Origin Energy Limited (ORG) Earnings Call Transcript & Summary

Okay. Good morning, everyone. It's Frank Calabria here, and welcome to our 2022 full year results call. We will adopt our usual format for the results. So you will hear from me and Lawrie Tremaine, our CFO; and then we'll open up for questions. You should be aware that I -- he and I are joined by all of the members of our executive leadership team, so you're very welcome to ask questions of any of us at the conclusion of the presentation. . I would now take you through to Slide 4, and you will see our financial highlights for the year. Our underlying profit is up by $407 million -- up to $407 million and so is our underlying EBITDA to just over $2.1 billion. Those have been both driven by the growth in our integrated gas earnings on the back of strong operational performance and the rising oil and gas prices. And we have a lower contribution from energy markets due to lower electricity margins. The underlying earnings have resulted in an underlying return on our capital employed growing to 7.6%. And then if you look at our free cash flow, which is just over $1 billion, this year, that's been underpinned by the record APLNG distribution. And when you add that to the proceeds of the sale of 10% APLNG and after the investment we made subsequently in Octopus and also some collateral in a very volatile market that we've needed to post, that contributed to a $1.8 billion reduction in our debt down to $2.8 billion. I'm pleased to be able to declare a final dividend of $0.165, and that's franked to 75%, and you can see that representing 7% of that free cash flow. And what you will do is hear, as usual, from Lawrie on our financial results in further detail. I have to say it's been -- and just turning to the next page. I have to say it's been an extraordinary year in energy, both globally and in Australia. You can see that the energy transition has accelerated and it's continued to do so. But it's also this year collided with macroeconomic and geopolitical events, and that's caused major volatility in energy prices. In addition to that, in the domestic market, there's been a number of factors that have added to these conditions with significant coal power plant outages and wet weather affecting supply. And that's obviously caused an acute tightening at times, particularly in the last quarter of this year, of both electricity and gas supply and led to escalated wholesale prices in the domestic market. I think what these events serve to highlight to us is that there's an urgent need for action on two fronts. One is that we need to be able to sustain the existing systems reliability and at the same time, accelerate the transition to the new lower emission system, and we're actively engaged with governments on those policy settings that are required to have that happen as smoothly as possible. Origin's taking a lead in driving the energy transition, and you'll be aware that we launched our refresh strategy and ambition earlier in the year, and we'll give an update as to our progress on that, which is going very well. And I think you can also see through the results this year the benefits of our diversified portfolio and its ability to generate cash in these conditions. After what's been what we would describe as quite an abnormal period and set of events over the last year or two, I'm also seeing an improving energy markets outlook, and we'll take you through the drivers of that. And as always, we remain very focused on the effective and disciplined allocation of our capital with the objective of always increasing returns to you, our shareholders. Now we'll actually look at each of those points in a little bit more depth. So turning to Page 6. There we go. To Page 6, you can see the elevated and volatile commodity price environment. Electricity spot prices reached a high $400 in the back end of the quarter to now -- but have now then, obviously, dramatically reduced in recent weeks, down to be just under $150. And similarly, you can see the coal price, both export and also the 5,500 indexed coal, have both escalated. In the case of that export coal to be up to as high as AUD 600 a tonne. And then in terms of gas prices, you can see the connection between the international JKM and spot prices. Domestically, they highlight really through to the July. And I think if you were looking at the Wallumbilla spot price today, that has also reduced dramatically, and it's probably down under $20 as we speak. Nevertheless, it serves to highlight just what's happened over the course of the year in commodity prices, and you can see they're moving inbounds that we wouldn't have historically seen due to the events I described earlier. Those -- if I then just turn to the domestic market conditions, which we've reported previously, but I thought it was appropriate for that to be a reminder to everyone as to what occurred in that final quarter. And you can see that we saw over 4,000 megawatts of coal generation coming offline in June at exactly the same time that weather was cooling and therefore, increased customer demand had occurred. And what you therefore saw is, I think, the importance of gas and the role of renewables today in terms of filling that supply gap in the fourth quarter. And you can just see that's what's led to a dramatic increase in both the gas and electricity prices, the magnitude of which we've just highlighted there in percentage terms. This led to the regulator applying an administered price cap and then subsequently suspending the market. The extreme electricity prices have meant that retailers, in some cases, weren't adequately hedged. They -- that meant that they face challenges. What we've seen is 5 retailers exit the market through Retailer of Last Resort events, but you've also seen many retailers that just withdrew market offers because the allowable price under the default cap was well below the cost of the wholesale electricity in the market. So it just really does show that gas power generation and the role of gas in the security of the system was critical over that time, and we were fortunate also to have renewable supply in those winter months as well. In terms of the urgent action I talked about earlier about the existing system and accelerating the transition, I think it really just highlight those events that I've just described to you, the critical reliance we have on that existing system in the coming years. And a key focus for both us, the industry more broadly and government now is to work together on making sure that the coal generation plant, which still represents a large installed base of what keeps the lights on, needs to be reliable. At the same time, I think it's highlighted the coal supply and the security of that supply is critical as it also is for gas supply to support peaking capacity. It has also highlighted a couple of other aspects of the market settings that have needed review, and that includes that administered price cap, which was set many years ago and also the Retailer of Last Resort provisions. And that's something that we're very much focused on and engaged with the market bodies and governments in terms of the improvements we can make. At the same time, I think it's recognized that if we accelerate into the transition, and that's something we firmly believe needs to be done to build the new lower emission system, a lot of investment is required in renewable energy, firming generation and transmission to underpin it. And therefore, that investment, and I believe the transition now, the key challenge is really the infrastructure challenge required to build out that new system, and that's going to take time and we need to get on with it. In particular, one of the key areas that we believe is required that's linked to that system reliability is that there needs to be a price incentive for the reliable generation capacity that needs to be available for these events that are less predictable but nevertheless critical for that tail risk of when the system doesn't have it all operating as expected on an average day. And in that regard, we believe the capacity payment mechanism that encourages new flexible capacity is urgently required so those investments can be made. And at the same time, we need to contemplate how the risk of a disorderly generation exit can be avoided through the settings that are made available. And I think we think -- we can see now also that whilst renewables will be there, there'll be more storage available, there will be more hydro built, but the role of gas-fired generation does really represent the key backup that's required when those -- because you do -- when there's not available because you will need dispatchable generation well into the future. This is -- the next slide is really the reminder of the ambition and strategy that we refreshed in March and launched our ambition to lead the energy transition through cleaner energy and customer solutions is set across 3 strategic pillars. You can see, they're unrivaled customer solutions, accelerating renewable and cleaner energy and also delivering reliable energy through the transition by being a great operator, doing that at a competitive cost and making sure it's available to create value. And what we've then done is given you an update on our progress on Slide 10. I know it's busy. The right-hand side, that ambition are really the repetition of the ambition that was actually -- and the targets we'd set ourselves at the time of launching the strategy. And I would like to highlight just some of the key achievements to date. I'm pleased to say that when it comes to the customer solutions, we've continued to improve our customer experience, and once again, our strategic NPS has grown. We now have 2.2 million customer accounts on Kraken. We've certainly lifted the standard and performance as an NBN retailer, and I'm pleased that we've received the Canstar Blue award there and grown our customer base. Octopus has continued to grow both as a retailer and technology provider, is now the #5 U.K. retailer in the consolidated market and has 25 million licensed accounts under its Kraken platform. And we've launched Origin Zero, our e-mobility 360 and also acquired WINconnect. So good, solid progress towards, if you look on that right-hand side, the ambitions we've set ourselves. When it comes to the renewables and cleaner energy, clearly, you're all aware that we'd announced the potential earlier closure of Eraring as early as 2025. We now have 1 gigawatt of renewable solar development projects that are in a late stage, and we've also purchased another 600 megawatts of greenfield sites. The Eraring battery development has now received permit approval, and we're in the process of tendering it. And we've continued to grow our virtual power plant now to 258 megawatts. We've received federal government funding for our domestic hydrogen project in the Hunter Valley and are now working through those steps and look forward to be able to introduce that over the coming months and years. When it comes to delivering reliable energy through the transition, clearly, record distribution from APLNG of $1.6 billion, $1.4 billion after the hedges. You're all aware, we sold 10% of the interest in APLNG. Very pleasingly, these fields continue to improve, and we'll take you through the fact that we have now, obviously, got a reserves replacement ratio for this year across operated and nonoperated 2P of 116%, but also highlight that over 5 years, that's 100%, which is telling you that we've got a very good resource on our hands, and that's playing out in combination with our operational performance. We have now contracted 4.4 million tonnes of coal for the FY 2023, targeting between 5 million and 6 million tonnes, and we'll give some context around that as we go through the presentation. So all in all, I'm very pleased with the progress we're making on our strategy, and we've got our eyes firmly set on what we want to achieve whilst continuing to manage the risks and all of the things that energy markets are playing out. And we're doing both of those, and that's setting us up for the future. We will -- going to Slide 11. Our strategy is also aligned with lower emissions whilst creating value for our shareholders. We will be putting a climate transition action plan for an advisory vote at our AGM. It does update targets that accelerate our emissions reduction and the target will be consistent with a 1.5-degree pathway and that will be announced, and it also will outline our approach to just transition. And we certainly have a live example of that going on with the work we're doing in Eraring, Lake Macquarie and the Hunter Valley region. We continue to be a purpose-led organization. If you look at 12, I won't take you through all of the points there, except to say that we remain focused on delivering for all of our stakeholders. I'll just highlight a couple of things. Clearly, our customers have needed support through COVID and floods this year. And clearly, we've got also, we've got price increases going on that we remain very committed to the support of our customers on our Power On hardship program. Our communities, you can see that we're supporting regional communities, our indigenous communities through a variety of measures and through our foundation. And on the planet, I'd probably highlight that in the last year, we've reduced our Scope 1 and Scope 2 equity emissions by 12%. And you can see there, we're also increasing the reuse rate of Eraring ash, so recycling more ash. And when it comes to our people, it's worth highlighting that we've been disappointed with our recordable injury rate. Good to see the process safety events down, and that's been solid improvement. And while our severity of injuries are down, that's prompted us that 4 0 TRIFR is not where we've been over the last several years. And so that's got a lot of attention for our leadership. And you can see there where we're doing on diversity engagement. So on that note, I am going to hand over to Lawrie to take you through the financial review, and I look forward to taking you through the operations and outlook after that.

Thanks, Frank, and good morning, everyone, and thanks for joining us. Look, I'm going to start with the profit bridge on Slide 14. So underlying profit was up $93 million or 30% due mainly to the positive impact of strong oil and LNG prices on our upstream business, partially offset by lower electricity gross margins in our Energy Markets business. We incurred $165 million of oil hedge premium and losses compared with gains last year, $23 million of losses on LNG trading and $25 million write-off of exploration activity in the Cooper-Eromanga and Canning basins. Depreciation and amortization expense was lower due to the impairment of generation assets last financial year, net of the increased depreciation of Eraring following the expected reduction in operating life. Net interest was flat year-on-year. Interest expense, $55 million lower with lower debt levels and MRCPS interest income, $58 million lower. Tax expense was $100 million lower, reflecting lower earnings in energy markets and oil hedge and trading losses, partially offset by tax on unfranked APLNG dividends. Moving to Slide 15. There have been a number of significant impacts on our financial statements resulting from the high and volatile commodity prices that Frank showed earlier. And this particularly occurred in the last 2 months of the financial year. There was $4.4 billion of net fair value gains in energy markets derivatives booked to statutory profit and the hedge reserve during the year and $3.5 billion of energy markets in the money derivatives on the balance sheet at year-end. Booking this derivative asset increased the overall asset carrying value for energy markets. Given these hedges maintain future expected cash flows rather than increase them, we were required to recognize an offsetting impairment of the carrying value of the business assets of almost $2.2 billion in our statutory results. The higher commodity prices also resulted in large futures exchange collateral cash inflows and an increase in the security deposit acquired by AEMO. These movements are timing rather than performance related and will largely unwind in the coming months. Next, I'll focus on APLNG cash flow on Slide 16. APLNG generated $6.8 billion of net cash flows from operating and investing activities. High oil and LNG prices are key factors in delivering this result, but so too was our operating and field performance, enabling strong production and low levels of development activity and spend. $5.3 billion of the cash generated was distributed to the shareholders in the form of MRCPS buybacks and interest. And once these were fully repaid unfranked dividends, a record $1.6 billion was distributed to Origin. A further $694 million of project debt was repaid. APLNG cash on hand increased by over $600 million to $1.5 billion, and that is available for future distributions. This strong cash performance was achieved at an effective oil price of USD 74 per barrel, with the lag in LNG contract pricing, we expect, to benefit from continuing strong prices well into the first half of financial year '23. With the repayment of the MRCPS, APLNG distributions are expected to be in the form of unfranked dividends for the near future. There are 2 important points to note. Firstly, Origin will pay tax on these unfranked dividends; and secondly, the unfranked dividends are likely to be higher than our equity accounted APLNG profits. This means our tax expense will likely be higher than 30% of Origin pretax profits. So Origin free cash flow on Slide 17 was $32 million higher for the year. Lower operating cash from energy markets was offset by higher distributions from APLNG, net of oil hedging losses. Futures exchange collateral receipts were substantial at $471 million. We have subtracted these from free cash flow for the purposes of the dividend calculation given they're timing impacts only. We received net proceeds of $1.957 billion from the 10% sale of APLNG and completed the acquisitions of WINconnect and a number of solar farm projects. We've also made further investments in Octopus Energy, including $188 million of deferred payments and $80 million of follow-on investments. $163 million was invested in Octopus early in the current financial year to restore our equity interest to 20%. We continue to apply a disciplined approach to capital expenditure, holding sustaining expenditures flat year-on-year, allowing for the increased capital allocation to meaningful growth opportunities. Slide 18 reinforces the journey we've been on from peak debt of some $13 billion in FY '15 to less than $3 billion today. Debt to EBITDA is slightly below our target range at 1.9x. This is a great achievement and restores our flexibility to invest in targeted growth and deliver returns to shareholders. Turning to Slide 19. Our final dividend has been increased to $0.165 per share, taking the full year dividend to $0.29 per share. And just by way of comparison, our final dividend last year was $0.075 per share and our interim $0.125. The full year dividend represents a 47% payout of adjusted free cash flow. This is on top of the $250 million allocated to the share buyback during the year. The final dividend will be 75% franked. With the receipt of unfranked dividends from APLNG, we expect to be in a taxpaying position and generating franking credits. APLNG is utilizing carryforward tax losses more quickly at current high commodity prices, and so we expect them to be in a taxpaying position from late FY '24 or FY '25 with a specific timing dependent on realized prices. Given the strength of our balance sheet and the expectations of continuing strong distributions from APLNG, the Board will consider extending the initial $250 million buyback during the coming year. The decision has not yet been taken, given the uncertainty facing the Energy Markets business. And just turning to Energy Markets earnings on Slide 20. As expected, Energy Markets EBITDA was significantly lower in the year, attributable to $692 million lower electricity gross profits, $325 million of which was driven by lower wholesale prices during COVID in 2021, flowing into customer tariffs in 2022. While revenues were based on these lower tariffs, we experienced higher input costs from 2 main sources. Firstly, fuel input cost to generation were $315 million higher due to the under delivery of contracted coal from our primary supplier, resulting in replacement coal purchases at significantly higher prices. Gas generation increased with the additional gas also purchased at higher prices. Secondly, lower generation due to coal supply disruptions at Eraring resulted in additional coal purchases at higher prices, further impacting gross profit by $124 million. These impacts were partially offset by improved management of customer value and the recovery of prior year network costs, providing a combined $85 million positive impact. Gas gross profit increased $117 million, primarily due to the increased volumes and prices of short-term trading sales, particularly in the second half of the year, the net of higher procurement costs. The positive impacts of retail and business tariff repricing was largely offset by increased gas supply costs from contract price reviews and the expiry of long-term contracts. Finally, the Octopus earnings contribution was lower than expected, impacted by higher energy costs and broader disruptions in the U.K. market. Octopus has fared well under these circumstances, particularly relative to many competitors in that market. Turning finally to Integrated Gas on Slide 21. We equity accounted 37.5% of APLNG until the 8th of December and 27.5% thereafter. Even with this sale impact, our share of earnings was up $989 million, primarily due to higher LNG prices, both oil-linked contract pricing and spot. The realized effective price before hedging was USD 74 per barrel compared to 43% in the prior year. Operating costs were $353 million higher with higher royalties associated with higher prices representing almost 2/3 of this increase. Higher electricity costs, higher purchase of gas during the major downstream turnaround and the direct cost of the turnaround making up most of the remainder. With that, I'll hand you back to Frank for our operational performance.

Okay. Thanks very much, Lawrie. And now we will turn to Energy Markets on Page 24. And really, on 24, what we put is not any new information but really just tell you the story of electricity for the 2022 financial year. Clearly, tariffs were set at the beginning of the year, where wholesale prices were low coming on the back of COVID. And what you will well understand, as we went into the half year, is that there was an under-delivery of contracted coal from our main supplier, which means we replaced that coal with more expensive coal, as Lawrie has described, and also purchasing and market. When we entered into the final quarter, clearly, we had an event where there was further short-term supply issues before we responded to that supply through additional coal being delivered, and that was through the support of us working with our suppliers, rail network providers and the New South Wales government to make sure there was enough coal delivered via rail while we went through that disruption. And at the same time, further increased by -- we further responded through increasing our gas-fired generation and gas purchases. So there's the story for the year that really played out in terms of electricity, but I think you should all have understood through prior communication, but nevertheless, does highlight what occurred and just how abnormal that is over the course of the year. When you turn to Slide 25, you can see the story of what's played out, therefore, in terms of both wholesale prices as they feed into the customer tariffs and also just highlight fuel costs through the coal prices on the right-hand side. And what you can see there, through the colors, red, blue and yellow, albeit small for '24, you can see '22, '23 and '24 prices, and the dotted lines represent the average that is feeding through to the tariffs. And you can see, therefore, that we have seen a rise in tariffs in the FY '23 that was set on the 1st of July. But the cutoff shows you that a lot of the escalation in the underpinning wholesale prices is not yet reflected in the tariffs. And therefore, if those forward prices continue or current prices maintain, then you'd expect a further material uplift in the tariffs for the FY '24 year. When it comes to coal, you can see there are the charts there for both 6,000 and 5,500 Newcastle Index. Just for clarity, we've mentioned before, you should be thinking about the yellow line when it comes to the type of coal that we are purchasing at Eraring. We've contracted 4.4 million tonnes for the financial year '23 at a target of between 5 million and 6 million tonnes. And it's at a mix of legacy and market forward pricing at the time of us doing the contracting progressively over this period. Rail deliveries to Eraring are increasing, and therefore, there's a higher proportion of coal coming from rail. And we continue to negotiate further coal supply. The risks around it really today are that there is obviously under delivery under contracts and also due to rail and mine performance, that's what we're really managing today. And obviously, we still want to buy some more coal based on market conditions, I should say, between that 5 million and 6 million tonnes, but clearly made a lot of progress in terms of us contracting the coal for FY '23. If you then turn to gas on Page 26. The slide on the left-hand side is a repetition of what you would have seen earlier. The higher gas gross profit for this financial year has been driven by short-term trading sales, which have been at higher prices and partially offset by the higher procurement costs, which we would have flagged, I think, leading into this. The East Coast gas prices have now obviously reconnected as the markets tightened domestically. They've reconnected to the international market, albeit you can see coming out of that sort of use of gas into the gas-fired generation as more coals become available, but therefore, that spot price for gas very recently since this has actually declined, highlighting that the gas is available but also that those spot prices respond to that. When it comes to FY '23, we have locked in fixed supply contracts. There are no price reviews on those contracts until the following year on the first of July 2023. And so therefore, we're well placed in terms of the cost of our gas for this financial year, in addition to which, all of the JKM exposed supply contracts for FY '23 were hedged before October 2021. And so we have a good cost position for our gas going into this financial year. All of the JKM exposure supply for FY '24 is now hedged fully, and that's at favorable rates to the market as well. And as it relates to the price review for 1 July 2023, it's in relation to about 50 petajoules. And that price review would be informed by contracts, the average of contracts over the last several years. So it's not actually based on the prices today. So that is yet to play out, but that's what the basis of that review would be. Turning to the retail market environment. You can see there what's really happened in terms of market churn, and you'll obviously identify that just right at the back end of the financial year, you see that spike. That spike's really driven by a few things. Clearly, the communication of prices by all retailers at that time. You had ROLR events occurring as well in May and June and some in July. And you've also got evidence of smaller retailers turning customers away as they were battling, I think, higher wholesale costs at a time when the tariff was not recovering them. What you can see in the case of discounts is they've therefore reduced. And we just give an example there of what's happened in market in response to those conditions. For example, in Origin, a market discount today of 5% of DMO compared to 19% only a couple of months earlier. So you're seeing a market response by competitors, and you're also seeing a market response in terms of the higher cost of that energy and how we therefore compete in a retail market from Origin's perspective. And I think clearly, what's our focus and why we focused on the ROLR events is that there's obviously -- continues to be risk for those retailers not adequately hedged or integrated as it relates to the spread between those wholesale prices and the retail cap. What you can see also, though, by the previous chart is that's also moved around, that volatility, where we've now got a forward price well below half what it was only a month ago. So it highlights just what's moving around in the market right now. Taking you to Slide 28. You can see there, we've continued to grow our customer accounts over the course of the year, including the acquisition of WINconnect that's contributed to our Community Energy Services business. You can see the ongoing trend in terms of customer experience we highlight through our NPS, but also you can see there in terms of our Trustpilot scores. We continue to evolve our products and loyalty schemes and what we've really done is combined with Everyday Rewards and now got fuel discounts, and that's going very well in terms of how we're attaching that more broadly and continue to have a market-leading brand awareness. We focus on being a lean and increasingly digital business, and you can see that in terms of our cost to serve. I should highlight that cost to serve actually captures within that. That's the retail, has continued to reduce on the way to our '24 target. We've invested back into some of our businesses, including the future energy and the growth of some of the others, but we remain very much focused on achieving our target of $200 million to $250 million cash cost savings against that 2018 benchmark by 2024 and very, very pleased with the progress we're making on that. Going to the next slide, just provides a little bit more detail. You can see there that the future revenue streams, particularly as it relates to Community Energy Services business has grown. WINconnect's contributed to that in addition to organic growth. The growth in the broadband business and the customer experience that comes with that, pleased to see the progress we're making there. And we've continued to grow value through the capabilities that we've been building over time that's really resulting in more personalized and segmented offers, and we continue to see that opportunity for us to become a better and better retailer at a much more personalized level. I did mention we had 2.2 million customer accounts on Kraken, and we've been able to hold customer happiness and employee happiness while we go through the big change, and we're very much focused on having that completed for the electricity and gas accounts by the end of this calendar year. And we made good progress on our virtual power plant. I mentioned the 258 megawatts. But what we're seeing associated with that is a hell of a lot more engagement by customers as we build out that digital interface and the products we're offering them. On Octopus, I did talk about -- they've certainly emerged very strong as #5. I think we should put it into context that we've had 30 to 40 retailers exit that market. And whilst that's come at some cost to Octopus relative to our expectations at the beginning of the year, I'd like to stress to everyone here that they have a very robust hedging program and have come out much stronger overall in a market that's consolidated and now have 15% U.K. market share. They set an ambition several years ago of 100 million accounts. They've gone from not that many to now 25 million accounts worldwide. And that's now going to drive licensing revenue over the next 3 years of GBP 500 million. They've successfully completed E.ON. They're moving into utilities other than electricity for Kraken on water and broadband. And they've added the renewable assets, and clearly, we've seen their growth in that value of Octopus, which has been, I think, validated by the investments recently made by CPPIB, Tokyo Gas following on and also Generation Investment Management. So you saw all shareholders continuing to vest in Octopus, and it's a very exciting opportunity with lots of growth to come. Turning to Integrated Gas. On Slide 32, that really is the story of reserves. You can see there that the operating reserves have replaced at 100% over 5 years, and we've just highlighted that really 80% of that's been achieved through the improved type curves and forecast upgrades and only 20% from converting contingent resource to the 2P. In this year, that's been 116% across both operated and nonoperated. And if you were focusing just on the operated, it's 129%. This continues to serve, I think, a very strong message to everyone that we've got very good gas fields performing well, and they've continued to improve as we learn more and as we -- and to take further activity. Production has continued to be stable this year despite weather events and everything else that's slowed. We are very much focused on production optimization. I'll take a little bit further that on the subsequent slide. And you can see we continue to be a low-cost operator. There is the increase between '22 and '21 largely driven by the power costs. We went through a large -- we've gone through the Train 1 major maintenance, and we do have one coming on this year for Train 2. But underneath all of that, the operational performance of low well rates and controllable spend is all going very well. If you looked at that performance on Slide 34, it just breaks it down. You can just see the level of activity of just how much of that has reduced in terms of drilling over the last couple of years. And that's meant that the focus has moved from drilling to optimizing our existing operations. And when we talk about that, a good example would be the work that's been undertaken to build infrastructure that essentially is just pipe, really pipeline infrastructure that's connecting where we've got excess gas to where we've got spare capacity for processing the gas, meaning, that, that really is the most cost-effective, incremental way of adding to the utility for us to produce versus drilling wells. And what you can see there is the well availability and also the gas processing facility reliability continue to be improving. We see further opportunity on that well availability, but we got very high reliability on that plant overall. What that does is that operational performance then translates through to the following slide in terms of record revenue when you combine it with the very strong commodity prices. And you can see the average LNG price achieved over the year, the average domestic price and also the LNG spot price. We delivered 15 spot cargoes during the year, continue to play a big role in the domestic market, providing, I think, close to 150 petajoules to the domestic or the East Coast market and increased that by 4% in the June '22 quarter and continuing to play a role actively to support the domestic market customers and find ways for gas to be actually moved to the southern states, and that continues today. But you can see there just how strong that revenue base is and combined with the operational performance, what that's delivered over the year for APLNG. Now coming to guidance. So firstly, what we have provided is guidance for Integrated Gas. And you can see there that our production guidance is between 680 to 710 petajoules, and that continues to reflect that ongoing strong field performance. The CapEx and OpEx is up from the $2.2 billion this year to $2.5 billion to $2.7 billion. There are 3 drivers behind that. There is the upstream -- there's an upstream program that's going through, a multiyear program that we've commenced -- we're commencing in this financial year that wasn't in last year, and we can talk you through that further if you've got any questions. There is some increased well workover activity this year. But one of the key things that's really played out is really just the power prices are flowing through, which have flowed through a bit into '22, but also into the '23 period. And they really are the drivers of that, and we continue to know the -- there's nothing else that's really sitting outside of that at the moment that we're experiencing. So I think we still feel very good about what our cost performance is. Now we've -- about 43% of our oil exposure for '23 has been priced in at USD 108 a barrel before hedging, and that's based on -- that really is based on the lag in flow-through that comes through rather than the spot prices. So based on those forward prices, the oil hedging program that was established when you were seeing very different oil prices a couple of years ago, so that actually has a cost to us of $290 million. And the LNG trading is just really the -- is the cost associated, the net spread between essentially our Cameron and ENN contracts. When it comes to Energy Markets, you'll see that we've not provided guidance at this point, but I just wanted to give some context to that. And that is that we do still see a wider range of potential outcomes for earnings than we would historically when we've given you range of earnings, and we'll continue to assess that outlook and provide an update as that uncertainty reduces. Clearly, that uncertainty has reduced with the contracting of coal, but I'll just take you through some of the other drivers of the results in '23. So we do expect higher earnings in FY '23, and the gas business is expected to deliver higher earnings on that largely fixed price supply portfolio I took you through earlier. The electricity gross profit is expected to remain suppressed due to the higher energy costs, and they're only partly priced through to the regulated tariffs that I took you through earlier. We have contracted 4.4 million tonnes. They are a combination of legacy and market-based contracts, and we still have the risk of under delivery due to rail and mine performance. So when we just combine the elevated commodity prices and the volatility that you've just seen and the ranges of those outcomes, we still feel that they're still wide enough for us to have held back on guidance at this particular point in time. But hopefully, you can see the drivers of that, and we will continue to keep you informed. We felt that because of the nature of our industry and the fact that commodity cost has a lag, if you think about it, the retail tariffs are set. They're essentially a 3-year lag when you really go through the way they're set over time. But we just give you some commentary also about the outlook for FY '24. And we do anticipate further earnings growth in FY '24. It is based on the assumption of the current forward prices as you see in energy at the moment are maintained and that they flow through to customer tariffs as expected over time. There is still coal contracting to be undertaken in that year. And also, I talked about that gas price review outcome that's yet to be concluded. We do expect our Octopus Energy to deliver growth, that licensing revenue will ramp up, and the U.K. market, while still going through extraordinary times, I think, is certainly more stable, I think, today as it relates to the energy retailers than it was a year ago. And I would just reinforce the comment I made earlier about the retail transformation expecting to deliver on our cash costs that we had previously committed to. So thank you -- and the last slide, just really to pick that up, just really to tie that all together, and we presented this at the time of our strategy presentation. I thought it would just be worthwhile to just have this in all of your minds as investors, that while we go through this and set our business up for the future, you can see that we are strategically positioned well to benefit from the energy transition. We've got a wonderful platform with a large customer base, with a lot of capabilities coming through that you can see progress on. We certainly have the diversification of a portfolio across electricity and gas when it comes to energy supply. And you can see that what we will do is we'll progress the phasing out of Eraring and the replacement of that with a combination of renewable energy that then enables us to move electrons around and through that price curve with batteries, virtual plant contracts and our large peaking fleet of gas-fired generation that's already being invested in. The gas, I think we've talked a lot about APLNG and the strength of it. Also, we've got a lot of access to historical gas and a fixed cost supply that's beneficial in that business and feel very good about the progress that Octopus is making. So on that note, I will leave it there, and we will now open up for questions. And the team are looking forward to getting all of your questions.

[Operator Instructions] The first question today comes from Dale Koenders from Barrenjoey.

I guess I just wanted a little bit more color around connecting the commentary around strong earnings from APLNG and a recovery in energy markets and leverage sitting below target range versus not continuing on with the on-market buyback program.

Dale, it's Lawrie. I disagree with the final point. What I said was that the Board will consider it, but we just want to get through a period of uncertainty here. And essentially, it's inconsistent, I think, to not provide guidance at this point and then have a buyback and express a great deal of certainty about the future through a buyback. So we're just taking time to consider that more fully through the year.

So I guess then if we're waiting for the certainty around guidance over the next 12 months, how are we progressing on coal contracting? When do you think you'll have greater certainty over that, which seems to be sort of the biggest swing factor at this point in time for FY '23?

Dale, it's Greg Jarvis here. Look, as you can see, we've contracted 4.4 million tonnes already, but the real message here is that we have made very strong progress on logistics. Getting coal from the Hunter Valley into Eraring is the key. And just that last quarter where we saw so much extreme volatility, we really relied -- and I'll just bring that to life. We're getting 2 trains a day into Eraring. In the very volatile period of the last quarter, we're getting 6 to 7 trains a day. So we've made real good progress. And what that allows us to do is not to be reliant on our local coal supplier. And so we're getting increasingly confident we can sustain that rail program going forward. So that's why we're getting more confident, and we've contracted up more coal. I think we've made really good progress on that front.

So just for clarity, do you think we need to get -- maybe it's a question for Frank. Do you think we need to get -- or you need to get the [ full contracts ], 5 million to 6 million tonnes per annum for FY '23, before we can get guidance for the year? Is that really the key?

I just want to actually -- I wouldn't put it straight down to that, to be really clear to you, Dale. There's a few key things. We've just watched prices go from $400 to $150, and we're watching that. And that looks like it's playing as coal's come back into the system, and we've got more confidence on that, but that's what we've just watched. At the same time, we've seen gas prices move from 40 to I don't know, to 20, if I'll use that as an experience. So we just got movements in commodity prices that we've not seen the scale of, and those movements in commodity prices when you've got fixed cost positions and risk management that's associated with logistics, it just produces a wider range of outcomes. And so therefore, given the recency of that information, Dale, and the movement around on that, it was just really that, that's really driven it. Alongside the fact that, yes, 1 million tonnes of coal, if we're going to buy another 1 million tonnes, has got to be closed out, but that would only be one factor. It would be just a combination of the others. And so that's all. It's just the recency of the changes in the market, the magnitude of them and just wanting to get line of sight.

The next question comes from Mark Samter from MST.

A couple of questions, if I can. I guess just within the context of all the debate around the buyback. First small question is not that I can say, there's no CapEx estimate for energy guidance for energy markets this year and whether that's a consideration or if you can give us some color on expected spend there. But also, have you thought about introducing a more rigid framework like Santos just did, but is certainly more common overseas where you just return a relatively set amount of excess cash flow from APLNG above a given oil price, so the market can get a bit more certainty and take its overview on how much that's going to be mean, your return?

Okay. So firstly, on the capital expenditure and then we'll go more broadly to capital management. I don't think there's anything unusual in our capital expenditure commitments for maintaining our business and running our business each year. There's a little bit more in the Eraring because we're doing some work on some ash dam work and so just we're doing a little bit of activity associated with that. But that's not material in the scheme of things. The balance of the capital expenditure, Mark, would be driven by growth activity and the timing of projects. They've been well flagged, and you know we would deploy capital, I think, wisely and you'll probably -- the evidence of that is we thought -- we said we would partner with third parties in terms of funding renewables investment, and you can see it's been sort of publicized as to who we're partnering with in relation to the CWP process as an example of thus flowing through that commitment. So I think it's just really the timing of those projects, Mark. But there are growth opportunities for us, and we will consider them as part of our capital requirements over the year. And now I'll go more broadly to then how that -- that would be just one factor that we would feed into overall about a more rigid policy but not determinative in its own right. So I just might ask Lawrie to talk about the capital policy.

So the potential for us to invest in growth is likely to be lumpy, and it's even likely to be recycling of capital. And so until we've got a clearer handle on that, it's pretty -- it's hard for us to consider a very structured program. And so we're -- and also the uncertainties that we've talked about at length already on this call. So we just need a bit of time to get through this period and a bit more maturity in our growth program. And then, yes, I think we probably could consider a more structured approach.

Okay. Perfect. And then second question is probably for Greg, I suspect. Just on the gas book and obviously you talked about the fact you've hedged all about JKM exposure out for this year. And your largest competitor kind of has the opposite-looking chart, whereas in the previous chart they put up suggests that they are under contracted on supply for -- to meet minimum obligations. I think my first question is, is there the opportunity to take market share from competitors? But more important than that, I think you said at the first half results, when you alluded to the better earnings in FY '22, that you've seen some bring forward in price increases that you expected to come to in FY '23. But obviously, the gas markets moved profoundly to the better for you since then. So I guess are we also going to be looking at FY '23 being considerably better than you thought it was when you talked about the bring forward of earnings rather than increases? Sorry, that was a very long-winded question.

Mark, and I think you've answered it as well. Look, our gas book is well placed. It's well hedged for a couple of years, actually. And we are -- we're seeing a pickup in market share. We are seeing some of even the -- some of the customers which were sitting with Western come off spot and contract with us. So we are seeing opportunities in our gas book. There's no two ways about it.

Okay. Just a small, minutial question, actually, just because it matters when CPI's 6% or 7%. So the fixed price contracts, do they go up by CPI or it is linked to CPI, but not at CPI?

Yes, right. There's a real mix in here. We have some CPI exposure with some contracts. Some contracts, we have none. But we also have CPI exposure on the revenue side as well. So real mixture, yes.

Not everything would be, yes. Not overall, but the reality is you will have a CPI linkage, but probably not full on all volumes, Mark, is probably the best way to think about it.

So would you say -- putting aside what wholesale price has done, would you say high CPI is net good or net bad? Is it that you have more exposure on the revenue side or on the supply side?

I'd say there's more exposure on the cost side than the revenue side, but it's marginal, Mark.

The next question comes from Ian Myles from Macquarie.

Can we just touch base back on energy markets with the concept that typically your pricing in retail is fixed in the next 12 months. Most of your C&I has been rolled over. You're talking about a relatively fixed -- nonfixed price gas book. And then you've moved away from sort of that product guidance saying, it's not certainly around coal, but you've only got 1 million tonnes left on hedge. What other large variances can really swing it given -- yes.

Okay. There's probably 3, okay? If you had under delivery of coal, for example, or had coal logistics, that could be one. And I'm not -- that's a risk event as compared to something to predict, but therefore it would be one. The second would be what coal price are you contracting the last 1 million tonnes at. The third would be what price are you selling uncontracted gas at. And there's probably just -- but the only last thing, what I would say is that we're watching and observing at the moment that the market has returned to hollowing out in the day. And that's obviously quite a different market dynamic. And that's obviously quite different to a month ago. And as you know, we've been set up to operate in that environment and that's probably the only other thing. And if that endures, that would go to the way we run our portfolio. Now Ian, individually, they're not all huge numbers. But when you think about what range we give on guidance generally in the range we give it to, you could have more than one of those add up, and that's the only thing that we've held back at the moment on, not because we're moving towards that, but because we're actually seeing quite a different dynamic in the market already in the last week or 2, completely different to what it was when it was high $300 or $400 flat 2 or 3, I don't know, 4 weeks ago. And so that's the only reason that sits behind it. There's nothing else, Ian, that's sitting behind it other than you've got a number of those moving parts. That's all.

Okay. And then Hunter gas pipeline being sort of announced or potentially being built, does that start changing your thought process of maybe building a gas plant up along the Hunter, where the cords are?

Ian, just say that again, building -- I mean I know the Hunter gas pipeline.

An open cycle gas turbine somewhere near that to take advantage of both hydrogen and also methane in the next 20 years.

Look, that is right through. We have lots of opportunities and sites to build additional open cycle gas turbines if we need. We'll see how that takes place with the Hunter gas pipeline. Clearly, there's other options for Santos to get their Narrabri gas into market. That, look, again, in our development fleet, we've got opportunities on existing sites. So we'll have a look, but I don't think it's -- there may be an opportunity, who knows?

Okay. And upstream in APLNG, you're starting a drilling program. Are you thinking about increasing the amount of production there? And I think there was a comment by government talking about potentially opening up the ullage in these plants to third parties. And is there any thoughts about how that Heads of Agreement is going with government?

Yes. Andrew Thornton here. So in relation to where we are in production, you can see our guidance out for FY '23. And obviously, where we land in any year is a function of natural decline and then our workover and drilling program. What we've -- the field strength has led us to be able to reduce that drilling program over the last few years. And so we're still in that zone where we're mainly focused on well availability and optimizing existing wells. I think there is an opportunity to consider additional drilling activity. But obviously, there's a lag to that production effect. The other considerations are we're already operating at above 100% nameplate capacity in the downstream. And so the other factor in that for the joint venture to consider is domestic demand and whether that demand exists to justify an uplift in production.

And any commentary on the Heads of Agreement or the negotiation with that?

I'll pick that up. So look, I don't think I've got anything more to say other than the ACCC came out with its report. It highlighted that there was 167 petajoules of gas available. And if all of those went offshore and we had another winter like this, there would be a shortfall of 52. I'd be confident that there would not be shortfall based on the gas that's available in the market and the response by the projects. So that has obviously set up though a desire by the government to therefore negotiate the revision of that and also the Heads of Agreement, and it's probably just a little early, except that there is an intent for that. And APLNG, which we're a shareholder, but APLNG, alongside the other projects, would be involved in those discussions, and we'll work constructively towards it. There's nothing more really to say at this stage, Ian. It's pretty live, emerging, right now.

The next question comes from Tom Allen from UBS.

So just recognizing that Origin hasn't put out FY '23 Energy Markets EBITDA guidance, and the mention in the presentation that Origin remains exposed to risk of under delivery on coal. Can you clarify what protections Origin has set to manage exposure to pricing volatility and generation availability in electricity? I think it's a little clearer in gas in regard to the hedging at your JKM exposure for the next year, but particularly understanding what new things have you done to protect against that volatility.

Yes. Okay. So I might give an opening statement of that, and Greg will add more to it or Tony can add more to that as well. There's lots of, obviously, risk management that sits within a business like Energy Markets. And as it relates to coal or relates to electricity, the first thing is that we've clearly got coal contracts in place, and we've got penalties and remedies for shortfall. The terms of those are confidential, but we do have, with any contract, we certainly have a regime in place for that. We clearly have been managing logistics risk by virtue of the diversification of supply and also working with rail. So that's the other thing, because it's really a physical operational risk. And you could probably see, outside of coal supply, we've had a very reliable plant, and we've been running that very well. And it's been well maintained, and we feel confident about it. And I might just ask Greg to say, because that's really where we've been focusing. He can talk about contractual and other aspects associated with generation. So that's really the key.

Tom, let's just take the last quarter where it was extremely volatile. The first comment I'd make is that our plant performance was exceptional. So we ran everything hard. We're running our gas peakers like base loaders, and that was assisted by our gas portfolio. Where we really maneuvered in the last quarter was on coal supply. And again, it comes back down to the logistics of coal. We really worked out how to optimize the trains, working with ARTC and Sydney Rail. So that's been hugely beneficial. I've got to say, the other risk mitigant that we will do this year is that the key is to make sure that we have that stockpile at a reasonable size, because in this market, when you get shocks in the system such as there was a lot of coal-fired power plants out, and then you just have to run hard. So storage is everything in this marketplace, and that's where we will set up through both our coal contracting going forward with stockpile and our gas portfolio. Again, I just want to highlight, it is very important to maintain your machines, and we have not missed on that. In the height of COVID, some competitors selected not to do major outages. We did and the team did an exceptional job of maintaining our plants. So I think we're in good order from managing risk going forward.

Just can you clarify Origin's arrangement with the New South Wales government and rail operators to preference the smaller 4 tonne (sic) [ 4,000 tonne ] domestic coal trains ahead of the bigger 10 tonne (sic) [ 10,000 tonne ] export trains in order to get more coal available into Eraring have an end date? And then also, how much volume are you currently receiving from the Mandalong line?

Yes. So essentially, we're still not receiving as much coal from Centennial as per our contracts. We're getting most of our coal from rail. And again, each train is about 4,000 tonnes. And we're getting trains, 6 to 7 trains in some days. So that just tells you how much coal was coming down the Hunter rail network. Again, going forward, we've made real progress on sustaining trains coming into Eraring. I won't say we've finalized this, but I'm getting increasingly confident that we can do that going forward.

Okay. Okay. It sounds like it's still work in progress. Just on the outlook for energy markets...

I wouldn't say work in progress on the basis that we went from a system that was delivering previously much higher on the conveyor and less by rail, Tom. And therefore, we were in a world that was doing 1 to 2. Under the New South Wales regime, that's gone to 6 to 7. The stockpile has grown dramatically, and we've now -- I think when Greg says, we're just working through, we're not finalized, the reality is we've actually moved to an environment where I would say we're working with a more sustained level without government direction of 4 to 5 trains at least. And that's where we're focused on, and we're confident of that based on those. But it is a job that we have to manage with both ARTC and Sydney Rail and they have been very good in that support. So we're feeling better about that. Without directions.

That's right. And the additional comment is the cost of whole has already gone up to 490,000 tonnes. So we've made real progress there, Tom.

No, that's clear. And just on the outlook for Energy Markets, following up an earlier question that I think mostly related to the next 12 months. If we assume for the next 3 to 5 years that we're going to continue to see extreme volatility in electricity prices, gas prices are going to continue to grow in higher, what are the most important factors that Origin needs to see to get sustained year-on-year electricity margin growth in the Energy Markets business?

I think when you look out that period of time, what you've really got is, firstly, when you think about a default market offer, Tom, it works on a 3-year average. So you end up having a 3-year lag. So on the basis you adopt the principle of what the average cost of energy in the market is, and then that flows through, it does actually lag and flow through. So we would expect upward momentum on the premise that those wholesale prices are connected to gas and coal prices. And gas and coal through this period of time are probably setting prices at about 60%. So you're seeing a relationship between those 2, and provided they flow through to the DMO, then we would still be -- that would be really what you would see the electricity margin open up over that period of time. And we're really just highlighting that as we come through that, that we're seeing this sort of momentum, '23, '24, and the timing of that is actually going to flow through over time, and therefore, you'd expect that to continue. The gas margin, I think in the wholesale margin of the book, is largely fixed or is fixed really with the exception of our price review for the next 2 years. And we still have legacy contracts of a reasonable volume that are sitting at the old prices that go out to the mid-2030s. So we feel good about the momentum around that and you can form a view of what you think that medium-term gas price is. The last component about that is that clearly the retail cost to serve comes down, and therefore, we put the growth of the remaining balance of the business on top of that in terms of some of the other things we do. But really, it is just the flow-through. Now in the C&I market, it's really an 18-month lag, in our view, on average on contracting. So it's really -- a lot of this will be around timing. And clearly, the last thing I would say to this is that we clearly got hurt this year about shocks of not having physical fuel supply when we needed it at moments, and what we focused on our conversation to you right now is putting ourselves in a position that you're not going to need it on average when we look at this market, you're just going to need to have stockpile when events occur, and that's what we're putting ourselves in a position. If this market plays out like it's playing today where we're not out of winter and it's already back at negative prices in the middle of the day, I can't even tell you that we would burn as much coal today that I thought we were going to burn a month ago. And that's good for a business that's setting itself up like we are. But the reality is that we just need to make sure that those events that occurred this year don't occur next year, and that's a physical supply thing that manages our hedge book. That's the key.

The next question comes from Mark Busuttil from JPMorgan.

I was just interested in some of the comments you're making about the capacity mechanism earlier on. Some of the news reports over the weekend suggested that ESP's proposal is sort of dead in the water. So I was sort of interested in where you think the progress of that procedure is and how Origin would benefit going forward?

Yes. So I think on the capacity mechanism, you're right, it looks like it's been taken back by government, if that makes sense, from ESP. But I don't know if that means a capacity mechanism is dead as it relates to new capacity. That would not be my interpretation. I think that will continue because new reliable capacity will need to be there. And if there's one thing that, I think, Mark, that everyone has stared into recently is that we're relying on coal, coal is going to come out of the market and something is going to need to replace it. And therefore, there's going to need to be a signal that's strong enough for that investment to take place. What I do think seems to be debated and is fair enough, too, is how do you deal with the existing capacity in the market, and there seems to be different views across jurisdictions from what I read, I'm not talking to each of them, about how do you set up a mechanism, if it is, or do you leave it to individual states to actually manage the transition away from the existing coal so it's done in an orderly way? And I think that's probably the area that I see is less certain about whether it falls within a capacity mechanism or not. And that's probably the area that I think, as it relates to capacity mechanisms, depends on the design. But if we focus, therefore, on new capacities, and therefore, we have the opportunity to participate in that, as you know, without even seeing that today, you know the New South Wales government has got a process which will tender for long-duration storage, for short-duration storage and also for renewables. So we've got the opportunity to participate in that investment of those assets. As it relates to how we think about Eraring, we were on a path to close, but we would expect to continue to be in dialogue with state government and any other scheme that goes forward in terms of its life of operation.

Okay. And just one other thing, just in terms of your cost to serve. You have indicated you've done $170 million of your $200 million to $250 million cost savings target. During fiscal '22, it seemed like cost to serve actually increased marginally. Why are we not seeing those cost savings coming through on that line item?

Yes. Mark, it's Jon here. Just to break that $170 million out for you, that's a cash cost for you. So think about it this way, from 2018, it's dropped in cost to serve by $110 million, and the remainder is capital spend and that capital spend, we certainly don't expect to do as much as what we did given that we're now moving to the Kraken platform. As it relates to the past 12 months, we've actually seen some underlying improvement in retail costs. It's still relatively marginal where we expect more to flow into 24 once we complete the Kraken migration. And some of that is offset by investment in some of the other areas. So we certainly still remain very focused, and we do expect that the remainder of the $200 million to $250 million would flow through on cost to serve and be achieved by '24.

Okay. So just if I could clarify, so the $200 million to $250 million, you reckon, how much of that did you say was capital versus operating?

We expect around sort of $50 million to $70 million in capital and the remainder really in operating costs in cost to serve, thereabouts.

The next question comes from Nik Burns from Jarden Australia.

Just a question around your hedging position and spot and logistics exposure in FY '23. I guess just looking back in your accounts in recent years, your net pool exposure has been sort of in the 4 to 5 terawatt hours a year. Back in June, when you announced the uncertainty around coal supply, I guess, potentially a short position for FY '23 was going to be much bigger than that. And you talked about putting more hedges in place as well as maybe running gas harder and letting some customers go. Just wondering where you are now in relation to your FY '23 net pool exposure. Are you still short based on your 4.4 million tonnes of coal. And do you need to secure more coal to close that short position? Or have you effectively covered the actual position through hedges, and therefore, the incremental coal that you could procure will allow you to deliver excess electricity supply and effectively claw back any of the hedging costs you've now put in place?

Nik, good question. Look, we are square. But certainly, just to go to your point, you've covered it a bit here, is we do have the opportunity to take advantage of those low pool prices in the middle of the day. So we are careful about how much coal we do procure. And so therefore, we've procured already 4.4 million tonnes. But we're going to keep a close eye on the market, so we can you run Eraring less in the middle of the day. And that, therefore, means we purchase less coal. So if pool prices do go higher, like we just saw in the last quarter, we will certainly increase our coal contracting and run Eraring harder. So that's where we have the flexibility. And clearly, we have the flexibility on our gas fleet as well. The overall message is square to energy prices, okay? That's the key.

Great. Okay. Just one question back on coal supply. I think you mentioned you're not receiving the shortfall volumes you're expecting from Centennial. I think previously you had mentioned that was around 1.5 million tonnes. So of that 4.4 million, how much of that are you really confident of receiving this year? And that, I guess, the 3 million tonnes, that's not from Centennial, what's the duration of that? Is it just FY '23? Have you locked in any supplies for FY '24 as well?

Yes. Nik, a really good question. No, we haven't locked in future coal supply from Centennial at this stage. In that 4.4 million I quoted, we do have the Centennial under delivery in that forecast. We do expect them to deliver that coal. They have a lot of geological issues which they're getting past. So we do expect that. But if they don't, again, a real key message here is that we will then get more trains coming in from the Hunter Valley. So that's where we will adjust our position. I think the real learning experience here is that we've worked out logistics of coal. So we are not relying on Centennial because we don't want to be in that position again. The other way of mitigating this is making sure our cost of whole is at a reasonable level. So we just can maneuver and give us time to get the coal down from the Hunter Valley. I hope that makes sense, but we've just got more levers in the coal position now.

The next question comes from Max Vickerson from Morgans.

Just a quick question on -- and look, I appreciate you've touched on it pretty well in a few questions already, but I just wanted to tease out a little bit more on the thinking about the target coal level at Eraring. I do appreciate what you said, Frank, about the middle of the day being a lot weaker as we've progressed through August. But I was interested to see, at the fourth quarter report, the targeted coal position. Well, I don't know that those trends were necessarily that clear yet in the spot market. You kind of talked about those 5 million to 6 million tonne coal targets, which would imply now 11, 12 teras maybe at Eraring. So I just wanted to see, was it always Origin's view that there would be some weakness coming in the electricity market? Or is this just kind of a good win to have? And what could potentially change that dynamic do you think? Are you confident that we won't see a repeat of the outages that we saw over the winter and probably even over summer in Queensland -- the summer that just passed?

Yes. So Max, I think the key thing is that there's a broader trend going on in the market that there's a lot of installed capacity of renewables. And we can see when the sun's out, and even in recent times, we're not even in warm weather yet, we can see it has an immediate impact on the market, okay? And so can wind at the moment. So I believe that trend, and we believe that trend is going to continue. What we saw over the course of this year was a combination of plant outages and also fuel for the first time became an issue, which is not really even the outage, it was actually the supply chain of that fuel. What we're addressing is to make sure that we buy enough coal, so that fuel is on our site whenever we need it, because I think outside of key events, we're going to continue to see the trend that we were seeing up until that time and continue over time. The key point I think you answered your question on the way through is when you see such a significant amount of outages, that's what we have to be prepared for as these coal plants get older. We don't know the causes of all of those. We understand where there was fuel issues, but a number of others were just unplanned outages. And so I think that's the key risk that we can see that could disturb that overall trend. And when you've got higher, what I would call, fuel or commodity prices on the back end of that, you've just got outcomes that can move more broadly than we would have historically said when you look at really gas and coal prices. So I feel that that's one of the things we wouldn't have seen. And certainly, when we were coming due in June, we weren't knowing when a lot of the coal plant would be back. And whilst you'd like to feel you're confident around that, we certainly felt that we needed to have built a stockpile. And so that's one of the reasons about purchasing. But how much we actually utilize, I think, will be dependent on that environment. Greg might talk to you more broadly -- might be able to add to that. Do you want to talk about what you're thinking?

We see no letup in renewables coming into the system, whether it's -- we've seen some large wind farms being committed just recently. They've been built and they're allowed to come into the system. So they've got the registration process from AMA. And we're seeing that with our own stockyard wind project in Victoria. But we're not seeing any letup in rooftop solar as well. So we see the trend, and already, as some of this coal fired plant coming back into the market, we're really seeing quite low prices in all the day. So the key to this market is storage and just being ready for the events, and that's where we're well positioned.

Excellent. That's clear. Just a follow-up question then briefly on the beach contractor. Obviously, that was a bit of a focus for that management team there is on Monday. I just wanted to touch on a comment I think you made, Frank, around the reference period for that pricing reset. Can you just clarify, you're saying that it's over the last 3 years, but will that include the coming year as well? And what's your view on the potential for more recent contracts to skew the outcome? Or should we think about it more like a simple average?

I think it's a simple average over 3 years. It is -- I say I think Greg will get me going. It is.

The next question comes from Peter Wilson from Credit Suisse.

A question to Greg. Just I'm curious about how the electricity book is shaping up for FY '24. Is it a case like this year that you've locked in sales that you're yet to hedge? Or is it more square? Or are you indeed taking a short position, noting the comments around the low midday prices? And also, I guess, some comments on your coal contracting into FY '24 and whether there's a possibility of getting some makeup volumes for Centennial.

Peter, the book is square. The opportunity is we run less coal if we do see a showing out in the middle of the day. Sorry to repeat it, but overall, you should think the book is being square. We don't need to buy additional hedges at the moment to hedge C&I load or anything like that. The book is square.

And just to add one, Greg's talking about the financial contracts, and therefore, the hedge contracts, so we would be running a square position. We are yet to contract the coal for FY '24. So that's the key. We've got to contract coal. Don't think of it as anything else other than us timing the contracting of coal, and that will be making sure we balance the timing of that with also the forward price.

And Peter, just with the makeup coal, that's for this financial year coming. So we have that in place. We'll closely monitor it to see if that coal comes.

Okay. Good. And just to follow up. So the book is square. Have you effectively locked in a wholesale loss on those financial contracts? And I think last time the update was that because of the lack of coal contracting, you've been holding back on C&I, doing further C&I sales. Is that still the case? And would you start to, I guess, reenter the market once you have the coal locked in?

On the contracting side, we certainly haven't locked in wholesale losses. You can see...

It would be above our hedged contracts.

Yes. You can see through our mark-to-market gains, they're fairly significant.