Origin Energy Ltd Ord

Okay, good morning, everyone. It's Frank Calabria here, and welcome to the Origin half-year results presentation. I'm joined here today by the executive leadership team of Origin, and the format this morning will be consistent with prior reporting periods. You'll hear from both me and Laurie Tremayne, and then very happy to open up to questions for the team and myself. Just turning to the presentation, therefore, going to slide four, and so our key messages for this half-year result. Firstly, consistent with the release that we sent out this morning, just to let you know that the consortium has substantially completed due diligence and active engagement continues in relation to the submission of a binding proposal, and we will continue to keep shareholders updated, and it's contained in the release, what we sent out today. Origin is well-placed to capture value from the energy transition, and so in this presentation, we've given information as to how We think a bit about that and it sits across three aspects. It's through a combination of an advantage portfolio. We are positioned for growth through a number of businesses and further, we represent a platform for transition investment and we set out some of that on the following slide. We continue to execute our strategy and we have a clear ambition and strategy that we're executing at pace. You would have noticed that we two weeks ago upgraded our guidance for energy markets for the financial year 23. And our medium term earnings recovery is on track and we'll go through that today. And even since the upgrading of that guidance, we've continued to see a strengthening and an improvement in operating and trading conditions, including performance here and with Octopus. And we now expect to be at the high end range of our guidance. No doubt you'll be reflecting on that because when you think about the first half results and the second half, it is clearly a tale of two halves and reflects, I think, the events we saw at the end of the last financial year playing through in the first quarter and what we've seen since then is a continuing momentum and recovery that we'll talk through. APLNG continues to generate strong cash flow, which is evident in the presentation. And we will make some comments today about policy Just really the key message from us is that it must support investments if we're to successfully deliver a sustainable transition over time in Australia. I did mention on slide five, I did mention that origins were placed to capture value through the transition. When we talk about an advantage portfolio, it really centres across the fact that we have a large scale and capable retail business. We have a competitive gas supply business. And we also have the largest thermal peaking fleet, all of which are key facets that you would want to have in your portfolio as we go through a transition that requires renewables and storage to be entered into the portfolio as coal exits the market. And not the least of which also is that we have a high quality, low cost APL&G gas resource. And you can see the benefits of the diversification across the two businesses in the half year results again. By position for growth, I really talk about the opportunities we see across businesses, firstly in terms of Octopus, and we'll talk about its ascendancy in the retail market in the UK, but also its global utility software business through multi-product offerings, Broadband EV and Origin Loop, our virtual power plant, and through our growth businesses in Xero and Community Energy Services. We've distinguished those growth businesses from the platform for transition investment, Because the combination of that retail scale, firming generation, gas supply and the upcoming Arara enclosure provides a large scale opportunity, which I think has been identified by the consortium that have approached us as an opportunity to invest in renewables and storage and also distributed energy assets, I should add, to accelerate the transition. And then as we consider further opportunities that exist in the transition, there's also the carbon products through carbon markets as they evolve. and then hydrogen developments. Turning to the financial highlights, you can see that the statutory profits up $530 million to $399 million through favourable derivative valuation and impairments in prior periods not occurring this year. But you can see the underlying profit is down and it really is the reflection of a mixed result in terms of the energy markets earnings being down. We've got strong results still continuing to occur in APL&G But what we have this year is the tax on those distributions, which has flowed through to the underlying profit result. And you can see that's down to $44 million. Underlying EBITDA overall is just slightly below last year, the equivalent period, equivalent half last year, at $1.05 billion. And you can see the combination of the two businesses reflected in the underlying return on capital employed. You've got integrated gases return on capital employed, and we should say for this, obviously, over this period of time at 19.8%, I'm sure you'll all reflect that that's been a cyclical business over time, depending on commodity cycles. But it's experiencing strength through the commodity markets at the moment. But you'll also notice that the energy markets return on capital point is negative. And so when we're talking about the recovery, the growth in earnings that we're seeing, partly what we're talking about here is a recovery in the energy markets earnings back to run rates that we've seen previously. Our adjusted net debt is up by 0.4 billion to 3.3 billion, and Laurie will take you through the cash flow. And I'm pleased to say that the board has declared a fully franked interim dividend of 16.5 cents per share. We have a clear ambition and strategy on slide seven. The ambition is to lead the energy transition through cleaner energy and customer solutions, and we have three strategic pillars that we remain very focused on. Unrivaled customer solutions, accelerating renewables and cleaner energy, and also critically important is delivering reliable energy through the transition. I've just included that slide to remind you of that framework because as we turn to the next slide, we're really just highlighting some of the key achievements to date on executing our strategy. And what you can see there is in terms of some of the key achievements, we now have 96% of our customers on the Kraken platform. We were pushing hard to get 100%, but we're 96% through and we'll complete that over the coming half. Octopus is now the number two UK energy retailer following the successful acquisition of Bulb. which is quite an achievement for a business that was only established in the middle of last decade. The CES gross profit is up to $70 million on the back of organic growth, and in particular this half, the acquisition of Wynn. And Origin Zero continues to actually offer low-carbon and other non-commodity solutions to large business customers, and we're gaining good momentum. We're very well advanced on the Araring battery. We're in... quite advanced negotiations with the selected contractors underway as we approach the FID decision, which will be very soon, we expect. We've got virtual power plant connections that have grown by 75% in the last six months on our way to two gigs. We now have 450 megawatts and that's continued to grow. And I have to say we've made good progress in relation to the Hunter Valley hydrogen opportunity, a domestic hydrogen, not green, a hydrogen opportunity. over the course of the last six months. In terms of APLNG, it's been another very strong half-year cash distribution at $783 million. Compared to the last time we held one of these coals, I'm pleased to say that both coal delivery and stockpiles have recovered at Araring, and we now have over a million tonnes on the stockpile. And we've experienced wet weather in APLNG, which has impacted production, and we'll talk through the recovery of that underway And in relation to our upstream exploration and appraisal business, the Beetle is sale is completed and we have just very recently signed the canning sale agreements. So we've achieved quite a bit today. We haven't achieved everything we set out to, but very pleased that we continue to execute our strategy at pace. Now I'm sure For all the analysts out there, they've got rulers out. And the whole idea was not to have rulers out on this, but really to provide an earnings-targeted trajectory over time, but really to demonstrate the various parts of Origin so you can see how we think about this business over the coming years and both the sources of that growth and the value drivers. In particular, you'll see it's done by FY24, so it doesn't show the FY23 results. But what you can see there is a recovery as Araring makes a positive contribution on the back of a tariff reset over a period of time. And what really will occur over time as Araring comes out of the fleet is that the wholesale electricity returns will be dominated until we introduce more growth in renewables and storage by the returns we will see in the capacity market through our thermal peaking generation also through our legacy renewable assets and also through our ability in the market to continue to capture value in what will increasingly have intraday spreads and volatility. What you will then see over time is that that will be supplemented by a growth in renewables and storage as we introduce the new wave of assets to the portfolio. In this case, clearly reflecting the fact that we would partner with others in terms of the capital that was introduced. And we would continue to see that as a growth engine. And that's what we really, one of the key areas we described as that platform for investment through the transition. We have stable and long-term earnings from our strategic gas position, which is really a combination of legacy coal contracts and as well as capabilities, transport and a portfolio and an ability to manage that. And we also have a scale, low cost retail business, which will continue to deliver a stable margin before we think of the additional products it's added to and the benefits you'll see that will accrue as a result of the implementation of Kraken, which flow from next year. And then you'll see the two areas of growth, which are really the growth businesses we described earlier, but that is really presented to us by the customer scale that we have in the business and the capabilities. And that really extends across our community energy services, virtual power plant and broadband. And then the growth that will emerge and is emerging from Octopus as a retailer in the UK and as a customer licensed growth business or a software business that's scaling up across the globe. And in addition to that, they're increasingly investing in the transition as their market goes through a similar trend as we go through there. So we really wanted to provide that to demonstrate, I think, to you how we see the earnings contributors and that trajectory that's targeted based on our strategy execution and the near-term recovery in earnings, particularly in the wholesale electricity markets. We continue to be a purpose-led organization. It's a slide you would see us. We're serious about it. We need to get energy right for our customers, communities, planet, and our people. And you can see there are a number of the achievements that are sitting across that over the last six months. I would only highlight a couple of those points. For customers, we continue to support our power on hardship customers and important right now in terms of rising prices. The communities in which we operate, it's the growing role and contribution played by regional indigenous suppliers. The great work of the Origin Foundation in education and the community investment and engagement in Arari that stand out over the last period of time. We were very pleased in the terms of Planet to have received 94.5% shareholder support to our climate transition action plan and you can see there across a range of the products and initiatives that we continue to make progress. So we have strong targets, we've got action and we've got progress. And for our people, we've seen improvement in safety performance, but we never rest, as you would expect, organisations wherever there are people that are still continuing to experience injuries and incidents, and so we will continue to focus on that. We've increased the proportion of our female senior leaders, and we're actively supporting our people at Araring through the transition. Finally, before I pass over to Laurie, I think it's important to note that we must have policies that support investment. And we made comments six months ago, and I think there are some clear messages that need to be, I think, made if we're to actually succeed on accelerating the transition. There is substantial investment required to underpin the new energy system, and I don't think that's any mystery. That's right across generation, transmission, it's renewables, but also gas supply. And investors will require stable policy and adequate returns reflecting the risk profile to have that investment made. There is investment in new gas supply required urgently and government and regulatory interventions that create uncertainty don't act in that investment being made on a timely basis and therefore that's very important. It's good progress to see the capacity mechanism that was introduced and I think it was very pleasing to see that progress There is further work required because that capacity mechanism did not include either the orderly transition of coal and also the investment in new gas-fired generation. And alongside storage and other assets will be required for a successful transition, particularly as we know the scale of what's required is significant and time is of the essence. And lastly, should never forget the fact that we are supporting bill relief for customers that are most in need. We are well aware that prices are rising for our customers and will continue to play our part. And that remains a key aspect alongside the regulatory and policy arrangements that continue to be worked across the industry. So on that note, I'm going to pass over to Laurie and then we'll return to talk more deeply about some of the operational performance.

Thanks, Frank, and good morning, everyone. I'm going to start with profit bridge on slide 13. So underlying profit was down $224 million to $44 million, due mainly to lower electricity gross profit and income tax on unfranked APLNG dividends, partially offset by stronger prices lifting APLNG earnings. Earnings from the non-APLNG part of our upstream business is $70 million lower due to higher oil hedge losses partially offset by a stronger commercial position in our LNG trading business and lower exploration and appraisal spending following our decision to exit our non-APLNG acreage. DNA expense is higher with the expected reduction in operating life at Araring. Moving to slide 14. The extremely high commodity prices at the end of the last financial year had significant impacts on our full year results, which have partially unwound in this half year. I'll talk more about this later, but higher fuel and pool costs further squeeze margin in our electricity business. The $2.9 billion of net in the money derivatives held on the balance sheet last year end have revalued lower and partially settled resulting in a large net asset reduction on the balance sheet and fair value movements in statutory earnings and hedge reserves. Very high pool prices in June 22 resulted in a large net creditor position with AEMO. This arises as we are short generation and therefore a net buyer from the pool. This net creditor was repaid in the first half, resulting in a large working capital movement and lower operating cash flow, which I'll quantify later. In addition, our coal stockpile was rebuilt at high market prices following a period of poor operating and delivery performance from a key supplier. Octopus energy earnings have also been impacted in the half by high and volatile wholesale prices and regulatory intervention. I'll cover this in more detail later. So the cash flow on slide 15 dimensions some of these outcomes. lower cash earnings and $757 million of higher working capital. For the reasons I've just explained, higher tax paid, partially offset by a further inflow of future exchange collateral, have resulted in a net operating cash outflow of $786 million. Higher distributions from APLNG and lower investment spend and net interest contributed to free cash flow. With higher expected cash earnings, more stable working capital and ongoing strong distributions from APLNG, we anticipate an improved free cash flow result in the second half. I'll drill into energy markets cash conversion in more detail on the next slide, 16. This chart shows energy markets EBITDA, that's the black line plotted against cash flows. The operating cash flow in red approximates EBITDA in all periods except for the last two. This is a function of the high commodity prices particularly at June 22. The chart shows how the low operating cash in the first half of 23 unwinds the strong cash conversion in the second half of last year. Last year's result also benefited from high futures exchange collateral inflows shown here in yellow. In blue you can see the $65 per certificate shortfall charge we've paid for the under delivery of LGCs. We'll make a further shortfall payment of approximately 200 million in the second half, but then expect refunds net of the cost of Ford certificate purchases of around 420 million across financial years 2024 to 2026. In the second half, we expect to see a rebound in energy markets earnings and positive operating cash flows. that rebound in cash flow should see us get back to more like our long trend in cash conversion. Turning next to APLNG on slide 18. Now we all know LNG is a cyclical business and we invest expecting to earn better than our cost and capital across these cycles. Without full participation across the cycle, Investment in these capital-intensive, long-dated projects would not be economic. As many on the call would recognise, there have been years where this business hasn't returned our cost of capital. We're currently at a strong point in the cycle, benefiting from higher global oil and LNG prices. We're also benefiting from good field performance, enabling us to defer development expenditure. These benefits combined to deliver origin a half year distribution of 783 million and a return on capital employed of over 19%. The cash generation performance of APLNG in the half was outstanding. On a 100% basis, $3.9 billion of cash was generated from operations after paying Queensland royalties of almost 400 million. Investment spend was only 200 million and debt servicing just over $500 million, allowing total distributions of an impressive $2.8 billion for the half. On slide 19, based on an expected improvement in earnings and cash generation, and given our debt remains towards the lower end of our debt to EBITDA range, currently at 2.1 times, the board has declared an interim dividend of 16.5 cents per share, consistent with last year's final dividend. This dividend, as Frank said, will be fully franked and the DRP will remain suspended. We're not in a position to contemplate further capital management initiatives just now, but this remains a consideration for the board. Turning next to energy markets earnings on slide 19. Energy markets EBITDA was 120 million lower in the half compared to the first half last year. Electricity gross profit was 183 million lower. Octopus earnings, 71 million lower. And these were partially offset by 145 million recovery in gas gross profit. The electricity result represents a $10.80 per megawatt hour reduction in unit margins down to $2.10 per megawatt hour. This reduction is largely a function of the very high fuel and pool purchase prices not being fully reflected in customer tariffs. Unit fuel costs reduced earnings by $341 million and unit pool costs by $193 million. We expect these higher costs will be recovered with future tariff resets, allowing a rebound in electricity margins. In gas, customer tariffs for both mass market and CNI customers have repriced to recover higher unit costs, benefiting earnings by 199 million. Offsetting this, increased gas procurement costs in this period decreased earnings by 102 million. Business customer wins have driven a net increase in sales volume of 12.2 petajoules, providing a 32 million positive earnings impact. Octopus earnings were substantially lower in the half particularly in the October to December period. Our equity account at EBITDA result for the half was a loss of 83 million. Now, there were two factors driving this underperformance. Firstly, a long energy position caused by lower demand, partly due to unseasonably warm October weather, resulted in Octopus selling back excess volumes during a period of materially lower wholesale prices. Secondly, The introduction of the energy price guarantee by the UK government resulted in fixed tariff octopus customers renewing onto a lower cap price set well below the hedged cost. In January to March this year, the price cap is now set and captures the significantly higher wholesale hedging costs observed in the latter part of calendar year 2022. As a result, octopus are forecasting a recovery in earnings in the second half this financial year, and we've already seen positive earnings results from Octopus in January. Lastly, turning to integrated gas on slide 20. Excluding the impact of the equity sell-down, our share of APLNG earnings were up $397 million, primarily due to the higher LNG prices, both oil-linked contract pricing and spots. The realized effective oil price before hedging was US $109 per barrel compared to 68 in the prior year. Operating costs were $157 million higher with higher royalties associated with higher prices representing most of this increase. High purchase of gas, increased work over activity and the commencement of planned cyclical upstream maintenance activities have also contributed. And with all that, I'll hand you back to Frank for our operational performance.

Okay, thanks very much, Laurie. Now we'll turn to the operational review and kicking off with energy markets on slide 23. Given the events that have occurred in the electricity market over the last 18 months and the electricity margin that's been suppressed through that period of time, we've included on that slide really what's occurred in the market for the financial years 22 and the half year 23, and what's then flowing through to our improved outlook. So you can see that in the electricity markets in FY22, the low wholesale electricity prices during COVID, they flowed through to customer tariffs, and that when combined with the coal supply disruption and the extreme market events and conditions in the fourth quarter of that year led to high wholesale prices and therefore compressed margins. As we moved into the first half of financial year 23, the half we've just gone through, the customer tariffs did increase, but still not enough to recover the higher costs incurred. And since then, obviously, cold deliveries have improved as we've gone through the half, and that's where we can see that market conditions have eased. But really, that half year result is still reflecting those higher costs. And so as we look forward to the second half of this financial year and beyond in the 24, we do see the continued recovery in electricity earnings. Wholesale electricity prices have moved lower, including through the impact more recently of the temporary price cap. And then customer tariffs will increase again as the lagged recovery of those higher costs incurred continues to flow through into the next financial year. I should say that the implementation and the impact of the recent coal price cap is still being worked through, and there are a number of arrangements that we and other industry participants are actively in dialogue with the New South Wales government right now. What flows on the next slide is really just an analytical representation of some of the comments I've just made there. Firstly, on the left-hand side chart, you will see the... the short-run marginal cost of ARARing compared to what is recovered through customer tariffs, the default market offer or the default market offer. So that's what's most recently resulted in the negative margins. And when tariffs reset on the 1st of July, we expect this to move to a positive contribution and for that to strengthen over time. The middle chart shows the trend of electricity forward prices in the swaps. and the average of which feeds into those customer tariffs. And so that's the relevance of including that. And you can see the rising forward price from, it started in April, but more likely May that will feed in from May through to December that will flow through to those tariffs. It also highlights the drop that's more recently occurred as a result of the caps coming in. And the chart on the right really highlights the improved delivery of coal and also the coal stockpile increase over the period. Just turning to gas, the overarching message is there's a strong gas outlook. Based on the fact that we've largely locked in the cost of supplies we go in over the next couple of years, and tariffs are repricing to reflect those costs that have been locked in. And when you look at the left-hand side chart, it really does highlight the sales volumes to business customers we've grown share in that market as we've won them over the course of the period. Origin is almost entirely contracted to business customers for their FY23 prior to the introduction of the $12 a gigajoule cap and so therefore it's not having a material impact in this financial year and you can see therefore the on the middle chart just how contracted volumes have evolved since 30 June through to the end of December. We continue to offer contracts to our business customers, either fixed price or spot-based. We did that through the period. A fraction of our CNI gas volume is on default pricing as it traditionally has been. We've ensured that customers during the recent renewal window have been offered alternatives to this It's only those that have not responded to that that might be sitting on default. But otherwise, we have worked very hard to bring everyone on to either fixed price contracts or those that follow the underlying spot market. Our supply is made up, on the right-hand chart, is made up of a mix of fixed price, price review and JKM and oil-linked contracts. The JKM exposure is fully hedged through to FY23 and FY24. and substantially or very primarily largely hedged in FY25 as well so we've got into that period and as you many of you all know we've got a price review on beach supply contract that occurs on the 1st of July 23 so it plays out for the 24 year and that process is underway at the moment I'll now turn to retail and you can see the retail market environment that really Firstly, as it relates to churn, you can see that spike that occurred around the times of those wholesale market events and also the communication of the tariffs at the time led to a lot of people seeking new offers. What's happened then is that the market has remained elevated over a period of time of that six months. And in the case of Origin, except for that really, that one event around the July period has largely churned, remained flat for the balance of the six months. and overall our churn in the market is about 13.2%. What you can see on the next chart is really, we talk about the value management that we've undertaken through personalization and segmentation that has delivered a good benefit in this first half. You should think about that as a combination of lower discounts that are emerging, plus our ability to continue to use data and analytics to then segment and focus on the customer value and the propositions we make to them, and also moving customers off non-profitable products through the period. You can see that that discount is really a reflection of those market conditions as well, as the wholesale prices are high. It's no surprise that across the market, retailers therefore reduce those discounts. And just to highlight the extent of those market events that you see, we've had seven retailer of last resort events since May this year. That seems to have calmed down more recently, but that's occurred. And then, so in addition to continuing to create value, we've also had customer accounts grow as our multi-product strategy continues to be executed and we continue to evolve our offerings and the products and we continue to grow that and pleasing to see the 4.7 star rating on Trustpilot. In terms of those growth businesses earlier, you can see then on slide 27, the growth in community energy services. We will get a full year earnings contribution from WinConnect this year and combined with the underlying organic growth, you can see that businesses continue to grow. We're number one in the market and can see good profile for contracts that are going to evolve over time that flow through to results. In the case of broadband, we continue to grow our customers up to 74,000. and pleasingly received the CanStar Blue Award. That growth really, we really are seeing the product resonate in the market. I think the key thing for us has really been balancing how much of our focus goes onto that product while we've been moving through the implementation of all of the RetailX program. So it's really around settling that business down and we feel very positive towards what we can achieve over time. As I said earlier, very pleased to see the growth in the megawatts that are in our virtual power plant. And we've added, I think, just under about 190 megawatts and 90 or so of those megawatts have come through our origin zero business. So we can see that cross both consumer and business segments. RetailX did talk about, just on slide 28, talked about it. We're now 96% customers accounts on that 3.4 million. We're in the toughest time of these projects. We've got the last cohorts coming in now. We're stabilizing operations. We've been pleased with the way the program has been undertaken. You can see that through the customer happiness index and employee happiness index that we are gaining confidence in the operating model, but we're in that time where we're stabilizing, settling down, and as you can imagine, trying to wind down the balance of the business and achieve that well as we land the plane of the new RetailX being built. We remain on track for our targeted savings in FY24 against the 2018 baseline of $200 million to $250 million cash cost savings. We will see some higher cost to serve this year, but that will be then followed quickly by the savings that we set out in the FY24. In terms of Octopus, Laurie did talk about this earlier, but just highlights what's happened in the UK market as it entered into this period. They've got the same circumstance that as higher wholesale costs are incurred they've got a lag where they recover it in the UK though that's now moved to a quarterly basis but really what that yellow line highlights is just where wholesale costs did go in the commencement of the last quarter uh and that's now being recovered through the tariffs in the January to in the January tariffs in the market so we are seeing strong recovery in the octopus earnings even in January and uh The other key aspect that they continue to manage is that it was very unseasonally warm in October, which meant that they sold some length of their position back into a lower spot price market. But we've got the bold acquisition coming in in the second half. We've got the recovery through those tariffs and it all looks like that recovery is well and truly on track based on January. It continues to be a very impressive growth story for Octopus and now following Bold. You can see they're the second largest energy retailer by customer accounts. They continue to lead the market on both customer experience and cost to serve and are well-placed to be able to grow their margin as the UK, really, the customer growth strategy is now completed. So they've now got themselves in a market position where they can be really running that business for cash. The growing licensed business, 25 million customers now contracted on to the Kraken platform, a very strong growth pipeline. It's now expanding into utilities such as water and broadband and clearly the migration. You can see where that is relative to the contracted customer base. And they have in their version of the VPP now got 4.6 gigawatts of assets contracted. Are they largely with third parties? They've got a 1.2 gigawatts online. And you should think about intelligent octopuses, the equivalent activity that we're doing with our origin loop in that it's really on our own customer base. And in their case, they're a much bigger market for electric vehicles. And as a result, it's nearly all through that asset category that they've got their 140 megawatts. Ours is spread across really a variety of devices that are in the home or in businesses where there's a large energy load. So they're seeing some very big increases occur in that business as well. And then now they've established themselves as one of the largest specialist EV leasing businesses in the UK. Just turning to integrated gas, the story really is that those record high commodity prices have really led to record high revenue. You can see there that in the half we delivered three spot cargoes, but overwhelmingly the revenue is being driven by the higher oil prices on our export contracts. And we were able to achieve very high production as a result of the downstream nameplate capacity on the LNG. Although, as you know, when it comes to the production, we'll talk about some of the weather impacts that are recovering underway. I think it's important to note that on the next slide that APLNG is a major supplier, has always been to the East Coast domestic market. Since the project's sanctioned, over 1,400 petajoules have been sold to the domestic markets. They've been supplied at average prices that are well below those paid by international customers. And you can see even in the last 12 months, we've paid $800 million in royalties to the Queensland government. And so it continues to play a key role, has always played a key role in the domestic market. The production, which was in our quarterly, won't be a surprise, is the guidance is down because productions and in the half year, it's down 5% against the equivalent half. There's been an unplanned non-operated outage that we obviously received volume from, but probably the key driver has been the cumulative impact of wet weather that occurred really in the early months and that therefore has led to the lag in really sort of upswing in volumes as we've got restricted access and a whole range of activity was stalled over that period of time. We also have up-planned the cyclical maintenance on our gas processing facilities. That goes to, it does have some impact on production and costs. And when you look at our costs, it's really the cyclical activity and now the increased work over activity as we prioritize those that are flowing through. And we've also experienced higher power costs in the business as well. In terms of that production recovery underway, we just wanted to really show to you the impact of waiting on weather, which is really that percentage of time a work over rig has stood down for wet weather on average. And so you can see that that impact over the last couple of years really associated with El Niño has actually had quite an impact on us. We are seeing that improve. We've had drier weather recently that's reduced in November and December. And the recovery is also being driven by the number of online wells. The work over activity really ramped up over the last several months. And we've also got new infrastructure coming online in terms of the Talinga-Kondabrai North Pipeline and soon to have the Orana South Loop Pipeline in the second half. It all adds to our operational flexibility and ability to deliver volumes. What we provided on slide 36 is just a little more detail about where some of that focus is on operational improvements. And in terms of that production optimisation, it really shows just how we target lower well pressures that then flows through to our gas rates and improving those and other things like optimising pump speeds. I think the point there is that there's a continuous program of activity that goes to the improvement of production and that's something that we're very much focused on. And we've also highlighted alongside that the mean time to failure and what we really have, I think, just demonstrated through that chart is the successful strategy in relation to swell packers that have improved well reliability and as they move through more of our stock of wells over time, you'll see an improvement in that alongside other initiatives. And that network infrastructure on the right-hand side is really just a little more detail on what I just described about some of the initiatives that are underway right now. I did touch on the beginning in slide 37, just on the strategic view of the non-APLNG assets. We've completed the sale of Beedaloo. We've executed the agreement in relation to Canning, which is expected to complete in the second half. And you can see in relation to the Cooper Aramanga, five permits will be transferred back to Bridgeport and the remaining 12 permits remain under review and we'll advance that over the coming period. So then just looking at outlook, really we provided updated guidance a couple of weeks ago in January. What has happened since then is the operating and trading performance in energy markets, including octopus, has continued to improve. and therefore the energy market's underlying earnings is now expected to be towards the higher end of that upgraded guidance range that we provided and therefore continues to reinforce the earnings recovery in that business and all of the initiatives underway. Otherwise, the guidance is the same as it was there. I think the only thing that we've added a comment here which supports some of the comments Laurie's made earlier, but the cash flow in the second half, as you would expect, is expected to improve, and it will be on the back of those higher earnings. There will be one thing that offsets against that, which is the old GC shortfall, which is really the renewable certificate shortfall charge, which has been a successful strategy, but clearly has a cash flow impact that gets recovered over time. and there's no material impact expected in relation to the $12 gigajoule cap, and we continue to work through the coal, so none of this guidance includes anything associated with the legislated coal price cap that is being completed. We do anticipate that that earnings growth continues into the next year, not the least of which is that you'll have customer tariffs rising to recover those higher costs, octopus energy growth, and also you'll have those cost savings coming through retail, and we'd expect to continue to see the benefits of a variety of drivers flowing through to 24. The guidance for integrated gas is just the same as what we provided two weeks ago in relation to the production of 660 to 680 petajoules, and really, as a result of that, it's associated with those volumes. The capex and opex range is the same. It flows through to a higher unit Right really on the back of the production. That's the key difference there and Why what we've done in terms of LNG trading guidance as you can see? We've seen the benefits and we did communicate those to you a couple of weeks ago as well So very pleased with the performance of that portfolio So on that note we will we've concluded the presentation and very happy to then open up to questions and And the team here and me are ready for any questions you may have. So thanks very much for listening.

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. If you are on a speakerphone, please pick up the handset to ask your question. Your first question comes from Mark Samter from MST. Please go ahead.

Yeah, morning, guys. A couple of questions, if I can. First, I'm going to try and ask a question on the bid that I'm not sure it's a question you're going to be able to answer, but I'll give it a crack anyway. And obviously not asking you to refer to any specific press that might be around, but should we assume that negotiations are still solely around a bid for the entirety of the company, or is there scenarios where you could see part of the business being sold, for example, just energy markets being sold, or are we purely... whole business conversations.

Mark, just the discussions, they're constructive, they're active, and they're ongoing, and they're focused on the consortium proposal before us.

Okay. Just to double-check just a small technical point on it, the original bid was deducted by dividends, wasn't it? So as of when you go ex-div, you dropped $8.83 and a half or whatever it is as a start.

Yeah, so that's right. It was an effective date, and as a result, dividends would come off over time. Yep.

Yeah, and I guess you're probably not willing to give us a date where you guys think put up and shut up. I'm just conscious that obviously the people in the data room bid for your largest competitor last year. There's probably only a certain amount of time you want them floating around the office indefinitely, but at this stage it is just ongoing and you hope it concludes soon. There's no drop dead date from your guys' perspective.

Look, the conversations continue to be constructive and ongoing. You imagine this is large transactions. The due diligence is substantially complete. And so from our perspective, that's where the transaction stands today. And that's the basis upon which we're engaging with the consortium. So it just continues at this point in time. And we'll see where that lands.

Thanks. And just a quick question for Greg, if I could. Obviously the other side of Origin is one of the largest sellers to the domestic gas market, but you guys are, I'm pretty sure I'm right in saying, the largest buyer of gas in the East Coast market. You're obviously covered for your minimum contracted volumes, but you would like to sell more into it. Greg, do you think it's viable for the industry to strike long-term supply deals from 2024 or beyond at the moment, or do you think it's just paralysis by intervention at this stage? Sorry, Mark.

Yeah, thanks, Mark. Look, it's pretty difficult to get any long-term gas contracts at this point in time. I think from an origin perspective, like you said, we have locked up a lot of gas contracts. What we're particularly focused on right now is, you know, sort of beach, beach's success. We are very interested in seeing thylacine getting connected to the market, which will give us ultimately additional gas supply. And if we get that gas supply, Mark, that's really good for our customers, right? So we can offer that out to the market.

And would the intervention from your guys' perspective have any impact on the price review? Or is it too late to have an impact?

Look, Mark, you know, again, I've got to be careful about talking about, you know, price review. But what I can say is that the conversation thus far is very constructive and mature. So... I'll just say that at this point, but it's going well.

Thank you, guys.

Thank you. The next question is from Tom Allen from UBS. Please go ahead.

Morning, Frank, Laurie and the team. Hoping you can quantify, please, an indicative range of uncertainty in energy market EBITDA that you're assuming for planning purposes, at least, over the next couple of years based on uncertainty arising from current government energy policy and perhaps also comment on the medium to longer term return on capital employed that you think energy markets can reliably sustain?

Yeah so just in relation to just so I've got it so the longer term I get it which is sort of the steady state what you think the run rate for the business should be and the first one was just the impact of the recently announced measures on caps is that the point that you're Is that the point on the first one? That's correct.

But then also for planning purposes, the impact you're assuming that might come from that broader policy package as well. So the mandatory code of conduct as well.

Yeah, sure. So as it relates, and I think you're asking that in energy markets, as it relates at the moment, the coal price that comes, the coal cap, if implemented, would clearly be beneficial relative to the relative to the underlying cost of coal for origin, but that would then also flow through over time to the wholesale electricity market. So I certainly don't see downside associated with the coal. There may be some timing aspects associated with that coal cost coming in and how that flows through to tariffs that could be beneficial, but we're just working through that right now. And as it relates to the The gas price cap, firstly, when you think about the energy markets business, the $12 cap has not had a material impact, but it will now determine, it will now, beyond the cap, it will all be associated with the reasonable pricing and the ability to access that gas, as the previous question just went through. So for planning purposes, we're really focused, I think, in the energy markets business about how the coal cap and ultimate flow through occurs in the businesses. They do link though to the sort of underlying premise of what's the energy markets earnings over time. So you should now at least see graphically that you've got a steady contribution that's occurring through the retail business. The wholesale gas business is reasonably steady return because of the long dated contracts that were in place. And therefore that would be determined by the wholesale gas price ultimately, but that would be the key driver there. In the electricity earnings business, which is the thing you're really focused on. And you could see that we've had a complete compression in the dollars per megawatt hour there. But when you actually look back into the longer term, we do expect that to get back towards that sort of $20 to $30 range. But even if you looked at the lower end of that range on a steady state basis, the composition of that will be quite different. And you're probably observing that really a lot more will, a lot of that, or at least half of that's going to emerge just from the peaking fleet based on our view of long a reasonably conservative view on long-run cap prices, and then you'll have some benefit associated with renewables, VPP, and the ability to manage the shape in the market. We don't anticipate when we say this that we're making large margin out of ARARing because it would be passing through a cost of coal through to a wholesale price. And so we do see that the earnings recovery does get back, and I know that people are You know, we do see that you could put that in and you would therefore see that we'd be back at a return in capital that would be above double digits based on those contributions. I should say that we make those statements before large capital investment for renewables or storage and before probably thinking about the potential, full potential of those growth businesses when we make that statement. So really looking at the underlying retail, wholesale gas, wholesale electricity, and the businesses we have today.

Thanks, Frank. That's clear. Just staying with policy for a moment. Has APL&G's drilling program changed at all due to the uncertainty arising from the proposed mandatory code of conduct and particularly that reasonable price provision legislation?

Look, I'll just pass that to Andrew just based on what's going on right now because I think activity is more driven by wet weather than any policy at this point in time, so... Yeah, that's right. So Andrew here.

So short term, no. We've got a clear work program and budget for the remainder of the fiscal year. It has been about trying to catch up on, in particular, the work overs that we haven't been able to do over the last several months through to wet weather. I think that there's a longer term question, which, as is usual with a joint venture, gets made sort of towards the middle of the year about what the ongoing investment program will be. And we're not up to that stage yet.

Sure. Thanks, Andrew. And can you just confirm I'm interpreting correctly, but with APLNG's Totex unit costs in the range of $3.70 to $4.10 a gigajoule, if the current draft legislation were written into law unchanged and recognising it is only draft legislation, wouldn't that provide little ability for APLNG to offer gas to the domestic market at a price over, say, $6, so the unit cost of production plus a reasonable rate of return?

Well, first thing I'd say is I think there's still quite a bit of uncertainty as to how that would play out. But I don't think that's our understanding that it's a reasonable price per supplier. I think it's a reasonable price for the market. And so I don't think it's about what APL&G's reasonable or marginal cost of production is. I think it's what the next supply source to solve for the market and that cost of supply.

That's helpful. Thanks, Andrew. And then just finally one for Frank or Greg. There was a big drop in electricity customers in New South Wales over the half. Can you just provide some colour on what happened there? And then perhaps just talk to the proportion of your business customers that are on this pool pass-through basis?

I'll just pass you over to John to talk about how that's played out over the half in terms of customer value.

Yeah, no worries, Tom. It's primarily the loss of a... what we would consider a very low value large tender with quite a number of sites in New South Wales. So that is primarily the impact there.

The strategy more broadly you'll see from us over the last period of time has been really to manage in a time where there's been compressed electricity margin and particularly the front end of it, we've been really managing the share and value, and that would have reflected in our retail unit margins over the period as well. Okay, thanks very much.

And then to the question on the percentage of CNI gas volume on default, I'd say very low single digits and meaningful changes over time.

And it's actually, just so that we're clear on that, that has always existed. It's not a feature of the recent events. So it's actually customers that have always either are transferring in or out, or for whatever reason, don't respond to that outbound. So it's not, let's be very clear, it's not as a result of the introduction of the cap. In fact, we've worked extra hard to try and contact them because we think it's in their best interests. Okay, thanks, folks. Thanks, Tom.

Thank you. The next question is from Ian Miles from Macquarie. Please go ahead.

Hi, guys. Just to hop back on coal, can you just maybe give a bit more colour on your infantry? Are you going to lose money on your infantry as a result of the prices dropping now, given the 125 coal cap at your coal infantry that are now 200 bucks a tonne?

Yeah, Ian, thanks. Look, no, we're under no obligation to bid that coal. We can bid that coal at its marginal price, and that's what we're continuing to do. Clearly, with new coal supplies that are coming in today, that is subject to the funding agreement that we're still needing to see final versions of. But, you know, the cost of coal, which is what you're implying, is, you know, we can bid that into the pool as we wish, right? So that's it.

Yeah, but I guess I'm alluding to prices have already responded, haven't they? So if you're bidding in now, you're not going to probably be making much money out of it. You're actually going to probably lose money.

Well, not really, because, you know, we're still seeing volatility in shape in the pool and we'll bid our power station and, you know, Turn it down in the middle of the day where we're seeing very, very low prices and we're certainly not seeing any return on probably any coal in the marketplace because of the renewable solar shape. But in the PM peaks, we are bidding that power station accordingly and getting returns on that coal. So it's a bit dynamic. It's half hourly. Well, it's actually five minutes now. But, you know, still, I think the most important thing for our portfolio is to have a stockpile of coal, which is going to be very important for this winter coming as well.

Okay, and then just, I know it's a bit contentious, but how much notice would you need from government organisations to defer an ARARA enclosure? Sorry. If it was to be deferred. Well, we don't have Snowy coming in any time.

Yeah, and really good question. Sorry, I understand your question now. But look, we are making decisions now on maintenance today. It's imminent. So, you know, we have to make those decisions. These outages take time and we've got to, you know, I think we've got months to work out our next major outage and just how much money we spend on that outage.

I think in advance of 25 you're asking, you'd certainly, I think you'd want to know, you'd certainly want to know, you know, 18 months, two years in advance, yeah, something like that. We certainly, we can respond earlier than that, but, you know, it would be better that everyone understood that in an orderly sense.

Yeah, okay. That's pretty important. And just on that chart, which you gave on page nine, I just want to make sure I'm reading it correctly. Are you suggesting that in FY24, the wholesale electricity business is actually a break-even exercise? That your loss on a raring will be offset by the gains on your caps?

You'll be making margin there, but it'll be still

not fully it would it would be a small margin in that period it just sort of doesn't have anything there so that's why that gray box it's at zero yeah it's um hi and it's lori yes hi lori good day um look you have to think about that chart as being sort of a cartoon it's it's it's deliberately not trying to be accurate um and so you know whether that whether that grey line intersects in the corner is sort of irrelevant. We're using that sort of trending technology so that you're not encouraged to try and look at any particular number.

If you want to know the facts, we will make a contribution in that electricity business next year. And we understand that in the efforts of trying to actually explain that simply, you're looking at that intersecting, it's going to be, there will be a contribution next year.

Okay, I'm not trying to, I'm just trying to make sure that's correct.

It's a good question actually.

The other thing is AGL got a bit of a response from the ACCC for making lots of money out of gas and you guys have made even more money out of gas. I'm just sort of wondering how are you dealing with the ACCC going, are you going to get this like an electricity regulatory response?

Well, we've got the unit gas margin that we've made this year is it was, I think, less than than AGL. I expect I understand that we've got a greater volume of gas we sell in the market. But if you look at the long term history of what we make as a unit margin, this sits in that range of three to four dollars or something like that. There's no doubt that the rising price of gas in the last 12 months has contributed to the rising benefit for that business. And we believe that as gas prices globally, domestically come down, that we will find that we'll be back into that and holding that sort of sustained margin that we have over many years. As to government's reaction to that, I can't predict. I understand and we all understand that the intent behind supporting customers We also, I think, all understand the complexity of the types of interventions having the desired outcomes. I think what we need is we need supply for new gas coming in and we need a market that functions and is available. And to the earlier comment, we need gas supply being made available to retailers and customers going forward. So they're probably the key things. In our business, you can see that intervention and regulatory plays a role. So we always need to be mindful of that. And as a result of that, we worked very hard to support our customers to make sure no one was on default this year and get them onto contracts.

Okay. And one final question on APL&G. The pipeline investments you're making, does that enable you to lift the production rates to a structurally higher level on a go-forward basis? I appreciate you may not have made an actual commitment to it, but have you created the potential to be able to do this now?

We'll talk about how the fields work, Andrew, if that's okay.

Yeah, so I think there's a chart in the slides there that shows some of the pipeline and infrastructure investments we've made. The point of those investments is to connect gas supply to processing ullage, so where we've got existing capacity to process additional gas. When we started and took FID in the project, we tried to guess where we should put the there's more gas than we've got processing capacity. And so what that serves to do, those investments, is at a relatively low cost of supply, accelerate that gas and put it into the existing capacity. So it's a really economically effective way to get some additional production. And in places as well, in particular, I think we mentioned TCNP and the Rana South Loop Line, it also seeks to reduce pressure in the gathering system which reduces pressure back on the wells and so you will see an uplift in production to accelerate our resource into village.

Thank you.

Thank you. The next question is from Peter Wilson from Credit Suisse. Please go ahead.

Thanks. I might just follow that up. So APLG production, we could see it move above the circa 700 PJ range of the last few years, or is that not the intention?

I think the key thing there is that there'll be decisions made by the joint venture each year about what it's investing. I think the point around the infrastructure comment that was made, the question earlier was around that that does enable in the field, more production to come about or to be accelerated. But we do every year, and remember only 27.5%, and we're a joint venture that will need to then decide what capital will be invested into that program over the next year. So that's probably the key drive is about it making the best decisions economically for the market more broadly.

Got it, okay. And then a question on, the coal cap compensation. So you've again declined to include any benefits from that in the guidance due to uncertainty. Can you articulate what exactly is the uncertainty that you see in relation to the compensation piece more so than the potential for new coal contracting and potentially give us a range of outcomes that you expect there?

The real reason we... we've not done anything yet is that simply the funding agreement hasn't yet been completed. I think yesterday there was even further directions orders and that wasn't done until yesterday and nor has the bidding agreements been completed. And so it's really, Peter, as a result of all of those being concluded that then you'd have the confidence on the understanding that that has all been locked down. And once we understand that and also the way minimum and maximum stockpiles and the way we bid and making sure we've got the protection for that through, it's really been that's the reason why we've not. And it's a little different to market because it's actually associated with, let's be clear, legislation and regulation and mechanisms. You want to see those finalised before you conclude. Greg, did you have anything else?

I probably haven't, Frank. All I can say, Peter, is that it's real today. It's probably what my team's mostly focused on. And that's not just our team, the government and other industry participants.

And I think the last point is that we're also out, and I understand that there's two components to that. There's the compensation arrangements, and then the secondly would be the suppliers. On the latter, there's actually still processes in place today where we go out and... nominate volumes, we're waiting on responses, and so this is all just coming to a head. It's really just wanting to have the confidence that we know it's all as we understand it to be, and then we'll actually update the market accordingly.

Okay, and Greg, should we assume that, you're thinking about, I guess, the consequences for spot price with some of the obligations that come with that cold cap. Would we be right to assume that your net short in New South Wales as you usually are or have you actually bought more hedges given that the coal supply issues that you've got?

Yeah look it really depends on how much coal we buy so we can square that position up so you know we yeah so we can square the position up or dependent on coal and that's why it's very important for us to have a coal stockpile because you know as we saw last The last half, we saw volatility in July and August, and that's where you really want to have the call to maneuver.

Okay, good. And one last one for Laurie. Just the LGC surrender strategy, so you're still asserting that there's value created there?

Oh, absolutely. Yeah.

Can you walk us through that? Because, yeah, the original strategy was based on backwardation of the curve and an expected cost of less than $20 a certificate. And it's gone against you. I mean, the spot price is above 60 now. So how is that still creating value?

Yeah, so you're right in terms of the concept. We've already eliminated the risk. I say substantially, almost entirely eliminated the risk by buying forwards at prices that are much lower than than what the spot price was in the year in which we would have to have bought those certificates and surrendered them. And so we can very reliably calculate that the economic benefit is around about $200 million across the three years.

Okay, understood.

So it's not at risk any longer.

It's all closed down.

Got it, thank you.

Thank you. The next question is from Rob Coe from Morgan Stanley. Please go ahead.

Good morning. Thank you. Can I maybe ask a question about the octopus? Because you've mentioned there was an incident in the prior quarter where they were caught long energy. Could you maybe give us a sense of what the gross margin for octopus would have been excluding that event?

it's john here i think maybe the um the way to think about it is in terms of the the way the price cap works the svt there's about 50 pounds per customer um net margin on a cost to serve allowance that octopus have a kind of consider quite a considerable advantage on so um so to sort of bring it up a little bit of steady state you would expect all other things being equal that you would be able to flow that advantage through to now um you know including bulb the five million customer base that they've got so you can sort of see the potential in that market now that they've grown and got share um so hopefully that gives you a as an answer in terms of what a steadier state could potentially look like in that market uh yeah thank you mr briskin it's helpful could you maybe while we're talking about octopus maybe just uh give us an update on how the balance sheet of that

companies looking and liquidity and I guess if Origin might need to continue its investment there or should we think of it as self-funding?

So in terms of the liquidity position, it's fine at the moment. There's certainly no issues over this winter period. There's also a range of mechanisms now and interventions in place with government that supports retailers in the market, including one of those things that Laurie mentioned, which is the more regular repricing of the SVT. The capital requirements across the business will be looked at, obviously, from time to time around where the next stages and businesses of growth are. And so it's kind of hard to speculate at this stage what that may mean, but there's certainly nothing on the agenda right now around significant capital requirements into that business.

Okay, cool. Thank you. And then I wanted to ask a question about Slide 9 with the indicative targeted earnings trajectory. Should we be interpreting the relativity of those colors? For example, wholesale gas margin there to be, looks like it's bigger than electricity and green in the 25, 26 period. Is that, or am I overthinking it as I always do?

Hey Rob, it's Tony Lucas here. Yeah, the way that you should think really about it is we've got a wholesale electricity position, which includes our R-ing today. And I've had some comments from the team on the profitability of that. And as we move through time, most of those earnings will come from the value from the peakers. Then you'll see investment in storage and renewables in that green, which will effectively show up in wholesale electricity margin through time. And we expect gas margins, as Frank indicated, to stay in that sort of stable range. That's how you should think about that chart.

The relativities are reflective, Rob.

Okay, that's very helpful. Thank you. And I guess, Mr. Lucas, while we've got you, I notice you've seriously grown that VPP year on year up to almost 450 meg. Could you give us a sense of the firmness and the duration of capacity that you're building there?

Yeah, so what we've added is... There's a series of lots of connected devices, both in the origin zero business and in residential customers' homes. Each of those have different operating parameters. I guess some of them is moving load into periods of excess renewable supply, which means we can get a lower cost of energy, whilst others are more storage in nature. What we kind of do is we think about that as a portfolio and we probably, if we were converting it to a firm cap, you know, sort of percentage, Rob, we would probably say it's in the 30 to 40% firm.

Okay. Yeah, great. That's very helpful. I appreciate that one. Maybe can I direct my last question to Mr Thornton? just about the package of reforms that's coming through and appreciate that that's still a moving part. There is also a draft regulation for the ADGSM that's come through and it's got allowances there for trading in allowed volumes and things like that. So just wondering, is that an opportunity for APLNG given its position?

Yeah, good question, Rob. Look, I think we're still digesting what it all means. I'd say this, that certainly APL&G's position as being a strong net contributor to the domestic market puts us in a good position to manage whatever comes our way. Ultimately, and going back to something that Frank said before, ultimately, the joint venture can sustainably produce, and I think we've proven we can, 700 petajoules for quite a while. What the shareholders of APL&G choose to do and choose to support in this environment is still to be determined. But certainly we would expect over the short term to have similar levels of uncontracted gas that we have had in the past and that gives us flexibility to support the domestic market other producers should they find themselves short in the case that an ADGSM is called.

Yeah, yeah.

Okay, sounds good.

Thank you very much, everyone. That's it for me.

Thank you. The next question is from Dale Conders from Barron Joey. Please go ahead.

Morning, guys. Just wondering if you could confirm really that the $184 million margin impact that you've called out, which really looks like you're only passing through sort of two-thirds cost into tariffs. Can you confirm this is really just a short-run marginal cost, as you've highlighted, or is this a DMO impact?

I think that that's a combination. It will be largely driven by the cost of coal and gas, particularly in that first quarter that was following the events where the market was tight and plants were still coming back. And because we weren't getting the production from our original coal dial, we were having to go in and buy more fuel. And then in the absence of that, secure more swap contracts. So it really all centers around those events. The tariff that was determined for the 1st of July was only set up to the middle of May. So the events of costs that you saw from the middle of May through to June weren't reflective in the tariffs and so you had a combination of that very high set of prices of wholesale electricity costs and prices over May, June not really getting recovered in the 1st of July and that's why we get that recovery coming through the next tariffs. So the underpinning real reason is that there is higher cost and you don't get the ability to pass much of it through. But that would be the way I would I would characterize it. I hope that answers your question.

I can add a little bit more. So think about the 341 million of additional or higher coal and gas costs. Think of it as being mostly coal. And then also don't forget paying more for unit pool costs as well, which is another additional higher cost.

Can you give us an idea of how much of that was really first quarter one-off?

Let me describe the fact that we're now seeing a strong recovery in the second half and you're all now working out first half, second half. A lot of it is associated with those events in that period of time. and therefore are largely one-off.

Okay. Just maybe some comments on your expectations for DMO this year. I understand it's getting set in May again and the risk of the same issues repeating.

Sorry, say that again. Sorry, Doug.

Just your expectations for the DMO, which I understand is getting set in May yet again, and I guess the risk of the same issues repeating.

Oh, look, I don't think there was. Yeah, well, I think there's two things. They actually extended the date through the middle of May, which was a good thing because they could see the rising costs. It just didn't fully capture it at that point in time. So I think the IAR attempted to hold it out as long as they could to try and benefit from it. So I think the timing wasn't the concern. I think that was a good thing. I think what we're really focused on now is they're doing a review of the methodology and we would want that methodology to consistently therefore reflect the underlying risk and cost in the market and that's the process that's underway. So we look forward to seeing a consistent methodology.

Maybe just a comment if you can on your hedging or buying forward practices if they've changed I guess, market intervention and DMOs and really the risk of even, like, gas-coded conduct, like, capping electricity prices beyond just 2023?

Yeah, I mean, look, that's a big question, but we are very conscious of the regulatory intervention and what that does to forward purchases, so we have to be conscious of it. The reality in gas, we've largely got a locked-in position anyway, so we're not doing... much additional buying gas, but I think the biggest thing we're looking at now is coal. I've just got to reiterate, coal stockpile is very, very important for this market. And the New South Wales government is very conscious of that. We had that experience last winter. It's really important to have coal acting as your battery. So that's probably the biggest risk management focus right now.

Okay, thanks.

Thank you. The next question is from Daniel Butcher from CLSA. Please go ahead.

Hi everyone. I just want to clarify a bit more about slide 9 with the long-term and tertiary earnings chart. Could you clarify that's EBITDA or NPAT and that's the field aspects I want to sort of dive into. I'm just sort of curious about the firming and renewables part of it for example. It looks like if I sort of eyeball the chart very, very roughly, it might be $250 million or $400 million by 2028 uplift. And I'm just wondering what sort of capital investment that might require and what sort of IRRs you anticipate on that investment as a start.

Hi, it's Tony here. Yeah, so in that chart on the renewables and storage... It's a combination of things like the ARARing battery, which we've talked about, replacing the ARARing volumes with renewable PPAs, and then potentially other storage options. And they may include batteries at other OCGT sites or contracting with third parties. So it's simply the margin from a combination of all those things. So some of them are on balance sheet and some of them are off balance sheet.

All right, so is that EBITDA or NPAT that you're quoting there? Just sort of curious, what's the base for that? It's EBITDA. EBITDA, okay.

And secondly, just looking at October. Just on that point. So clearly that's consistent with the way we would deploy capital, you know, in these asset classes and that's the way we've thought about it. I don't think it's lost on anyone that one of the rationales for the bid that we've received is people see that as an asset class that they can deploy a lot of capital which would then give returns associated with the ownership of those assets. And so that would be a larger EBITDA if it was in that scenario.

Sure, sure, okay. Just doubling a couple more questions on that same topic. The Octopus EBITDA last half widened to $83 million. And obviously, calling out, it will turn around a bit next half. But again, it looks like it's getting to sort of $50 to $100 million in this chart. How do you sort of see the path to profitability there and growth into a profit given it hasn't turned a profit yet?

Yeah. Well, we've expressed confidence about what we've seen come back as a result of that timing of the tariff. and it has no contribution for bulb yet and so the path to profitability we do see associated with the uk retail business emerging now that it's actually put itself in that position it's no doubt managing um the volume volatility and price volatility in the market but as those gas prices uh calm down you don't get any much price differential as much as we've seen over the last quarter which was very accentuated leading into the winter so We're seeing that that will be the path to profitability and that goes back to John's analysis earlier about what the available margin is and what their cost to serve advantage is. And they just need to make sure that they are managing which they are the risk associated with volumes that have been through weather and so forth that comes about with that. So we do see the path to profitability emerging pretty quickly.

Okay, thanks.

And January was evidence of that. Yep. Okay.

And just a final one, I suppose, just to round it out on the retail growth side. I mean, broadband customers only grew 13,000 from six months ago. It's only 74,000. How much of that retail growth contribution is from broadband versus CES versus CPP, if you don't mind?

So I think, so very little to date on broadband by 74,000 customers, so not making much contribution at all. We certainly, so CES is a big driver of it now, and VPP will be a driver over time. The VPP benefits will be associated with both retail, wholesale, so they're a combined, but for simplicity, we've included in that as we add more megawatts, as will the origin zero over time. But at the moment, broadband is not making much contribution at all as it goes through that growth, but we're confident that we've got a proposition here that firstly it's reducing churn, but we'll make a contribution over the longer term, especially as we've bedded down the implementation of RetailX and we've got the operating model and therefore we can scale that faster organically.

All right, thanks.

Hey Dan, this is Laurie again. There is more information on customer account movements in both the appendix to the presentation and also in the OFR if you want to have a look.

All right, thank you. I'll have a check of that. And just maybe one final one. On coal contracting, you mentioned you got to your target of 1 million tonnes, so congratulations on that. Previously you were given your target for contracting for FY23. of five to six, but you haven't mentioned that. Are you at that target now, and can you say anything about looking at FY24, how you're progressing there, given we're only four and a half months away from FY24 starting?

Yeah, look, we'll progress. So this financial year, what, six million tonnes is locked in, being delivered today, and really the logistics issue that we were challenged by, you know, we've overcome. So it's looking really good. We will progress on the next financial year, but what we are dealing with right now is the intervention or the dealing with governments and just how we get that coal in by the various suppliers. So again, I feel confident about getting that coal in, but clearly we have to deal with the government at this point in time.

Okay. And if I could speak one last one in, and it was quite alluded to previously. Reasonable pricing of gas in terms of long-term potential price cap that might come in. Can you give us any colour for your discussions with the government about how they're viewing reasonable cost of supply, what they'll be looking at to measure that, given there's probably a very wide range of potential marginal sources of supply and so forth?

We know what they've articulated and now they're in a process of consultation, but what they've said it would be associated with a reasonable price that delivers a return on a long-run marginal cost of a next marginal development. But I think our view is the government are taking a broad view to assess that right now. But that's the premise upon which they went into that. But I can't really shed any more light on that. We've made our submissions. And I genuinely think that governments will be thinking, the government will be thinking, how do they set that that encourages the investment to flow? I think everyone is aware that that's what needs to happen. So I don't have any more colour than that, Dan.

Yeah. Okay, thanks very much for listening. Ask.

Thank you. Thanks.

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

Thank you very much. Frank, I'm interested in your comment about the rearing battery being very well advanced. You previously commented about costs going up. Lithium pricing was high or has been very high. Just interested to see if there's any kind of change in the cost in that project from your viewpoint and whether you're still looking at a 460 megawatt phase one project.

Still looking at a 460 megawatt phase one project. You could probably track where lithium is in those key indicators. So the costs are, I think, probably higher. similar to when we would have last commented, if that makes sense. We did talk about Escalade, but they haven't really moved since then. The business case for those and in terms of the need in the market and the various revenue sources has probably, in our view, firmed up to be stronger. And as a result, that's why we feel confident that we head into it right now and the market need for that. And that's what's supporting our investment decision. But we're not seeing the cost come down. We're just seeing the business case strengthen for the various sources. Greg, did you want to add anything?

Nothing to add since we're betting down the final pieces. But since we last looked at it, we had no additional increase in costs. So the business case is looking good. And Frank's got it right. We're also looking at the revenue side assumptions as well.

Okay. And just on that, if you were... us to extend the life of a rearing? Is there flexibility in the delivery time for those batteries then?

Yeah, so for the battery, we're looking for the completion of that project prior to 25 before a rearing comes out of the system. So that's why we want to get on and get on with this project.

Okay. Francis, one more for you. Just on the proposed changes to the ADGSM in terms of timing of notice and potential intervention in LNG supply contracts. Can you just comment on your view on that and how it could impact APLNG?

Firstly, we think that ADGSM should be the last resort mechanism. We don't think it should be used as a mechanism to manage the market on a quarterly basis. I think that could get very complex. There are other mechanisms also in place that IMO has now implementing for those tighter periods in the winter months and they're more set up to manage that sort of peak requirement, if that makes sense. So we wouldn't want to see this as an ongoing quarterly notice period, preferably to think about it being used as a market management mechanism and it should be used as that last resort. I don't know, Andrew, if you had any other comments associated with that practically?

The only one I would make is it was helpful to see the clarity around the LNG producers being treated equitably in the sense of if one project is short, they have an obligation to go and seek that volume commercially from others who may not be. Okay, thanks for that.

Thanks, Gordon.

Thank you. The next question is a follow-up from Rob Coe from Morgan Stanley. Please go ahead.

Good morning. Thanks for indulging me in another one. I guess I wanted to ask more of an ESG-related question. You've talked about retail tariffs moving up to help you recover costs and that's great, but that does also come at a customer hardship cost and I guess the cost of living pressures economy-wide are also going up. Could I just maybe get your thoughts on where you're at with your customer hardship programs. I know they've always been a big focus for the company, but yeah, just any incremental thoughts on that, please?

Yeah, Rob, it's John here. I may answer that. I think you're right to pick up that point. It is really important that we are supporting customers as they're facing a range of cost of living pressure issues. In terms of our hardship program, we have seen growth in customers on that program. We've been proud of the support that we do to that. So we have invested over $20 million into that hardship program. And you should know that we have made decisions in the past as prices rise, including the recent one across the July price increase and the gas increases just in January. Well, we actually haven't passed on any of that increase to customers in our hardship program. We are conscious that we need to support those that are most vulnerable. The second aspect of that is also providing support on the broader customer base, whether that's through our collection practices, deferrals, energy efficiency advice. We've got a lot of work we've done on rewards like fuel offers and other sort of loyalty and rewards to help more broadly with cost of living pressures. So we are certainly conscious of it and I think it's a great point to call out.

Yeah, thank you, Mr. Briskin. I appreciate that. Maybe just continuing on to that into the longer term, when you think about your customer book, do you think about providing incentives or support for customers to transition to more electrified futures versus gas?

Yeah, we're sort of considering a range of things. I mean, we've worked with the New South Wales government on things like low-income solar housing programs. And there's certainly formation of certain discussion papers and policy positions on electrification in the homes in places like Victoria and some of the councils that you see. So we're thinking those programs through, looking what we can do to support with solar battery and BPP and how do we sort of amortise potentially some of that capital cost through the transition.

Okay, great. Thank you so much. Much obliged.

Thank you. There are no further questions at this time. I'll now hand back to Frank for closing remarks.

Okay, thank you very much and thank you all for your questions and attention this morning. Clearly, as always, a lot to digest in the energy markets and across the sector. We clearly see momentum in the business, both across both businesses. Clearly, you'll digest both first and second half and also looking forward. but we're feeling very confident about the outlook for the business and feel well-placed to capture value from the transition. So thanks very much for your time and attention this morning, everyone.