Origin Energy Limited (ORG) Earnings Call Transcript & Summary

Okay. Thank you very much, and welcome, everyone. Good morning for Origin's 2022 half year results call. We'll adopt the usual format where you'll hear from me and Lawrie Tremaine, our CFO, and then we'll open up for questions. And Lawrie and I are joined by all members of our executive leadership team with one exception, Greg Jarvis, who is currently at the Eraring site. I'll just probably guide -- given we're on a call guide each of the pages we go to, and I'm now on Page 4, which is a financial summary of the half year results. The statutory loss arises from the noncash charges associated with the 10% interest sale in APLNG. And we reported that to the market last week. So that's what that really relates to. Conoco have now received further approval, and we do expect the completion of this transaction to occur in the very near future. Our underlying profit and underlying EBITDA were $268 million and $1.099 billion, respectively. And compared to the prior half, they reflect 2 key drivers: growth in the Integrated Gas earnings driven by rising oil and gas prices and a lower contribution from Energy Markets due to lower electricity and gas margins. In the case of electricity, you'll know we previously guided the lower electricity prices, but we've also had some higher costs of energy, particularly coal costs, which we'll take you through and gas has really been in line with our expectations. The free cash flow and debt reflect the underlying EBITDA. There is some higher working capital that Lawrie will take you through. We do expect that to reverse in the second half and just also to remind you that we made further equity investments in Octopus. We've declared an interim dividend of $0.125. It's above our target payout for the half year, but consistent with policy over what we expect through the full year. And really does reflect where we find ourselves in terms of outlook and capital structure. Lawrie will take you through the financial results in further detail. I'll come back and talk about outlook. The headline there really is that Origin's underlying EBITDA guidance for the financial year '22 is higher on the back of those prices that I referred to in Integrated Gas. So now if I turn you through to Page 5. So really, what we see is we see forward outlook is really quite positive momentum for us driven by both the macroeconomic environment and also the shaping of our business for what is a rapidly transforming energy landscape, and you've obviously seen our announcement today regarding Eraring in that regard. The positive outlook for Energy Markets, we've seen a strengthening in wholesale prices that will flow through to our revenue as retail prices reset and also as business customers renew contracts. They've been in part driven by higher coal and gas prices. And so there will be some offset to the tailwind of those higher prices through higher energy costs, particularly associated with our coal purchases. In the case of our gas retail and wholesale business, the higher gas prices and the tightening market is flowing through to stronger earnings and margins, and that really will show up really in the second half of this financial year and through to next. We continue to transform the retail business. We've certainly made good progress in relation to our fracking implementation, and we're bringing a number of capabilities together, we expect our customers to be on the platform completely through this calendar year. And our investment in Octopus continues to create value as it grows customers, enter new markets and also through its technology. APLNG continues to outperform, driven by strong field and operating performance. They are record revenues and cash flows from the strong growth in those commodity prices and also low development costs. The Energy Market continues to rapidly change, as you can see through our announcement today, and we'll talk about that over the coming slides. And we have substantially strengthened our balance sheet with the sale of 10% of APLNG, clearly providing us with much more flexibility to allocate our capital. Now turning to Page 6. I think you can see over the last 6 months, we've been proactive in shaping our business as the energy landscape changes. Over the last 6 months, we've made further equity investments into Octopus following the introduction of both CPPIB and Generation Investment Management. We now have over 850,000 customers on the Kraken platform being served in our Retail X business. We've sold 10% of APLNG. We have announced the establishment of Origin Zero and a new executive, James McGill starts on the 1st of March. We completed the acquisition of WINconnect. And today, we've announced the submission of the notice of closure for Eraring. And we also continue to decarbonize Origin and have committed to bring a vote back on say on climate to our shareholders later this year. Turning to some of those more material aspects over the 6 months. And on Page 7, really, just that the sale of the APLNG state has enabled us to crystallize value. And it also means we retain a significant stake. We continue as upstream operator and therefore, continue to participate in the benefits of that business going forward, which I'll cover further in the operational review. Probably if we turn to Page 8. So really, probably the big news of today is that we've submitted a notice to AEMO this morning, indicating the potential retirement of Eraring, at the end of a required notice period, which is 3.5 years or August 2025. The decision to submit that notice really does reflect the rapidly changing conditions of the National Electricity Market. They're increasingly not well suited at traditional baseload power stations and now challenging their viability. It's not a plan we've made overnight. We've been carefully weighing Eraring's future for some time, and we've also consulted extensively with the New South Wales government. It just has become increasingly clear to us that over the last few years, the influx of renewables has changed the nature of demand for baseload power. And what has changed is that there are now mechanisms, as you can see on those slides both in terms of energy and capacity. Importantly, there are mechanisms in now in place to guide future investment in supply. They do include the New South Wales road map. They include firm commitments that have been made for other dispatchable capacity to come into the market over the coming years. There's also a new transmission infrastructure, which contributes to that. And together, they are expected to more than compensate for the exit of Eraring. The notice we've submitted is for a potential closure at the end of the required 3.5-year notice period, but doesn't lock us into the timing for all 4 units, and we'll continue to assess the market, and we won't make any final decisions about timing of closure until we get closer to the date. But the notice has actually gone in this morning for those 4 units by 2025 August. I'll just reflect on the asset and turning to Page 9. I mean Eraring, it's been -- it's a very high-quality asset. We have a skilled and dedicated team. They do a great job supplying power, have done for decades and doing that reliable and affordably. And for them, we just really should acknowledge it's going to be challenging for many of them and our colleagues and also our suppliers in the local community. And our priority right now is to support them. This is the start of the process. And we will now commit to consulting with them and supporting them through any potential closure. There are no changes to the Eraring operations today. our people on site, our contractors and suppliers will continue to be required for as long as the service is still required by the power station. We're committed to funding and supporting employees during the notice period. Our transition plan for our people, which is generous, we'll work to key principles. We'll engage openly. We'll engage transparently with them and their union representatives. And we'll focus on the support package that goes to each person's situation. It will cover training skills and career planning, support to reskill, enhancing skills and practical support. It will go to deployment opportunities to roles at Origin. We will continue to fund the completion of all apprenticeships and traineeships and provide broader health and well-being support. And we'll prioritize our site employees for future long-term site operational roles, working with our subcontractors and suppliers over the transition period. And we will continue our community support out to 2032 with a $5 million commitment over the next 10 years. That's our priority today, it's really all about supporting our people and our communities, in particularly in the Central Coast and Hunter region. And that's why Greg Jarvis is there today, as you would appreciate. With the rapidly changing -- I'll now turn to Page 10. So with the rapidly changing Energy Market, I think the chart on the left-hand side shows the formation of electricity prices will continue to change, this is our view as we look forward from today through to 2030. And you can just see how that changes on a half-hourly basis. This is a market that becomes more and more suited to a mix of capacity, both short and long duration storage, whether that be batteries, pumped hydro, gas peaking plants as it continues to support the growth in renewable energy. We have progressed -- well progressed in fact for a battery of up to 700 megawatts to be located on the site. And we will participate in the New South Wales government road map process as appropriate to support the installation of as much of this battery as possible. We will also seek to bring additional online renewable and storage capacity in, including the potential expansion of the Shoalhaven pumped hydro scheme through the road map process. Origin's restoration and rehabilitation provision is $240 million based on the previous closure date, which was 2032. That will continue to be reviewed. They are expected to be incurred over several years post any closure and the timing will be dependent on the ongoing battery and ash dam operations. Now turning to Page 11. You can see here that any retirement of Eraring is expected to remove a significant proportion of our Scope 1 emissions. And it's also a big step in progressing the decarbonization of our business. And it's also delivering on our commitment to help achieve the goal for the Paris agreement well ahead of 2030. We remain, as I said earlier, committed to a shareholder vote on our climate transition action plan, and that will be held at our AGM this year, and that will include updated emission target reductions consistent with the 1.5 degree pathway. If I then take you to Slide 12, it's a slide you've seen before, and I would just repeat the message that we remain very focused on delivering for all our stakeholders. Slide 12 highlights the actions and progress over the period. And in relation to customers and planet, we've either covered that now or cover further as we get into the operational section. When it comes to communities, just continuing to grow the use of regional and indigenous suppliers. Our engagement with native titleholders and local community, Beetaloo is a priority, and we continue to be very proud of the role that our foundation plays in education. For our people, it always is a focus on safety, diversity and inclusion and leading to support our people through COVID, like many businesses have over the last period of time. On safety, our attention is really on preventing serious harm, but you can see it does concern us that our injury recordable rate has gone up with higher maintenance activity, and we just continue to strive to achieve better outcomes on that all the time. On that note, I'm going to pass over to Lawrie to take you through the financial review, and then I'll come back with the operational review.

Thanks, Frank, and good morning, everyone, and thank you for joining us on what's a very significant day for Origin. I'll start with the profit bridge on Slide 14. Underlying profit was up $41 million or 18%, reflecting the positive impact of strong oil and LNG prices on our upstream business, offset by lower forward wholesale electricity prices last year, driving lower customer tariffs this year. The positive impact of commodity prices in the half year has been partially offset by -- sorry, $58 million of oil hedging premium and losses compared with gains last year as well as $37 million of LNG trading losses and $25 million total write-off of exploration activity in the Cooper-Eromanga and Canning basins. Depreciation and amortization expense was lower due to the impact of the impairment of generation assets last financial year. Lower tax expense reflects the lower earnings in Energy Markets and the hedge losses associated with our APLNG oil exposure. Moving to Slide 15 and the one-off accounting adjustments. These mostly relate to our sale of the 10% interest in APLNG. Firstly, an impairment was booked relating to the difference between the expected proceeds from sale and the carrying value of the 10% interest, partially offsetting $105 million adjustment will be booked in the second half following completion of the transaction. This offset arises from the release of the foreign currency translation reserve associated with the same equity interest. Secondly, we have booked a capital gains tax expense associated with the sale. There is a gross capital gain of $396 million, reflecting the low tax base and a net capital gain of $173 million after utilization of carryforward capital losses. We don't expect a material cash tax payment on this gain due to offsetting tax reductions. Last year, we booked a deferred tax liability related to the expected future dividends from APLNG. In this period, we backed out $178 million associated with the 10% interest sold. Finally, we booked a further $217 million deferred tax liability for APLNG, which reflects the improved short-term outlook for both performance and expected future dividends. A reminder that the DTL booking is an accounting timing matter, bringing forward the recognition of tax expense, where the dividends are expected to be paid from APLNG retained earnings. There's no impact on the economics of the project. Having said that, the recent improvement in APLNG financial performance will bring forward Origin tax on APLNG dividends, which we now expect to occur from financial year 2023. Next, I'll focus on APLNG cash flow on Slide 16. APLNG generated $2.7 billion of operating cash net of investment cash flows in the first half. The high oil price and our ability to capture high-price spot cargoes have been key drivers. So too has been the continuing low level of development activity and spend. $1.5 billion of the cash generated was utilized on the buyback and interest on MRCPS, of which $555 million was paid to Origin. A further $350 million was spent in reducing project debt. Over USD 2.5 billion of the original $8.5 billion project debt has now been repaid. APLNG cash on hand increased by over $800 million to almost $1.7 billion as at 31st of December. This strong cash performance was achieved at an effective oil price of $73 per barrel with a higher effective oil price largely locked in for the second half, we expect full year distributions from APLNG over $1.1 billion after taking into account the sale of the 10% stake. Moving to Origin free cash flow on Slide 17. Free cash flow is down compared to the first half last year due to 4 key drivers: firstly, lower earnings in Energy Markets, which we'll cover later in the presentation. Secondly, a timing-related increase in working capital. In particular, we sold a $150 million spot cargo in late December resulting in a large increase in debt is over half year-end. This cash was received early January. So we've added the amount back to free cash flow for the purposes of the dividend calculation. Thirdly, the oil hedging, LNG trading and exploration activities I mentioned earlier. And finally, we've invested a further $260 million in Octopus Energy comprising $189 million of deferred payments from the initial investment and $72 million to maintain our 20% share following the GIM investment. The $261 million is also added back to free cash flow for the purposes of the dividend. Slide 18 fast forward to how we see our capital structure by year-end. Our approach to capital management is broadly unchanged. The 10% APLNG equity sale will take leverage to the bottom end of our target range and perhaps even below with the prospect of further improvement in the year ahead. This being the case, we've now increased flexibility to invest in targeted growth and deliver returns to shareholders. While we continue to target a free cash flow payout of 30% to 50%, the Board has declared a $0.125 per share dividend of it's unfranked, representing a 66% payout of the first half free cash flow. Cash flows are expected to be stronger in the second half, so full year dividends will potentially fall within the target range. We currently anticipate the dividends in relation to the 2023 financial year earnings could be partially franked. Turning now to Energy Markets earnings on Slide 19. EBITDA was down $367 million or 58%, with the decrease coming predominantly from lower electricity earnings. Electricity gross profit decreased $281 million, primarily driven by the $17 per megawatt hour decrease in unit margins. $260 million of which was related to lower wholesale electricity prices flowing into customer tariffs. Wholesale energy procurement costs were $58 million higher due to higher coal and gas generation fuel costs and higher green scheme costs, partially offset by a decrease in swap contracts and other energy procurement costs. Improved management of customer value and the recovery of prior year network costs provided a $43 million positive contribution to earnings. Lower retail volumes of 0.3 terawatt hours was more than offset by 0.7 terawatt hour increase in business volumes due to contract wins, but the unfavorable sales mix change resulted in a $5 million reduction in earnings. Gas gross profit reduced $79 million, gas procurement costs increased as a result of higher JKM linked supply costs, the roll-off of long-term supply contracts and contract price reviews. The higher procurement costs were partially recovered through customer repricing, including oil link sales. Our JKM price exposure has been fully locked away through the balance of the current year and to a large extent for financial year 2023 also. Based on this position, we expect to see improved earnings as higher gas prices are fully reflected in contract prices and tariffs. Gas sales were 11.8 petajoules lower due to the expiry of business volumes, partially offset by higher retail customer numbers and demand. Cost to serve is slightly lower with further savings expected as the fracking implementation is completed. Turning finally to Integrated Gas on Slide 20. We have equity account at 37.5% of APLNG up until 8th December. At which time, 10% was being held for sale, and then we've accounted 27.5% thereafter. EBITDA would have been $46 million higher in the first half, but for this change. Even with this pending sale impact, our share of earnings was up $526 million, primarily due to higher LNG prices both oil linked contract pricing and spot. The realized effective oil price after hedging was USD 68 per barrel compared to $38 last year. We shipped 3 high-priced spot LNG cargoes in the half with a further 6 cargo sold for delivery early this calendar year. Operating costs were $109 million higher, mostly reflecting higher royalties and also higher purchase of gas during the major downstream turnaround. So with that, I'll hand you back to Frank with our operational performance review.

Okay. Thanks very much, Lawrie. I will now turn to Page 23 and go through some of the key highlights regarding Energy Markets. Really -- Slide 23 really shows the tailwinds we now have from the higher wholesale electricity prices and that can be seen on the left-hand side of the chart, partially offset by higher energy costs, in particular, coal that you can see on the right-hand side. But really the chart on the left highlights those wholesale prices. The yellow line is really what forms the basis of our customer tariffs this year. And the blue line is really what forms that forward price, what forms the basis of the tariffs in the next financial year. So the recovery in those wholesale prices, they've really been driven by both higher fuel costs and some baseload outages, but you can see just the trend over the last 3 years as to how they've moved. One of those fuel costs is coal. And so you can see on the right-hand side we've highlighted the 6,000 spec coal at Newcastle and that surprised us over time. We buy coal at 5,500 spec. You can see that by those blue diamonds where we've executed deals over the course of the period. I'll then take you to Slide 24. We'll just go through the cost of energy that's been impacted by coal supply constraints. So that's really what over the last 6 months -- over the recent months, I should say, what our major coal suppliers encountered operational issues really associated with the mining of their coal and also COVID. And as a result of that, their contracted coal deliveries to us have been lower than expected. And we do expect that to continue in the second half. That's led to a Eraring volumes being lower, as the first, as you can see on the left-hand side chart. It's also led the need to purchase coal at the higher market prices when we needed that over summer. And the lower output from Eraring has also been replaced by swap contracts and pool purchases. The combination of this has led to the higher cost of energy in the period and we do expect to recoup the deficit in those contractual deliveries, but that will occur through into the financial year '23. Turning to Slide 25. The outlook for the gas business in Energy Market has improved. That's on the back of the tightening domestic gas market. You can see the domestic gas prices. They haven't risen anywhere near those LNG netbacks. They remain below, but they've certainly improved recently. And our gas portfolio was positively exposed to that trend. In terms of our gas supply portfolio, we've obviously got it underpinned by fixed supply contracts that you can see there on the right. And our JKM linked supply is fully hedged this financial year and all hedged with the exception of 4.5 petajoules in the next financial year. And there are no further price reviews until the financial year '24. So that's leading to an improved outlook for that business in the second half of the financial year. Now turning to retail on Page 26, and we're continuing to build our next-gen retail business for the benefit of our customers, and that brings together really technology, a new operating model, growing the scale and products of the business and also involves us entering into both investments and alliances. And so as we do that, I'll now take you to 27 to show you the progress in terms of outcomes associated with that build-out. And you can see there that Retail X has over 850,000 customers now migrated, good customer happiness and we're on track to migrate all of those customers this calendar year. The capabilities and then the culture and the operating model that we bring together have led to improvements over recent years in our customer experience and reduce cost but we set our targets higher again. And so as it relates particularly to cost, you can see there that we delivered $110 million of savings against that FY '18 baseline, but targeting a further $100 -- essentially $100 to $150 really to arrive at $200 and $250 savings by 2024, and that's both operating and capital cost savings. The key driver of that will be the implementation of this model and the implementation of the Kraken X technology coming together for the benefit of a lower-cost retail model. Turning to Slide 28. We are growing scale and products win. There is an increased appetite for multiproduct offerings by consumers. And during the period, we've grown broadband. We -- our community energy services and also LPG. In addition, we have over now 100,000 connected assets or in excess of 200 megawatts on what we call Origin Loop, which is essentially our virtual power plant for our retail business. Which really that, in essence, allows customers to optimize energy use and costs and also allows Origin to optimize distributed assets in the portfolio. So it's good to see that growth. And as I mentioned earlier, we've completed the acquisition of WINconnect, which will continue to grow the community energy services business once again. Turning to Page 29. Octopus has continued its impressive growth and now has a presence in the world's 7 largest deregulated Energy Markets. They're growing their business through retail customers. They're growing their business through customers licensed on Kraken. And now also growing their business through renewable assets and other services like demand response, which they KrakenFlex. They now have 5.8 million customer accounts across the U.K., U.S., Germany, Spain and Italy. They've grown to 11% market share in the U.K., which I think now -- we think now makes them the sort of fifth largest retailer. They have continued to grow their licensed customer accounts and now have 25 million contracted accounts there. And that's going to provide revenue of GBP 500 million in licensing over the next 3 years. They've introduced 2 new shareholders to the register, both Generation Investment Management and CPPIB. They both invested in Octopus at a valuation of around GBP 3 billion. It's been well reported, there have been very challenging conditions in the U.K. Energy Market, and I'm pleased to say that Octopus has successfully navigated this period. They have incurred a higher cost of energy but that's actually also been reasonably offset by trading gains and licensing revenue growth. And overall, when we look at our financial year '22, we're currently forecasting our earnings to be broadly in line with our expectations. They have grown at the same time, much faster than we expected in a market that's consolidated as a result of many retailers leaving the market and where Octopus has acquired 1 million customer accounts from Avro Energy. So a very positive trajectory in relation to our -- the Octopus business. I will now take you to Integrated Gas, and that takes us to Page 31. And really, they've again delivered -- we've once again delivered in APLNG a stable production. And that's despite wet weather, and we also had planned LNG maintenance in the period. It's a quality resource. There has been some field decline of Spring Gully, which has been offset by improved performance in Reedy Creek and Talinga/Orana. The strong field performance, the continuous improvement may have driven reduced activity, and they've driven good cost management. And really the higher operating costs in the half largely reflect the planned LNG maintenance and higher power costs. We continue to maintain our forecast of $3 to $3.40 a gigajoule this financial year. Turning to Slide 32. It really does highlight the reduced activity over recent years in terms of the number of wells drilled and commission. That led to further reductions in sustained CapEx. There are a number of initiatives underway that have driven outcomes, whether that's the use of digital tools, the installation of downhole gauges, all of which are improving production and also going to lower our emissions. And the facility utilization, both in terms of our gas processing plant, but also the LNG plant have been very high at times when the price has been high. I'll turn you through to Page 33, it just builds on what Lawrie said earlier. You can see the record revenue there, which is really the combination of those higher realized oil and spot LNG prices. 3 spot cargoes sold in the half, a further 6 to be delivered in the second half. And domestic revenues also grew strongly, and that was primarily driven by short-term sales when there was downstream maintenance of that LNG maintenance I talked about just before. Turning to Slide Page 34, I think gives a good picture of what has occurred over the last 3 or so years. So since June 2017, APLNG has repaid $2.5 billion in project debt, and it's replaced 91% of its 2P-operated reserves since the financial year '18, showing really the strength and quality of APLNG asset and its importance to Origin. I'll take you to Page 35 as a highlight on Beetaloo in our Velkerri dry gas play, the Amungee NW 1-half production test -- sorry about that, the Amungee well production test indicates normalized production, results that are comparable really with other commercial shale gas plays globally. We're going to use that existing well pad this calendar year to drill 2 horizontal wells. And to frac and production test those. We continue our core analysis in relation to the Velkerri liquids play. And where we have preliminary results that indicate the presence of wet gas and our farm-down process is underway. In the Canning, the Rafael well 1 preliminary results, they do indicate liquids-rich potential gas. We're looking to undertake production testing as soon as we can, that has been impacted by COVID. So we're working hard to get back there as soon as we can. And in relation to the Cooper-Eromanga we've written off Obelix-2 and additional permits were required to evaluate the Toolebuc further. So we're continuing to do work in that Toolebuc. Now just taking on to outlook, which is contained on Page 37 and 38. Really, the guidance has changed in one respect, the underlying EBITDA for Origin this financial year has now risen from 1.85 to 2.15 to now 1.95 to 2.25, and that's really on the back of the strength of those commodity prices in APLNG. When you look down, you'll see that the only other changes are the higher investments associated largely with Octopus and WINconnect. And you'll see that the cash distributions despite the sale of the 10% of APLNG and now forecast to be greater than AUD 1.1 billion net of the oil hedging. So the outlook really for '22 is stronger overall. There is further information provided on Page 38. I've mentioned really that consolidated outlook for Origin this financial year. You will see that in the case of Energy Markets, we've held our guidance. It's a story of truth though in that the electricity contribution will be lower than previous guidance due to the coal constraints that I referred to. And gas will be higher because of increased volumes and the improvement in the gas market. In relation to the next financial year, we've retained guidance to improve by $150 million to $250 million. That does obviously assume the higher electricity and gas prices continue to flow through tariffs and reflects higher coal costs, the existing fixed supply gas contracts and also Kraken cost to serve savings. In relation to Integrated Gas, you can see I have referenced most of those. One thing you'll notice is that we have not included the breakeven. And the reality is that we've had such strong revenues coming out of our non-oil-linked contracts. You're finding that, that breakeven is now very low, if not negative. So it really is a focus on us really targeting total CapEx and OpEx and continuing to maximize those cash flows. And you can see the following settlement of the 10%, our oil exposure associated with the 27.5% investment in APLNG is estimated to be 17 million barrels equivalent for the financial year '23. So on that note, I will pass you over -- we will hand over and we'll commence questions. So thank you very much.

[Operator Instructions] Your first question comes from Max Vickerson from Morgans.

Just a quick question. It was probably more on a Greg, but unfortunately he is not here, but hopefully, might better speak to it anyway, just with the Eraring potential earlier closure. In the past, you guys have talked about maybe changing the operational methodology to maybe looking at a double shifting approach where you maybe have to start today. Is that something that's possible if you've got a shorter remaining life. Can you maybe squeeze a bit more or optimize the running profile a bit more?

Yes. So Max, I'll give you a broader comment around that because the reality is it's all about flexibility. And so clearly, we are balancing both having the reliability when we need it and promoting that flexibility. Clearly, that's a trade-off and we'll continue to do what we have been doing. We may be able to eke out more flexibility, it but really will be a trade-off against the -- making sure the ongoing investment makes that reliable enough. But clearly, we're all about maximizing the flexibility but also making sure that capacity is available when we need it. So that's really the point. I wouldn't want to be drawn more specifically into the operating because I think we'll continue to assess and optimize that over the period.

Fair enough. And then just one more, if I can, on what happens post '25 once Eraring shut Can you remind us what the average duration is for your renewable PPAs? Is that enough to meet your LREC commitments? And how does that compare with Origin's broader carbon targets? .

Yes. So sorry, I'll have -- you've asked me for the PPA duration. It's not a -- I don't have that top of my head, but I'm happy for us to come back to you on that, Max. I just don't have it there. What we do as -- we have PPAs. A lot of those do go out to 2030 and beyond, but I would come back with a more specific answer for you, happy to do that. But essentially, what it looks like for us is you get beyond the closure of Eraring is that we see it's essentially going to be -- firstly, when you think about capacity, it's a mix of storage, it's the gas generation plants we have. It's demand management and distributed assets coming in. It's obviously also our contracting in the market and the various contracts that we have as well. But that will obviously sit alongside renewables coming in because, obviously, the cost of energy is both the cost of that capacity and the energy. And you would -- yes, we will continue to look about the investment and/or contracting for renewables to come in as appropriate as that market evolves. But yes, that's really how we do that. But I'll come back with specific answer with duration. Most of those PPAs go out, the balance of this data, it is my understanding.

Your next question comes from Mark Busuttil from JPMorgan.

Just a couple of things. And if I could start with Eraring. Did you ever consider selling it? I mean, have you commenced a process or would you consider commencing the process of selling it rather than actually shutting it? And then a related question, is it actually any money at current wholesale prices?

Yes. So 2 things associated. But firstly, the notice period, Mark, requires us to give 3.5 years. So we're forming a view of what the market is like out of 3.5 years. And so today is really the start of a process. And so we will consider all reasonable options between now and then. So we have thought about it pretty clearly, and that doesn't mean we won't consider that going forward, but it does come down to how we think the evolution of that site will be used for batteries and also how we think the market plays out. And you would expect us to assess all of those. We've carefully weighed Eraring's future when we've come to this decision. But it's the start of a process now, Mark, because it's 3.5 years' notice. And we will now consult the employees and unions to work through that. As it relates to Eraring, there's been -- we obviously capture a price that's better than the time-weighted average price. It's generally probably 15%, 20% higher. We've certainly seen prices coming in at the cost of coal coming in over recent times, that would be more challenged. But I'd have to say, if you're linking the 2, they're not really the driving because we're also going to see recovery in wholesale prices occur, and we'd otherwise -- have to go out and purchase a lot of capacity. So the economics is broader than just the fuel cost, and the short run marginal cost for us. The thing is that we really have CapEx and OpEx essentially largely fixed of $200 million to $250 million a year. And as more and more renewables come in to the system, it continues to have to run, they more and more as a capacity plant, and therefore, that becomes challenging over time. And if you're therefore, looking forward to the capacity that's due to come into the market as well as what might be announced under New South Wales road map, we're making an assessment of where we see the economics of that over time and having to make what is a difficult decision, but nevertheless one based on that. But yes, clearly, we will -- it's the start of the process, Mark, and we will continue to work through that with all options ahead of us.

Okay. I do want to ask you about your fiscal '23 guidance. But just before I get to that, one last thing on Eraring. I know that you've mentioned a couple of times you've had discussions with the state government, but have you -- is Angus Taylor and the federal government aware of this? Or are we going to see comments from him in newspapers similar to what happened with Liddell?

Look, certainly, I've spoken to Angus, but in terms of consulting over a longer period of time has been in New South Wales, but he's aware. And I don't know that will be up for the government. What I'd just say is that the governments have made decisions over time, which I think have been all to prepare for this transition. And it's as a result of those decisions we see a lot more capacity, transmission and announced frameworks coming in that give us the confidence to make this decision today and for the market to navigate that capacity being available when it's needed in the future. And yes, I think that from our perspective, we'll continue to work with the mechanism, the 2025 capacity mechanism. But yes, we're just all working -- we work with all of the governments and in itself we see ourselves today in a situation where we think this is the right decision. It's a big decision. We think it's the right decision strategically, but that's where we take it from now.

Okay. Very last thing, just in terms of the guidance numbers or the target, I guess, you provided for Energy Markets in fiscal '23. Obviously, since the original provision of that electricity prices have gone up like 30%, 40%. I'm a bit surprised that you've reiterated that. Can you give us a sense of how much conservatism is built in there? Or is it -- is the entirety of the wholesale price increase offset by higher fuel costs?

Look, it's really a judgment of the -- you can observe where the wholesale electricity cost is and it's really a judgment, Mark, around where we'll purchase that coal into the FY '23 year. And so without being specific, that's got a range of outcomes. And therefore, that's why we formed a view regarding that guidance. What we've seen is the gas that we had foreshadowed to occur next year is actually almost being brought forward into the second half, which has held the guidance for this year, but it really is just around a range of those outcomes, Mark. And that's why we provide the range we do.

Your next question comes from Tom Allen from UBS.

Frank, just again, the question, just following up your plans to close Eraring Power Station in 2025. Just given that Eraring is obviously important to the portfolio and providing baseload power peak capacity in caps. Can you share some color directionally on how to think about the change in EBITDA contribution from Eraring compared to a large scale for our duration 700-megawatt battery?

Okay. Yes. So yes, I think -- so firstly, Eraring is running increasingly at lower capacity compared to several years ago. So each role is changing as well, but you understand that because we've reported that previously, and you'll get a sense for the sort of terawatts we produce on it. The way I think I described because batteries play only one. I know it's very clear that you can put sort of the fixed cost or fuel cost and therefore, the average cost you should expect to receive from Eraring over time. And therefore, we're forming views as to how those prices will form over time. I think I describe it to you is that when we think of the margin going forward and think about it in the post-Eraring world, in the Energy Markets business for electricity that is, that you'll have, in fact, 3 components of your margin. You'll actually have your retail margin, which you can understand through the DMO and that will be set by pricing that's set every year. It will have -- in our case, we believe we'll capture further margin through the technology we deploy in that operating model largely through Kraken. And then when it comes to wholesale margin, you have to think about the cost of energy through both the cost of the capacity and the energy. I think you can actually see that as more energy comes in, you'll see that coming through is renewables, but increasingly, that will provide the energy and then the capacity of the mix of storage will be those peakers plus the battery storage plus demand management and it will be also those contracts that we've entered into historically. The difference for that is that really you are capturing the difference between prices moving up and down in the market. And therefore, capturing the benefit of prices when they're low in the day through a particular setting and then as they rise, but over peak periods also capturing a 3-year peak plants. And I recognize that's a more complex equation for people like you to get across and the model. But we'll have more to say about that, but that's essentially how that works. And therefore, generally, the batteries that are coming in at the moment would come in at short duration. We expect that over time, that might improve in duration, depending on cost and economics. But essentially, it's going to be that combined with our peakers and other contracts that will combine together to provide that capacity cover far less capital-intensive way. And we just feel that the combination of the economics of those are going to be more attractive now relative to the high ongoing fixed cost of the Eraring being incurred and continually being pushed to run faster and more flexibly and that's going to make it more difficult over time. And that's why people see that acceleration. But that's really -- the economics is really that capture. Now in batteries to further that answer, it really is also about you'll have ancillary services and other forms of revenue, but that's essentially what that's associated with. And we recognize that we will have to continue to communicate and help people understand how that margin gets captured and then give you the confidence about how we bring that to life.

Okay. That's helpful. So it's all about capturing that increasing in intraday price spread is the way to look at it?

It is that and it also will provide, obviously, capacity for whatever duration that battery is available, but it will be a shorter duration. And as it gets longer, you need to pick that up either through your hydro or your gas. And therefore, that does also have a seasonal and other event-based benefit, but it will be the combination that delivers that. In the short-term, batteries will pick up, you're right, that intraday as well as other services that are available.

Sure. And then just regarding your coal supply and price exposure, the additional detail on the short-term deals you recently executed is helpful. But given you've got that 4 million tonne coal supply contract expiring in June, can you just clarify a little further on how you're going to manage that coal supply and price risk via contracting over the next 18 months? .

Yes. So we're in negotiations right now, Tom. But just to be clear, there will be under delivery under that 4 million tonne contract this year, and that's what we've baked, we've included in our guidance, not only for the half year, but for the full year. So we would expect to have volumes from that contract also going into the '23 year, so there will be some volume associated with that. And then we're obviously in market with our key suppliers and continued negotiations on the balance of the contract. So that's probably the 2 things that are going on in the business there, yes.

Okay, sure. And then just quickly one last one. Just following up your comments on Octopus' exposure to rising energy costs in the U.K. Can you just share any color on hedging or contracting that Octopus has in place that give us confidence there will be no material exposure to gas shortages and very high prices?

Yes. So they did have some -- they've certainly been able to manage that. They've got very good hedging practices in place. That doesn't make people immune from some of the squeeze and that spread that can occur because there were contracts and retail that have caps to them. And you'll know that it was recently reported caps have been listed in the April period. But they did get some offset through some trading benefits and also some licensing revenue. What I'm giving you confidence overall is that, that's actually been -- overall, with all of those parts, it's been very effectively managed, okay? And therefore, not a big driver of the earnings one way or the other this year. That's for our June '22, recognize it has been quite an interesting period.

Your next question comes from Rob Koh from Morgan Stanley.

Can I maybe ask a question of Mr. Thornton, I guess, given this might be his first result call in the role. Just wondering if we could get an update on how the company is thinking about the Beetaloo developments in the context of FPT obligations? .

Okay. Yes. So did you -- Andrew, did you want to have -- did you say Mr. Thornton by the way?

Yes, that's what I meant.

Yes, that's fine. Andrew, you're happy to open up and I can come in if the...

Rob, so certainly, we'll -- future developments of our upstream resources would be done in a way which is consistent with our decarbonization objectives and commitments. And the way we think about that is really in a couple of areas. So certainly, for a new port where we have the opportunity for it to plan for new development, we would engineer our Scope 1 emissions in the way we designed the field and the plant. Scope 2, I think there's lots of opportunity there for renewable energy to power the field and then Scope 3 is all about working with customers moving forward. So certainly, any development of Beetaloo moving forward would be consistent with our overall objectives.

And does that kind of skew you more to export type markets with -- given the Scope 3 element of it?

I'd say it's still too early to form a view on domestic versus export. I mean what we said is we're going to be prioritizing initially the Velkerri dry gas play. I think as we move through the next stage and drill the next couple of wells, we'll have a better sense for which markets will be targeted and for which products.

Yes. Okay. Maybe can I ask a question, this might be either for you, Andrew, or perhaps Mr. Tremaine, but just thinking about oil hedging costs, I guess your exposure is less with -- after the sell-down in APLNG and there's obviously a lot more margin for safety on the credit rating. So should we be thinking about the level of hedging in those premiums going down?

Mr. Koh, it's Mr. Tremaine. Yes, thanks for the question. You've sort of answered your own question, but yes, indeed, our exposure to oil measured in barrels has reduced substantially, and our balance sheet is in a stronger position. Obviously, we have to continue to look at that going forward with -- and look at it through the prism of protecting investment grade, but obviously, there's a bit more of a buffer to investment grade today than it was -- with the proceeds of the 10% sale than there was -- has been previously. So given that, you would expect less hedging going forward.

Okay. Cool. And then maybe just one last question. This might be something for Mr. Jarvis, I guess, and feel free to come back later. But I noticed in the Energy Markets, electricity gross profit, there's an item of $61 million negative for green schemes. I'm just wondering, is that a timing thing related to surrender? Or is that -- should we be thinking about that on a full year basis? .

Okay. Greg is not on the call for that, unfortunately, Rob. Yes. Looking in any given period, you're exposed to the -- if you like, the wholesale cost of green schemes and you'll recover that through tariffs on a lag basis. So I think that timing would be the way I would characterize that. If any nuances -- Tony, so I'll just check Tony Lucas whether there's any nuance in that you want to.

No. So there's an increase, Rob, in things like the [ RET ] schemes or some of the other schemes then that just lags on the tariffs. So you end up in the cost in the same year, and that flows through to tariffs in the following years.

Your next question comes from Dale from Barrenjoey.

A couple of quick questions. Just trying to connect the dots on coal constraints, the 4 million tonne contract on the delivery and what this means is for coal availability versus generation for Eraring going forward? And maybe just, I guess, Slide 8, the circa 14 gigawatts and our generation '22 and '23? And then declining thereafter, is that how we should think about generation from the asset going forward?

Yes, I think we -- so I think the running of it -- just be clear, I think we would expect to be consuming about 5 million tonnes of coal on our outlook for this year, there or thereabouts. That would equate, I think, Tony, get me if I'm wrong, I'll just make sure I've got my numbers right here, but that would be about 11 terawatt hours, Tony. I think that's right, isn't that right? Is that's about right?

Yes, it's about right.

Yes, that's about right. It does depend on events through the year, but we're not constrained by coal. There are other sources of coal. We've obviously had a supply dial over time that's been characterized by -- underpinned by a sort of 4 million tonne contract and then supplemented by short-term contracts as we also have the rail facility. We would expect that to be a combination going forward. So we don't think those constraints our -- again, there's going to be a coal constraint. It will be just around the negotiations of the various contracts, which are underway now. I think what really drives it more than anything is how do we think the plant will need to run when you need to provide that capacity over the year and depending on events as you know, over the last couple of years, we'd have to run that harder as we did in the final quarter of '21 when there were outages. So I think it's more driven by that and the market events. And then it's really about a combination of supply that comes from those sources.

Okay. And then for the FY '23 Energy Markets guidance that was provided, what had been assumed in terms of -- is it really coal costs at the time when it was provided around sort of July, August and middle of the year? Or which have obviously increased as per Slide 23. And what sort of volume would it assume the whole thing, obviously, undersupply extended into next year, no rollover of cheaper coal?

No, no. So what we have -- just so you're aware, because the existing 4 million tonne contract won't deliver on those volumes this financial year to the full extent. We do expect to receive coal from that contract in the financial year '23 to make up for that shortfall on deliveries this year, okay? So that will be part of what we've expected. And then you're right, there is also then an assessment around what we will pay as the market price for those coals under the various negotiations underway. And therefore, we've got, as you would expect, range of outcomes associated with that as well as we've seen a pretty dynamic movement in the wholesale electricity prices. It does have a lag. Just going back to Mark's comment earlier, and you'll get a lag of that through to the tariffs. It may not all flow through next year. And therefore, it's just really based on those range of outcomes, the whole combination of the delivery of that contract volume shortfall makeup plus what we enter into for contracts for the balance of the coal, recognizing we don't really buy export coal, we buy coal at a lesser grade. So that's the balance.

Okay. And then just finally going forward to end of life, are you looking to contract out to '25? Or will it be more of a 12-month rolling process?

I think it does come down to term and price and everything. So clearly, it doesn't mean we have to be contracting on a 12 months. We're probably likely to do a bit of a mix of those 2 things, but maybe not going out all the way to '25 today. It will just come down to basically term and price. It's a pretty dynamic coal market. We've got suppliers that have been with us for a long time, and we'll just continue to keep you and others informed as to how we contract that. But yes, it's really a balance. Balance is really underpinning it with some term and then some shorter term to top up. That's really the way to think about it.

Your next question comes from Gordon Ramsay from RBC.

Frank, I have question about your Energy Markets, you contracted gas supply and price reviews coming up. I might be mistaken, but I thought there was an 8 petajoule contract in the Cooper Basin this year. It was up for price review. And I guess the question is, if the pricing you receive in a price review is deemed to be high from your perspective, what kind of flexibility do you have on nominations with, let's say, your normal contractual positions?

Yes. So there are -- I think that the Cooper one, you're now starting to test my memory, with the Cooper is done, I'm pretty sure. So I think that's all been done. I don't think there's another one coming up on this, unless I'm mistaken anyway. The -- and I'll put that on notice to Tony, because it's not certainly on my radar that there's another Cooper. We've been certainly locking away all of that. We certainly have nomination flexibility in our gas contracts, as you would expect. They're just similar to all of them that we actually, therefore, have certain contractual tolerances, we can nominate cheaper contracts and/or by spot. That just really is what we do throughout the year. So that's -- we'll continue to manage that portfolio of supply within those tolerances. But yes, that's how we manage our gas. As to the price review, I'll just make sure the team come back, but I'm pretty sure that's been done, So yes, it's not been on the back of my mind.

If we're looking at percentages, I know you've got seasonality obviously, but is it like 10% like on the LNG contracts where you can go 10% up or down?

I don't -- I mean we really don't -- those contracts are confidential. I mean we just -- there are tolerances within them. So I just -- I prefer to leave it there.

Just on LNG and spot cargos, congratulations, I think the guidance previously was 5 spot cargoes in the March quarter, looks like it's 6 now. But I think -- and maybe it's Lawrie question on hedging. You've been able to hedge some of that JKM pricing. Can you give me a feel for what levels that's at or what instruments have been used to do that? And the basis risk?

Lawrie or Andrew?

I'll just ask Gordon, is your question in relation to LNG trading? Or is it in relation to our Energy Markets business and the cost of gas going into that business?

The trading side.

Yes, right. So we would to the extent that we can, we would hedge out that exposure because it's a trading business. So typically buy resell type business. So we would seek to close out any commodity risk or basis risk as we put those contracts in place.

And Gordon, just confirming Cooper has been done as well. I just had Tony check it through me there for a moment, but the Cooper price has been done with.

Okay. Is we're forecasting higher pricing in the March quarter at JKM, let's just hopefully -- you can capture some of that?

We would -- if you're asking that about both businesses. I mean, clearly, we would see some of that benefit obviously coming through those spot cargoes and Andrew's peaking at every petajoule, gigajoule, and then it comes down to how -- who we're selling customers to in the domestic market. And you're right, there will be a combination of customers that's on fixed, and there will be some that will take JKM linkage. So we're certainly thinking about that as a portfolio of sales in the second half.

Gordon, I missed the fact that you were talking about the spot cargoes. So they'll be priced according to the period in time which has sold so that they would reflect the market price at the time that they're sold.

Your next question comes from Peter Wilson from Credit Suisse.

Lawrie, I might actually follow up that question on JKM, actually could be, Frank or Lawrie, Energy Markets, can you talk about whether you expect the overall portfolio margin to increase into FY '23 versus FY '22? And specifically I'm interested, is the increase in domestic C&I and revenue prices across the portfolio. Is that enough to offset the increase in JKM costs you expect?

Yes. So broadly, Peter, we're obviously seeing -- when you saw the guidance we go to '22, you'll see that gas is stronger over the '22 period than when we previously guided. And effectively, what's happened is that the market dynamic that we all thought might have occurred in the gas market has ended up occurring a bit earlier than we thought. Our view is that between '22 and '23 earnings are pretty broadly in line for the gas contribution. So the answer to your question is yes. Therefore, our outlook for the gas business is a similar contribution for FY '22 and FY '23. Some of the benefit that we were seeing come back in that gas business to '23 has actually been -- brought forward to '22, if that makes sense in the second half. That's the way it's really playing out for us.

Okay, perfect. And on Eraring, so sort EnergyAustralia locking the deal with Victorian Government to extend the operation will be your long plan by a few years. So you said earlier that you've been in discussions with state and federal government. Is that kind of deal being put on the table? And should we consider that an option, there might be some sort of underwriting to extend the life or should we consider it completely off the table?

Yes. I said we certainly consult in New South Wales government for some time. And that's the reason for doing that with the New South Wales government is that clearly, they have a road map process in place -- and their preference is for everything to go through that road map. So we certainly explored options with the New South Wales government and we've landed in a position where they will continue to utilize their road map and look for more capacity and/or energy in accordance with those terms and will participate as appropriate with that. As I say, this is the start of a process of submitting the notice, Peter, and therefore, we'll continue to assess the market and continue as I've been asked before, there's a lot that can happen over the next 3.5 years, and we'll just continue to assess that as we get closer to the day.

Okay. Because I guess the timing is slowly coming in and -- road map is pretty anxious about ensuring that capacity comes in ahead of closures, and I guess, takes in the context of 2027 time frame. So I guess...

What coming in? Yes, you're right. There's timing of what comes in as a consideration as also will be what does the New South Wales government want to come in between now and then as well, which is within their power. So you're absolutely right. There are mechanisms but also firm commitments and clearly, there's timing associated with all of that capacity that we'll continue to watch. Yes.

Your next question comes from Ian Myles from Macquarie.

I'll just talk on APLNG firstly. The primary customers, have they exercised options to flex up? And I guess you've done really well selling 6 spot cargoes, but you have much left in the system to be able to sell more spot cargoes on a -- for the residual year.

Yes. Okay. Andrew, I'll let you take that one.

Yes. I mean first thing to point out, obviously, is we are bound by the terms of the ADGSM HoA, which requires to offer that any uncontracted put through the domestic market for maybe the first principle. We have disclosed that we've sold another 6 spot cargoes into the second half. We don't disclose -- we don't provide guidance on second half sales, but I would say we intend to run the plant and expect to run the downstream plant close to full capacity as we have done in the first half. And then probably the only other data points to provide there that might be helpful is on average, usually we run about 10 spot cargoes a year to provide some context there.

Okay. Secondly, there's a real gap between the international energy price and the sort of the Australian or domestic energy price. This sort of intrigued what you guys are thinking and how that may correct itself given suggestions of import terminals in New South Wales, whether the economics of these are going to work and how you manage that risk over '23 and '24?

Sorry. Was that in relation to JKM prices you're referencing?

It's just you've got both oil-linked and JKM materially above probably where the Australian number pricing is. That's just maybe not sustainable, but politically unpalatable. I'm just sort of intrigued on what you're seeing may occur?

Look, I think it's as much to overseas. I think there's at the moment, do I see contracting as a very high netback crisis? I'm not saying that in the market, but we're seeing obviously the strengthening of those domestic prices, there will still be. It's a contract market largely as well and so it comes down to what are people are prepared to pay domestically. Yes, I'm not sure how it squares, but I think as much of it as anything, is driven by the situation in Europe and our geopolitical as to whether people are assuming that it can sustain itself. I think ultimately, in the domestic market, there will be a cap out as to where people just won't tolerate higher prices. So I feel that that's the managing balance there, the 2 forces of play, to be honest with you, Ian. You can see the spot cargoes going out. People are reviewing to the ADGSM, and people domestically should be pleased that those prices haven't found their way to be anywhere near where they currently are overseas. So yes, and hard to see how the domestic market will go right to that very high prices that you're currently seeing in the short-term markets there. Yes. But never know. Never know how this is going to play out completely, yes.

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

Okay. Thank you very much for your time. We always appreciate it. We know it's a busy day, and there's obviously a lot going on with Origin. My apologies that Greg couldn't join. I'm sure you understand that. We will provide more opportunities to the extent you've got questions over the coming hours, days and weeks. Hope you have all a good day and speak to you all soon. Thanks very much.