AUD 950 million this year. We'd sort of expect that to tail off in 2026 to be around sort of maybe half of that. Frank highlighted maybe some other things that we might be thinking about, but stay-in-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's 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 that.
Thanks, Tony. Thanks, Frank. That's helpful. And just on APLNG, just recognizing the changes to guidance that came out of the 31 Jan 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 that more development work is required and that the optimization work that you've been doing is at 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 Origin over the next few years?
Yeah, 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 cargoes, 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 would be a little further color on the four and how to think about that. And we can open up on the cargo bit as well.
Yeah, so building on Frank's comments there, so the AUD 4 a gigajoule 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 C2P this financial year. So we'll ramp up those activities to try and manage that decline as best we can. I think then on the, 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'll be no immediate ramp-up in development drilling.
But 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 require some investment in processing capacity. We'll restart our exploration program next year. And so really those are sort of medium-term decisions, which it's going to be the joint venture decision to make. And 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 cargoes, anything further? Yeah, just to joint venture.
Yeah, 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. 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'll be at the back end of the contract.
That makes sense. Thanks, Andrew. Thanks, Frank.
Did you want? Okay. Got it.
Thank you. Your next question comes from James Byrne from Citi. Please go ahead.
Morning, team. 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 one to two calendar years of a rather tight LNG market. And if they're lifting those cargoes effectively for free, treating that prior cost as sunk, if I was that customer, rationally, I'm going to be calling as many cargoes as I can. So is there a limit there on the phasing of that? Because it could be quite a material hit to earnings.
Yeah, I can pick that one up. So you can think about it as a normal, like a typical commercial agreement where, in particular, they 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 unilateral 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. Obviously, there's an NPV optimal outcome on CapEx and production, right? But if some of these opportunities like Reedy Creek are 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?
Yeah, 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 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, which the joint venture needs to make on drilling and infrastructure.
As far as if you 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 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 that 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 we're going to be ramping up.
We have been successful in offsetting a lot of that decline the last few years. This year hasn't been as successful in Condabri, Talinga, Orana. Really, there's a couple of drivers we've called out for that. One is these unplanned outages and turndown that's come, that's slowed us down from the ability to actually execute those activities and drop those flowing bottom hole pressures. Then, as that part of the field has moved, transitioned from facility constrained to field constrained, we're learning more about the extent of the optimization required. 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 Markets guidance unchanged despite a strong first half, and you've described yourself feeling good about Energy Markets. I mean, if summer's behind us now, right, that big risky period, you seem to have gotten through those AEMO challenges really well. What's that actually portend for second half and beyond if you're not lifting the bottom end of that guidance despite feeling good?
Oh, just look, we're more comfortable with it. There's nothing out there. That's why I was giving you that. 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 of 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. So there's nothing we're worried on.
Yeah. 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 it at the moment.
Good stuff. Thanks, Team. Appreciate it.
Thanks.
Thank you. Your next question comes from Gordon Ramsay from RBC Capital Markets. Please go ahead.
Thank you very much. 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 three to four 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 hand. Does it mean less spot LNG sales?
Yeah, 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 gas. And we think about LNG spot, given our mandatory code requirements, we think about that as the swing customer. So yeah, that's how you would think about it. If there's an extra, say, one cargo or two cargoes going to that customer, that would be two less spot cargoes, all other things being equal.
Okay. And secondly, just on the retail side of your business, yesterday we heard about squeezed margins, 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's handling that?
Yeah, I might get Jon to make some comments. So, Jon Briskin here, who runs our retail business.
Yeah, 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 sort of look at, our weighted average discount has really not changed particularly. It's perhaps a 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 sort of prior period costs.
Excellent. Thank you.
Thank you. Your next question comes from Dale Koenders from Barrenjoey. Please go ahead.
Morning, 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 AUD 45 million in the waterfall sort of as a one-off hit or bigger? And how long will that run for?
Yeah, so just give a sense for it. 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 their 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've 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 allocators of capital, a decent return on that effective cost and investment, maybe ramping up in a year or two?
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've 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 early days. And therefore, we're going to see it play out. And I'm sure they'll continue to respond to the market and what they need to do to succeed and make calls along the way.
Okay. And then a second question for Tony. Just on the dividend outlook, we've only had a very brief history of executing on new dividend policy and briefly with yourself. Prior CFO had flagged sort of FY2024 dividend levels 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?
Yeah. So when we came out with the new dividend policy, we really took away, I guess, the cap on the paying of 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. 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's considered the interim dividend, the first half, we're looking through the CapEx spend. We're looking at the outlook for the two businesses.
We just consider that when you look through those, even though 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, we sort of see this as more than sustainable.
Okay. Thank you.
Thank you. Your next question comes from Nik Burns from Jarden Australia. Please go ahead.
Yes. Hi, everyone. 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. Thank you.
Yeah. Thanks for the question. So in terms of so maybe starting point, of course, all unconventional wells are on decline after an 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, you're still getting good production flows and as stable production flows as you can. And so what we haven't so as I said earlier, 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? 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 impact on the overall reservoir or how we're feeling about it, no fundamental change in how we view the resource.
While 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 2025 into 2026 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. Thanks for that. My understanding is a reasonable proportion of coal seam gas reserves is based on really drawing down the bottom hole 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 hole pressure down to the level that you feel is necessary to extract all of these reserves?
Yeah, you're exactly right. The key to extracting all of 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'll be some kind of additional compression required. There are different technical solutions to do it. You can have wellhead compression. You can have nodal compression.
You can adjust the existing GPFs that we have. We will consider all of those alternatives, and something will 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'll certainly be continuing the work that we have done at a faster rate.
That's very helpful. Thank you very much.
There's been a few questions about APLNG appropriately, 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 only because I heard that there, we should just be clear about that. The earnings recognition won't change.
It'll 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 as people were starting to think about volumes and what's happening as a result of 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 to be sold domestically and under contract, we will have those volumes available as well. So I just would want to make sure people are all linked to that between production versus sales versus what's available and how we might be thinking about volumes overall.
Thank you. Your next question comes from Ian Myles from Macquarie Research. Please go ahead.
Good morning, guys. Maybe just start at a macro level. You reiterated that long run or the medium-term guidance of Energy Markets at sort of $25-$40 a megawatt hour. You're sort of sitting at the upper end of that range. The other question sort of emerges 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 35-37 terawatt hours per annum for the last five or six years.
Yeah. Thanks, Ian.
Yeah. So firstly, Ian, Tony here. I'll 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 that we'll be probably where you get an overlap of those two things will probably be towards the upper end of that range. And then any additional investments that we made would then perhaps drift us to the top of that. So 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.
Yeah. That's good, but what about the volume? Because the other half of that is volume, which isn't really moving.
Yeah. So I'm just about to address that. Thanks.
Oh, sorry.
So on volume, 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 that AEMO is forecasting, while a reasonable chunk, 15%-16% comes 2030, a lot of that load growth in terms of electrification, perhaps data centers. I know they've got hydrogen in 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 in the not a lot yet in coming at the residential level. You're seeing some uplift with EVs, etc. But that's still, I think, forecast to be stronger uplift in the future. So a lot of it's coming at the C&I market. We'll still compete heavily at that.
We're having quite sort of, I'd say, deep discussions with data center developers, etc., to compete in that market. So we're hopeful that some of that volume then starts to flow in the medium term.
Okay. Just a specific one. On your cost saves, AUD 100-150 million per annum, is that inclusive or exclusive of the licensing fee you now have to pay to Kraken?
No. That's inclusive of the licensing fee.
So the underlying savings are probably going to be 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 have you actually locked in of that 100 and 150?
I don't really want to sort of guide. I think we would say that we'll see a reasonable sort of reduction in FY 2025. I'd say maybe we do a third of that number in FY 2025, perhaps. But programs have been in place that'll see that we're pretty confident on that reduction into 2026.
Okay. Just on Octopus Energy Services, last year, that business at 100% owned lost sort of GBP 50 million. Based on your slides, it would probably imply the business is losing close to probably GBP 200 million this year. And I was just sort of trying to get my mind around, is the large losses reflecting the cost of installation and getting people on smart meters, EVs, heat pumps, etc., and that the profitability will come as all of this is installed and we move to more of a service orientation like gas-fired heat pumps or gas boilers are done?
Yeah. So Ian, 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 as probably the key driver. When you think about the EV business and even the smart meter business and so forth, I would the EV business 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.
Okay, 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?
Yeah. I don't. Thames Water.
I don't think we'd speculate. I know there's a little bit of press around it.
Yeah. The comment I'd 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 a 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 two 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 two engines that are driving that. It'll 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.
Okay. And one final question. You mentioned in Energy Markets, gas, the importance of gas, two elements to this. Firstly, you flagged previously, I'm not sure exactly when, looking for new gas sites and positionings. I'm interested in how that's progressed in developing those sites and the likes. And secondly is lots of hype around batteries and the profitability of batteries. What is the corresponding offset to the profitability of gas plants if batteries are far more active in the two to three hours every evening?
I might get Greg to talk about portfolio. That's okay, and I'm happy to open up.
Sure. Firstly, on gas sites, Ian, 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. I think just broadly, longer term, if you really want to take out more coal, and Frank's alluded to it many times, we really do need more of that mid-merit gas-fired power stations, so we're getting ready for that. We've got the Mortlake site in Victoria. We've got a new site in New South Wales. We've got Darling Downs in Queensland, so we've got three pretty good sites we're looking at. Yeah. Just as batteries, I mean, you can see the volatility. We've just got renewables coming in all the time. You'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 really got to be careful about just running your gas-fired power station and having a start cost just to meet one hour's volatility. Batteries actually do a better job of that. So they're very complementary. And quite frankly, if I think forward even further, ultimately, coal will come out of this market. It's base load. Base load is a very hot 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 that's where we are at the moment.
I think, Ian, probably the other thing to think about is when you look at sort of 2040 and AEMO's sort of forecasts, they would say we need six, seven gigawatts more of gas. They would have sort of, I guess, a total of about sort of 45 gigawatts of firming that has to come into the market to meet that low 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's highlighted, and the OCGTs as complementary with the batteries dealing with the more frequent, shorter volatility spikes and moving energy and OCGT running that sort of longer firming.
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?
Yeah. I still think you'll see quite elevated cap prices. I mean, cap prices are what, Greg? AUD 30 a megawatt hour. I still think there'll be demand for longer duration contracting cover in the market. And majority of the revenue recovery for the peakers is absorbed through the contract market and what's recovered in the tariff versus sort of the spot returns. I still think there'll be significant periods of four-plus hours where gas is going to be leaned on, particularly as coal exits and becomes less reliable. So we're not seeing any sort of material decline in that outlook at all.
Okay. Thank you very much.
Thank you. Your next question comes from Rob Koh from Morgan Stanley. Please go ahead.
Good morning. Congratulations on your first-half result. 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 constraints today. Apologies if I missed this. Can you maybe just give some color on which facilities? Is that really CSG processing, or is it RO or gathering? Just some color there, please.
Yeah. I think you're onto it, but I'll get Andrew to describe it swinging.
Yeah. Thanks, Rob. A couple of parts of our field or facility, what we call facility constraints. In Reedy Creek, it's gas processing. That's a function of stronger-than-expected reservoir production and performance. When we talk about an investment required, that would be for additional processing capacity to augment what's there already. In Spring Gully, we're actually water-constrained for the moment. We've got some infrastructure to debottleneck, which over the coming 12 months will be in place. Then we can still do some level of drilling that is planned in Spring Gully. But ultimately, that's expected to be quite close to maximum capacity from a gas perspective for quite a while. The ability to ramp up further than what's currently planned is constrained. They're the two areas of our field that we would say are facility-constrained.
Thanks, Mr. Thornton. Much appreciated. Maybe switching over to Energy Markets and the progress on the cost-to-serve reductions. One of the issues that you 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?
Yeah. G'day, Rob. So 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 a last resort. And in our regulatory requirements, we meet all of the outcomes there. We have started to increase that. We've seen more across sort of November, December period in the AER 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, as I said, a 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 all customers in debt.
Okay. Great. Thank you. 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 account 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?
Yeah, 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. We look at comparisons to its nearest competitors and across the industry average. And yes, no, it's certainly holding that cost-to-serve advantage.
Okay. Great. Yeah. Thanks for clarifying that. That's very helpful. Sorry. One more question about Octopus. So obviously, the big growth push into energy services is one of the projects ongoing. Actually, this is a two-part question. So firstly, is energy services covered by the Origin NEM exclusivity deal? i.e., can Origin bring any learnings from that into the NEM? And then also, that business, I guess I've conceptually been thinking of it a little bit like your community energy service business in that it's a little bit infrastructure-like in how it operates. Is that fair?
Correct, so 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 those assets but 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 SolarQuotes 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 that 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.
Yeah. Okay. That's great. And just as a final comment, congrats on the SolarQuotes deal. And I hope that you're looking after Mr. Peacock. Thanks very much.
Thank you. Your next question comes from Henry Meyer from Goldman Sachs. Please go ahead.
Morning, all. Thanks for the update, and perhaps a final question on APLNG. Just understanding that the JV will need to approve plans for all the accelerated drilling activity, maybe more investment in capacity and compression. It seems the decline in CSG has been fairly recent. So could you share how far progressed an 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?
Yeah. Hi, Henry. So the work program and budgets for APLNG are approved a year ahead. And so we're going through that process over the coming months for FY2026. 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 the existing well and infrastructure fleet with then 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. Thanks, Andrew. And within Energy Markets, we're looking at the current year gas margin remaining within the $3-$4 targets, but also highlighting 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. Yeah. So yeah, the decrease we saw in the gas gross profit this year, as we highlighted at the full year in 2024, was those prices coming down and flowing through into the business and large sort of C&I customers. And then we also had some sort of trading deals. GLNG rolls off in 2026, as Frank said. So we expect some uplift because that was signed at sort of lower prices. I think that in the balance of the portfolio, we'll have normal-type escalation on some of the fixed-price contracts. And then we've also had to do some recontracting of some APLNG 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.
Great. Okay. Thank you.
Henry, just 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 venture's aligned. They're moving. The whole scaling of that is underway. And the planning for 2026 is underway. And clearly, the WP&B would then consider the activities that might flow through to drilling over the next two years, if that makes sense, or whatever the lag time might be. So I'm just flagging to you if I wouldn't want to leave you with the impression that we're not ramping that activity now, the optimization activity.
Yeah. Perfect. Got it. Thanks, Frank.
Thank you. That does conclude our time for questions. I'll now hand back to Mr. Calabria for closing remarks.
Yeah, 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 advantage portfolio. It is difficult to replicate, and we are investing further and positioning ourselves for the transition. Feel like we really have the momentum now, having gone through the Kraken implementation and 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. And clearly, the global growth opportunity for Octopus.
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. Thanks. Bye.