Origin Energy Limited (ORG) Earnings Call Transcript & Summary

Thank you for standing by, and welcome to the Origin Energy Full Year Results Teleconference. [Operator Instructions] I would now like to hand the conference over to Mr. Frank Calabria, Managing Director and Chief Executive Officer. Please go ahead.

Okay. Thank you very much, and good morning, everyone, and welcome to Origin's 2021 Full Year Results. Thank you all for joining us and probably acknowledging that many of you, like us, are in lockdown. And just to let you know that Lawrie and I are presenting remotely, and we also have the rest of our executive team in attendance as you would normally expect. I'll give a short introduction, then Lawrie will go through the financial review, then I'll come back and give an operational update, strategy and outlook, and then we'll go to questions and answers. Before I start, I'd just like to acknowledge the traditional owners in all of the lands that we are meeting today and all the lands that everyone is participating on this call today and just pay my respects to their elders past, present and future. And with that, I'll move straight through to Slide 4. And you can see there a snapshot of our financial results. The statutory loss was foreshadowed to the market on the 30th of July when we announced $2.2 billion in noncash charges, which were really associated with impairments to the generation assets, to some goodwill in energy markets and also the recording of a deferred tax liability to APLNG. Our underlying profit is lower for the year, which is predominantly due to the lower commodity prices, both in integrated gas and energy markets. And we've worked hard to offset some of those lower commodity prices through lower operating costs in APLNG, some retail cost savings, lower interest expense, and we've also had some oil hedging gains. Operating cash flow is up slightly to $964 million. That's despite the decline in EBITDA. And our adjusted net debt has continued to reduce down a further just over $500 million to $4.6 billion. And we have, as a Board, determined a $0.075 final dividend, taking total dividends for the financial year to $0.20 per share. So now turning to Slide 5. I just thought I'd give a -- some highlights. Obviously, operating conditions were challenging this year. And we obviously had low prices, low demand, particularly in the early parts of the year with the impact of the pandemic across all of our key commodities and those being electricity, gas and oil. We continued to generate strong cash flows. Some operational highlights worth calling out. Firstly, for Integrated Gas there continues to be, what I believe, outstanding performance by APLNG. Our reserves replacement on a 2P basis of 94%. We have demonstrated our ability to ramp production up and down during the year based on demand. The early part of the year was obviously subdued and then we ramped back up into the stronger demand period, and overall is able to achieve production levels similar to the prior year. We've achieved record low unit costs. And the distribution breakeven is also a record low. And we finished the year with a cash distribution to Origin from APLNG of $709 million. In Energy Markets, we achieved our cost savings target that we set off of FY 2018 baseline of $100 million. We achieved $110 million, so that's very pleasing. And we're now -- we extend our lead as the lowest cost to serve retailer in the market. We secured gas and supply and transportation deals through the APLNG APA deal into the southern markets from 2023. We increased our customer accounts by 30,000. We now have 250,000 customer accounts migrated on to the Kraken as we establish our new retail business. And I have to say that the growth and material uplift in the value of Octopus Energy has been incredibly impressive, and I'll touch on that later. It's a business now that extends across renewable energy services and technology and all of those are growing dramatically. So just then coming to the next slide, which really then focuses on our stakeholders. And in a challenging year for many of our stakeholders, we continued to support and deliver them. Firstly, for our customers, clearly, a lot of customers have been impacted by the pandemic and I'm proud of the way we supported and assisted them, particularly businesses in small to medium enterprise -- enterprise -- all the small- to medium-sized enterprises, in particular, sectors that have been impacted most. And we've been pleased to be able to actually provide that support. And for many, many of our customers, they've had lower energy prices this year, and we've been able to assist them and assist those ones that are in need. On a policy basis, we continue to advocate for energy policy that supports the investment required for particularly the sort of dispatchable, reliable energy. And that needs to be supported with the ongoing growth -- dramatic levels of solar and wind in our generation mix as really the energy supply just continues to transition at pace. So it's all about making sure that transition happens smoothly for customers. And that's one of the key areas of policy that I'm sure no doubt people have been reading about recently. Continue to focus on regional communities. We operate in many of them. And also, we do quite a lot of good work through our foundation, and you can see there that we've contributed once again in many ways through our people, funding and other measures. It does some great work. From a people perspective, our recordable injury rate score of 2.7 was steady. We maintained our top quartile engagement score at 74%. And I think like many others, there's been a real focus on mental health and well-being to support people over these last 12 months, including areas like pandemic leave. And we have continued to act on climate change when we think about our planet. So we introduced a short-term emissions reduction target last year and linked that to our executive remuneration. And I'm pleased to report an 8% reduction in our Scope 1 and Scope 2 emissions this year, and that's down 11% since 2017. Just expanding a little bit further on climate change, and we are working to a 1.5-degree emissions reduction pathway. We continue to progress that work. And we're still -- we really are in the process of updating emission reduction targets in what is a dynamically changing environment. We've recently announced a nonbinding advisory resolution, and we'll put that to shareholders at next year's AGM relating to climate reporting. So we clearly continue to make progress not only just in relation to commitments and targets but also our actions. And we've taken a number of those actions that you can see there in both the near and medium term. So on that note, and concluding Slide 7, I think I'll pass over to Lawrie now to go through the financial review. And then I'll come back and talk operational strategy, outlook and guidance. So over to you, Lawrie.

Thanks, Frank, and good morning, everyone. I'll start with the underlying profit bridge on Slide 9. As Frank mentioned, our financial results were significantly impacted by weaker commodity prices across electricity, gas and oil. These negative impacts were partially mitigated by Origin's oil hedging gains as well as lower operating costs in both businesses. Higher net corporate costs are largely due to investment in systems, including our ERP replacement project, which went live on the 1st of July. Depreciation and amortization expense was higher due to the accelerated amortization of our retail IT systems as we implement the Kraken platform and higher amortization of restoration assets and generation. Interest expense reduced $74 million with lower debt outstanding and lower average interest rates. Moving to Slide 10. The statutory loss for the year reflects 2 material noncash charges. Firstly, in impairment in Energy Markets driven by a lower outlook for wholesale electricity prices due to new supply coming online, particularly renewables, as well as a contraction in near-term gas earnings as a result of higher procurement costs and recent subdued market conditions. This impacted the valuation of our generation fleet, particularly Eraring, The outlook for long-term renewable power purchase agreements and the lower gas earnings have also impacted goodwill valuation. Secondly, the recognition of a deferred tax liability associated with our investment in APLNG. An improved outlook for operating and financial performance means we now expect the APLNG preference shares to be fully redeemed by financial year 2023 and distributions thereafter will be in the form of ordinary dividends. These dividends will initially be unfranked until APLNG has fully utilized its carryforward tax losses, which is not expected until later in the decade. Origin is expected to pay taxes on these unfranked dividends from FY 2024. So just to be clear, the $669 million book reflects the required timing for accounting purposes, but this has no relationship to the underlying project economics, which continue to improve or tax payments, which we expect will start in financial year 2024. Next, an update on our LGC trading strategy on Slide 11. At half year, I presented our plan to defer the surrender of more than 2 million LGCs, electing to incur a shortfall charge of $65 per certificate that is refundable provided we surrender the certificates within 3 years. This plan arises as we expect the LGC market to be oversupplied with the backwardation of the forward curve presenting an opportunity to lower our supply costs. We have now purchased most of the certificates in relation to the 2020 calendar year shortfall at a substantial discount to current market prices, locking in a benefit of around $50 million. We will continue this approach for calendar year 2021, deferring the surrender of an estimated 3.1 million certificates. The 2020 and first half 2021 calendar year shortfalls result in a refundable shortfall charge of $262 million, which is included in the statutory result. Of this amount, $64 million is expensed in underlying profit, reflecting the estimated future cost based on purchases to date and current forward market prices. Currently, the shortfall charge is not tax deductible, but the refund is accessible. The legislation to correct this asymmetry was recently introduced to federal parliament. Moving to cash flow on Slide 12. Operating cash flow was stable year-on-year despite the reduction in earnings and payment of the LGC shortfall charge, partially reflecting the unwind of electricity futures collateral positions and a tax refund in the year. Free cash flow was also strong at $1.14 billion, driven by a high cash conversion, $709 million cash distributions from APLNG, lower capital expenditure and lower interest and tax payments. This enabled debt reduction of just over $500 million, while also allowing for investment in growth and continuing dividends to shareholders. Free cash flow yield was 15%, well ahead of the ASX200 average. Focusing in now on APLNG cash flows on Slide 13. Due to the lag in pricing of offtake contracts, this result includes the low point in recent oil price cycle from April to June 2020. Despite this, the APLNG distributed $709 million cash to Origin at a realized oil price of USD 43 a barrel. Origin also realized oil hedging gains, net of premiums paid, of $92 million. With a contract pricing lag, approximately half of the FY '22 oil exposures have already been priced at USD 68 a barrel. At this level, for the full year, we estimate distributions in excess of $1 billion, again, net of Origin's oil hedging. APLNG continues to delever around USD 500 million per annum before distributions to shareholders. Gearing in the project has reduced to 26%. Next to capital management on Slide 14. Our approach to capital management is broadly unchanged. We continue to balance the priorities of reducing debt with delivering returns to shareholders and funding targeted growth initiatives. While headwinds in Energy Markets are expected to be largely offset by higher earnings and cash flow from APLNG, debt reduction and risk management remain key priorities given the higher proportion of earnings will be oil-linked. We ended the year with net debt of $4.6 billion with debt-to-EBITDA at the top of our targeted range at 2.9x. We've continued to target debt to-EBITDA at 2 to 3x through the cycle and target a net debt level over the medium term of less than $4 billion. We also continue to target a free cash flow payout ratio to shareholders of 30% to 50%. The final dividend of $0.075 per share takes the full year dividend to $0.20 per share, 31% of free cash flow and a dividend yield of 4.5%. Dividends will continue to be under franked in the near term. Moving to costs on Slide 15. We have established a track record of driving operating costs lower. Our successes in APLNG and our retail business have been well reported. The chart on the left shows functional costs are trending lower as well. This trend isn't apparent from our annual results as it is reflected through lower overheads in our businesses. We expect a reduction in these costs of around 19% over the period, as shown in the chart, to 2022. Disciplined management of capital expenditure resulted in materially lower spend in 2021, particularly in generation. Some of this saving comes from rephasing of shutdowns with a major Eraring unit overhaul just getting underway. The licensing and implementation of the Kraken platform was a significant component of our spend in the year and progressing through to financial year 2022. We're also forecasting higher exploration and appraisal spend in the coming year, primarily at Beetaloo. Our objective is to rebalance our capital allocation towards growth initiatives. Now to oil hedging on Slide 16. Our oil hedging program is designed to protect our balance sheet through the business cycle, whilst also retaining a level of upside exposure to the oil price. For the coming year, we have roughly half the remaining oil exposure hedged by our combination of swaps, puts and producer collars as well as some purchased calls to increase upside participation. Hedge positions have been established for 2023. And as shown on the second chart, we'll continue to monitor financial risk and potentially add to this position through the year. I'll now provide a more detailed analysis of operational drivers in each of the businesses before passing back to Frank, and I'll start with Energy Markets on Slide 17. EBITDA was down $468 million or 32% with the decrease coming from both electricity and gas businesses, partially offset by retail cost savings. Electricity gross profit decreased $288 million, primarily driven by a $10 per megawatt hour drop in wholesale electricity prices and a $15 drop in renewable certificate prices both flowing into retail and business tariffs. Margins were further impacted by higher network and metering costs not factored into the regulated retail tariff and ongoing costs associated with customer support and competition. Gas gross profit reduced $297 million with lower C&I and retail tariffs, reflecting the competitive environment. While our procurement costs increased as a result of price reviews and higher JKM-linked supply costs due to strong demand in international supply constraints in the second half. Margins were also impacted by the roll-off of long-term supply and transportation capacity sales contracts. Cost to serve reduced from our retail cost out program as well as the impact of a 2020 $38 million debt and doubtful debt provision increase associated with COVID-19 not repeating in 2021. COVID's played a role in these results, with weaker demand, particularly across our C&I and SME customers, partially offset by higher residential demand with many working from home. Now lastly, turning to Integrated Gas on Slide 18. Our upstream business continues to deliver stable production at lower cost while demonstrating the flexibility to respond to market demand. Underlying EBITDA was down $606 million, mostly due to lower oil prices flowing into LNG contract pricing. The realized oil price was USD 43 per barrel compared to USD 68 for 2020. This was partially offset by lower operating costs. Lower earnings from APLNG were partially offset by Origin oil hedging gains and lower LNG hedging and trading losses as well as lower upstream overhead costs. With that, I'll hand you back to Frank to discuss operational performance.

Okay. Thanks very much, Lawrie. And so we'll now move to the third section, the operational review and starting with Energy Markets and turning to Slide 21. It was mentioned by Lawrie but, and it should be well understood by everyone, but just the first slide really highlights the impact of the lower wholesale prices in electricity and in terms of LGC spot prices that have flowed through to the tariffs for both retail and business customers in the year, and that's been a key driver of the electricity margins over the last 12 months. The impact it has is it essentially reduces the margin against 16 terawatt hours, which is our rule of thumb really around the relatively fixed cost of energy supply and around about the 3 million LGCs that are relatively fixed cost as well. We did decrease our energy supply costs. We managed swap and short positions in that and they do have -- the swap will have a little bit of a lag impact. But nevertheless, we keep managing that portfolio in terms of responding to those energy prices. The other key aspect of managing that portfolio is to have your generation available to capture when prices are high through those peak periods and then also to flex their load down when prices are low. And that's the role our gas peaking fleet provides and increasingly, particularly in terms of the financial year where we saw significant volatility in those energy prices. I'll expand a little bit further on there for the role of Eraring by turning to Slide 22, and you can see the role that's played over the financial year. And I think you'll identify that the energy margins at Eraring have come under pressure because we've given you an indication of both its output, its cash costs. But you can also see the significant what we describe as the capacity value that it provides, particularly in the final quarter. That's the role that increasingly Eraring's playing for us, and that's why it is a critical component of our portfolio today. It was able, based on its flexibility relative to other coal plants, to capture a higher than average pool price because it minimizes its exposure to the lower price periods of the day. And you can see there that our cash costs are made up of $40 a megawatt hour for fuel and a further $15 a megawatt hour for OpEx and CapEx. And I just note that CapEx can be lumpy depending on maintenance schedules. We're in the process of recontracting fuel supply, that's coal supply beyond FY '22. We want to be balancing that based on an outlook for pool prices. And I'd just make sure that everyone is aware that the coal we purchase is closer to a 5,500 index rather than the export. So clearly, the way we want to buy that coal over time is you don't want to be caught with a long coal position. But at the same time, you want to be layering that in, and that's all informed based on our electricity price pool outlook. So hopefully, that gives you some insight into the changing role that Eraring plays as we continue to think about the transition of the portfolio. Turning to Slide 23. Lawrie outlined those gas margins declining through the year. We give a little bit more color to that. What you can see there is that there's been lower prices on C&I sales. What we saw is really an oversupplied domestic market as the electricity market, in particular, came under weaker demand. We also saw gas-fired generation not running as much, and that gas then became available more broadly to the market, and that put pressure on domestic prices at the same time that we saw the tightening of the international market growth, JKM-linked supply costs higher in the second half. In addition, we completed several gas price reviews. And clearly, the outcome of the Beach review is disappointing for us. We do expect the international and domestic markets for gas to reconnect over time. and we see the emergence of that right now, but we'd expect that, over time, that has a lagged impact for that playing back through the C&I contracts and so forth. And I should note that the JKM exposure is largely closed out for the next financial year. And the next time we have any gas supply price reviews are in 2024. I then turn you to -- if I then turn you to Slide 24. We set out to transform our retail business 3 years ago. And I think you can see on this slide that we have continuously improved, over those 3 years, our customer experience. And we once again improved our strategic Net Promoter Score, which is a measure of customer satisfaction. As I mentioned earlier, we achieved our cost-out target of $100 million against the FY '18 baseline. And we've grown earnings in our CES and solar businesses each year, and those businesses continue to grow. We are now establishing and made very good progress on building our new retail business, which is what we call Retail X. And it now has 250,000 customers on the Kraken platform. It's been served by our people in the new operating model every day. And we are targeting 850,000 customers by the end of this calendar year. Not only do we see that as a driver of future improvements to customer experience, it's also a key driver of reducing our cash costs by a further $100 million to $150 million by 2024. So very good progress in the retail business, and it continues to advance. Touching on then Slide 25 shows that Origin churn was 12.5% over the year, that's 4.8% lower than the market. We grew customer accounts by 30,000. And every day, we're competing through that customer experience I talked about, the products we develop and launch in the market and that low cost to serve. And then really, how do I think about the capabilities that we're building in that retail business on Slide 26. We've built the technology and digital capability that has been a key driver to our competitive strength and continues to be that. There have been a number of technology developments. We've developed our own virtual power plant. It has nearly 160 megawatts of connected assets on it. And these are enabling the development of new products and services you can see, like Spike and others. And we add to these capabilities, not only through our own internal efforts, but through partnerships and alliances, including those with Octopus and the Kraken platform and the Everyday Rewards program with Woolworths. And that's all being brought together now to create a technology-based operating model for our retail business, providing products that I think puts us in a very good competitive position as we go forward. And then separately, I'd like to just now turn you to Page 27 to give you an update on Octopus. You may all recall that we made a 20% equity investment in May last year at the same time as entering into an arrangement for the implementation and licensing of Kraken in the loan market. And since then, Octopus has grown exponentially. As an energy retailer, they've grown their customer accounts now to 4.2 million accounts, that's the same as the size of Origin. They now have 7.5% market share in the U.K. They're growing those customer accounts anywhere between 70,000 to 100,000 customer accounts a month. They've entered a number of other markets, most notably the joint venture with Tokyo Gas. It's obviously an exciting opportunity because they're now entering the largest deregulated energy market in the world. And you may also recall that Tokyo Gas took a 10% stake in Octopus at a valuation well above our investment. And in addition to that being a retailer, they've also grown as a technology business, and they now have 4.7 million licensed customer accounts on the Kraken platform, and that will drive GBP 250 million of revenue over the next 3 years. In addition to that, they've acquired Octopus Renewables which is a renewables assets fund management business, and they have about GBP 3.4 billion of renewable assets under management. So we've been very delighted with that. And you can see that the growth in that business really makes our investment in that 20% -- through that 20% stake very attractive. Now I'd like to turn to Integrated Gas, and we're now on Slide 29. I touched on it at the outset, but really, the reserves position continues to perform above expectations. At an APLNG level, the 2P reserves replacement ratio during the last 12 months is 94%. And on an operated basis, that's actually 105%. It is being driven by both an increase in the EUR due to strong field performance and also to the maturing of resources to reserves. We've now finished the financial year with a 2P reserve life of 16 years based on this year's annual production. So very pleased to see the reserves position continued to advance. Just go a little deeper on that on the next slide, Page 30. And really just highlighted to you that when it comes to that estimated ultimate recovery or the EUR, it's largely driven by improvements over the last 12 months in the Talinga-Orana fields. And we've shown that indicatively to you on the left-hand side of the chart. At the same time, we've matured a number of new areas for appraisal, and that's shown on the right-hand side of the chart. And you can see there they're identified at the bottom there, Peat Flank, Ramyard South and Spring Gully Northeast Flank have all contributed to this reserves position as well over the last 12 months moving from resources. When we look at the APLNG performance on Slide 31, you can see it's been very strong. We talked about that stable production. The cash cost once again reduced. That's driven by strong field performance, which also [ and we mentioned ] in turn, reduces development activity and also the team continues to make productivity improvements. And that's meant that we've reached a unit cost record low of $2.80 a gigajoule in the last 12 months. That operational performance and also some recovering JKM prices has also lowered our distribution breakeven and that's achieved a new record at USD [ 22 ] a barrel. And you can see that, that's more than half what we achieved only 3 years ago. So we have now a very strong, resilient business under oil commodity prices. I'm now turning to Slide 32, which gives more insight into the APLNG operational performance. Touched on that development activity, and you can see that, that's -- you can see that that's highlighted on the left-hand side chart and just how much less that activity was over the year. What made the production performance pleasing on the middle chart was that in response to subdued demand at the beginning of the year, we actually reduced production and the fields are able and the team were able to demonstrate the flexibility of these assets by ramping production up into the middle part of the year when demand recovered. So that's obviously been very valuable for us, and it's also been very valuable to manage production. And you can also see on the right-hand side, we've had outstanding gas processing facility reliability. What that all means is we turn to Slide 33 and on the left-hand side, really around [ APLNG ]. This strong field performance will enable lower development activity over the medium term. And that continues to drive us to target cash unit costs of less than AUD 3.50 a gigajoule through FY '24. So our focus really does remain on continuing to create value through efficiencies and well workover activity. We'll optimize production, and we'll invest in infrastructure where we see benefits can utilize available processing capacity. And that's where our focus is in terms of creating more value through APLNG over the coming years. And then just turning to exploration. Clearly, at Beetaloo, we have the Kyalla 117 well, that did flow liquids-rich gas. And you can see that, that was at 0.6 to 0.9 terajoules a day. We are preparing for an extended production test, but we have paused operations in July just to investigate a downhole flow restriction. So that's what's underway with the team right now. We spudded the Velkerri 76 well in August and production test at Amungee has commenced as well. In the Canning, we obviously have farmed into that. And probably the key development announced over recent times is just the Currajong well has been drilled -- will be drilled in August with options for a production test being developed. And in the Cooper-Eromanga, there's some activity there around the Obelix vertical well in December '20, and we're testing that maturity as well. So that's just a quick highlight on some of that exploration activity. And then outlook and moving to Slide 35. And just a few comments I'd make on the commodity outlook. You can see the lag in APLNG's long-term LNG contracts mean we already have line of sight to a significantly higher realized oil price for the FY '22 year because around half of those volumes are already priced in. In the gas markets, we are starting to see a reconnection of domestic gas prices and LNG netback prices, and we do expect that to continue. We've largely closed out that JKM exposure in FY '22. And sorry, I just had a bit of a slide issue there. And the JKM rally will be beneficial to APLNG, but I do note that the majority of APLNG domestic sales, I think it's worth noting, around those long-term contracts that are linked to oil just to make sure you've got that context. In electricity, the $20 a megawatt reduction in wholesale electricity prices that's in the customer tariffs is the key driver to the FY '22 earnings. And we have stated in our announcements on the 30th of July, that we do expect a rebound in the FY '23 for Energy Markets. And that is provided and assuming that the current forward prices for electricity continue and those actually throw into -- flow into the customer tariffs. So I just think it's worth just reflecting that there are some calls around that. But that's what we're expecting in FY '23 if those commodity prices continue. So against this background, our priorities are clear, like, we really have a strategy that's really linked to the energy transition, which means we have to do a number of things. We have to maximize the value of those existing businesses, and I think you've got an insight into the -- to the cash engine of APLNG, the changing role of Eraring. We already talked about the disciplined capital and cost management, and you can see the retail transformation that's underway. They're all -- and also -- and I should also say the activity of exploration and appraisal and, obviously, the commencement of farm down in the early stages of the Beetaloo that we continue to look to create value and unlock value in that upstream as well. It's important that we continue to reduce emissions, and you can see the progress we've made on that. We're doing all of that to actually make sure that we have the capital available to not only meet our allocation objectives of both distributions to shareholders, reducing debt and importantly, to pursue growth. And in those 2 areas, there's really the growing of the integrated customer solutions, which really is all about the ongoing innovation and growth of our retail business, the offerings we take to them and in growing our customers. And secondly, we've obviously got the growth underway through our investment in Octopus. At the same time, we will grow through accelerating what we call renewables and clean energy. And that really means that the introduction of renewables and storage, which will be linked to, as you can see recently, policies like the New South Wales road map and it's about investing in over the right time. We've got falling cost curves on batteries, and we have to do that in a way that continues to move the business forward in that transition. And at the same time, pursuing investments in opportunities like hydrogen and ammonia, which we continue to advance. And when it comes to that, I'm just on Slide 37. We do think about it all being driven by customers increasingly. The 2 existing businesses are well-established leaders in the energy sector in Australia. They both generate strong cash flows. We are well positioned. We've got a very good customer base. We've got a very good capability around digital data and analytics. We have the capacity of the customer load to invest into the generation opportunities at the right time and we have the capabilities in the LNG and fantastic world-class asset in APLNG. And that all just leads to that strategic focus of maximizing that value through the transition, accelerating renewables and clean energy and growing integrated customer solutions. I will just now turn to guidance. And you will be aware that some of this was provided in the market on the 30th of July in the update we gave. I'll just quickly step through a few items. Firstly, you'll notice at the top of Slide 38, the introduction of new guidance, which is a consolidated underlying EBITDA guidance for the whole of Origin. What we're doing here is seeking to simplify the guidance framework and just provide a clear indication of overall business performance, which we hope will assist shareholders to narrow the range of earnings outcomes. I will just make it very clear that, that EBITDA guidance is based on a $68 a barrel of realized oil price and Australian U.S. exchange rate of $0.75. And we have provided on the next page a sensitivity to this guidance so that you can apply your own oil and FX assumptions. And you'll see that sensitivity because a number of that oil is already priced out but I think it's plus or so or minus $10 will yield a plus or minus $120 million variance. Then just in terms of CapEx, it's expected to be moderately higher. That's largely due to the phasing of generation maintenance spend. Lawrie gave you an indication as where our CapEx is going, and that's particularly Eraring, some of which we deferred from the recent financial year. And we do have further installments of the $200 million in deferred consideration for Octopus. Some of that's being brought forward from FY '23 as a result of the higher Brent price, which is really part of the deal that if Brent had recovered given the timing of our deal, then we would time this consideration the way we have. The Energy Markets' underlying EBITDA is consistent with what we communicated to you on the 30th of July. And I think you'll also see the APLNG guidance there in Integrated Gas production. CapEx, OpEx, overall, I think, consistent with what we provided, all of which at a realized oil price of $68. We expect to have a distribution back to Origin of more than $1 billion net of Origin's oil hedging. We also -- I did say, and you've got some further detail on Slide 39. The only thing I'd add to what I've just mentioned to you is really just all about the FY '23, which we did give you a range of rebound expectations for FY '23 of $150 million to $250 million. I did say that, that assumes current forward commodity prices continue and that they flow through the tariffs. And just to draw out what that really relates to, that's about a $5 to $10 a megawatt rebound of electricity forward prices flowing through. It does assume that we have a reconnection of the JKM netback and the East Coast domestic gas pricing and that we will achieve Kraken cost to serve savings in that year as well. So on that note, I will -- that's the rest -- that's the finish of the slides. We'll now, I think, open up to questions from everyone, and look forward to receiving them.

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

Frank and Lawrie, over '21, the key driver, 2 of the downgrades have come from getting caught exposed to higher spot or short-term commodity prices. So that was in the case of JKM LNG over December and February and then thermal coal prices more recently. Is there any plan to adjust your contracting and hedging strategy to provide better downside cover from commodity price volatility going forward?

Yes. So just on a couple of points there, Tom. So firstly, you've certainly acknowledged that the JKM in the second half, but I don't think any coal price has really had anything to really play into our results this year. It was really the JKM and the Beach announcement, which were the 2 things in addition to actually electricity commodity prices. But nevertheless, I take your point. No, I think we've had -- look, I really do believe we've got a robust risk management. But there's -- it'd be fair to say that as -- if you're looking forward in the current environment, we've seen obviously a lot of volatility in commodity markets and we certainly didn't see the JKM play out the way it did over that period of time. It's been -- our risk management, I think, is robust. There's no doubt that when we look into the FY '22 that we've closed down a lot of that. I mean, we certainly, I think, closed down or tightened a lot of positions around that. And so you would expect us to just continue to adopt the risk management approach to it. I do think we have a robust one, but I think we have called out. It's been valuable to us over many years, but we called out where we missed it in the JKM. As it relates to the future years on coal, which I think might be your question, we've largely got that coal position for FY '22. Well, that's contracted now. And I think, really, we would be, in terms of then contracting FY '23, I think the way we think about coal is we've always had a base sort of volume of that coal at about 4 million tonnes, and we would go back in the market and purchase depending on the capacity factor we would be running, which I think is linked to those pool prices. And you would expect us to continue to manage that actively, and we're well advanced on those contract negotiations. Yes.

So just extending your last comment there. So recognizing that 2/3 of your contracted coal supply to Eraring expires at the end of FY '22, can you share what your average coal price assumption is implied in your FY '23 Energy Markets EBITDA guidance?

Yes. I think all I'd say is that we're not expecting it to escalate beyond '22 based on where we are in negotiations on those contracts and also based on where we see the backwardation of those coal contracts today. And I think further, just thinking about the coal we do buy is not all of that export quality coal, it tends to be a lower index. So we're not expecting it to be significantly high. It might be a little bit higher, but not significantly higher. It might be a small uplift in that number that we've assumed.

If I could just sneak one last one in. Just on the way that you used the Eraring power station going forward. Given there's plenty of cheap energy available in the market, can you reduce your exposure to low average prices in the cooler 6 months of the year by turning off capacity from Eraring completely rather than just cycling the output up and down throughout the year?

Yes. So the answer is yes. I will give you -- I'll just let Greg know that I'll ask him to supplement this answer, but just to make sure that we give it the attention that it requires. There were periods of time this year where we only ran 3 units, okay? And ultimately, the call for us is having the available units be there if there were volatility events to protect yourself. So the answer is, we would have lower capacity factors and may run less than 4 units for extended periods of time depending on that electricity pool price outlook. The key when we talk about the role being capacity, it's all about making sure that if you do have those excursions in price that you're not caught short, and that's the key role it continues to play. But within that operating envelope, Tom, there are a number of choices we can make. I wouldn't say perfectly all the way down, you can't shut all the units down unless you're really confident about it. But certainly, we've tested that and we'll continue to test that. And that's the key challenge for, I think, the situation as the market evolves because you'll be running them differently. You won't want to run them in those low price events. You'll, at the same time, not want to catch yourself short if there's actually a spike in prices because that can be very costly. And that's why ultimately, we have to continue to plan for those scenarios going forward. Greg, did you want to add something on the Eraring operations?

Look, Frank, you covered it well. Look, just to give what we did last year, we are certainly cycling those units down to mean gen levels around 200 megawatts and then cycle them back up at night, 700 megawatts. We also -- we did take a unit off last year when prices were quite depressed, especially around those COVID times. So we have done that. And look, we'll just assess the market all the time, and we'll take those opportunities as they arise going forward.

Yes. I think, Greg, the only question is to whether you turn more units off or not is always just a risk management. It's always been about us protecting. It's just a risk management question of protecting against [ similar ] prices.

Yes, that's right.

That's all it is, yes.

Your next question comes from Dale Koenders from Barrenjoey.

Frank and Lawrie, just a question on APLNG production guidance, flat versus FY '22. Just questioning this given it's in contrast to your statement of having asset flexibility to adapt to market given FY '22 is managing maintenance. And as we look into FY '23, we're seeing record spot LNG prices relative to oil. Just a question there. Can you actually produce more gas?

Yes, we can produce more gas. It is -- there's a lead time. So it really -- and I'll answer it in sort of 2 parts. The first is the ability, obviously, to flex the production within a year as it isn't able to go down and come back up to use there. But if you're then wanting to sustain higher production at higher levels, that will be a function of the development activity and there's generally a lag on the development activity. So that won't be giving that guidance around that 700 petajoules now. It's a function of the development activity that the CPMs, that the joint ventures are making in advance of that production, probably 18 months to 2 years. So that will be -- it will be subject to those decisions. And therefore, that would be APLNG that would be the ones that -- it will be a Board decision about whether or not we invest in further development activity at that time. So I hope that explains the answer about the flexibility thing.

Yes, that does. I guess second question in the actual report, there was the comment the Board is considering a combination of ordering dividends and on-market share buyback in the future. I just wanted to marry that with leverage being at the top of settings in FY '21 and FY '22 either died down a little bit. And your words of focus on accelerating investments in renewables and new energy. Can you give some comments about your outlook for leverage and balance sheet capacity? And are we 12 months away from really sort of rolling through those lows in EBITDA before the balance sheet starts to open up?

I might -- Lawrie, do you want to talk balance sheet and then we can talk about how we make decisions across that second?

Sure. Dale, yes, look, we -- 6 months ago, we changed that narrative around how we might distribute cash because we want -- well, first, we didn't want to take anyone by surprise if we reverted from paying dividends to executing on a buyback as a way of distributing the same amount of cash. And so obviously, we didn't do it last time because we wanted to foreshadow and we haven't done it this time based on a $0.075 per share dividend. But yes, we want to preserve the ability to do that. If we look at our balance sheet today, yes, we've headed up to 2.9x. Obviously, the -- it could go higher in '22 with lower energy markets earnings. But exactly where our balance sheet ends up depends obviously on oil price. But we do expect in the midterm for that gearing to head back down to our target range pretty quickly. And so therefore, we would have the full range of capital management levers in our hands.

And Dale, just to add to Lawrie's response. Strategy for us is clear, but we obviously operate within the prioritization of that is always within the envelope of the capital structure at that time. And so clearly, depending on the -- and you can see next year, you'd expect you've got the Energy Markets EBITDA down, but you go a long way to offsetting that with the rise in Integrated Gas. But nevertheless, the extent to which we're investing in replacement capacity or new capacity in renewables and storage will be determined by the balance sheet. And therefore, that's why we continue to look at ways where we can optimize that over time.

Your next question comes from Max Vickerson from Morgans.

And look, I just want to circle back around on Eraring as well, if I could. So just having a look back at the historical commodity prices, I apologize for being a bit of a backside energy trader here. But given that we came out of a pretty weak summer, futures prices were very low. I'm just a bit surprised that more of the position wasn't bought back and covered when there seem to be an opportunity to do that quite cheaply. Obviously, you didn't anticipate Kyalla do any of those other things. But just wondering if you could maybe give me a bit of the color on the thinking there. Am I oversimplifying how I'm thinking about that? And then just looking forward with Eraring, AGL has made comments that their baseload fleet is maybe less effective as a means of hedging retail risk or retail demand. I know Eraring's a pretty flexible power station. But are you seeing something similar? Should we think that maybe in the future, Eraring is going to play potentially a less critical role in covering some of that peak demand?

Yes, sure. I might just -- the first one, I'll just put Greg on those, but just whether or not there was a trade to be done in the weak prices when you've got the rise there in a moment. But just coming to the broader question, I think there's no doubt the role of Eraring in baseload generation is changing, Max, which is really one of the key aspects we've associated with the fact that it plays a critical role to provide capacity to the market, and it does play a risk management role for us. And with large retail load, you've got to have that capacity available. And if you don't have that, you need to have other capacity available, and therefore, they are the choices you're making as you go forward. And therefore, that is the changing nature of these assets. And therefore, I don't think we have a different view to AGL in principle. And that's why one of the reasons why you think about how much you're going to run that, how you run that, but also what's going to be the way you evolve your portfolio over time. Greg, do you want to just comment? I think your comments are just about clear on your question, Max, but I think it was with low prices, why didn't you buy swap at that point in time rather than run Eraring in a particular way over that time. So maybe I'll just give it to Greg as to what was in our thinking about the portfolio strategy over that period of time and share that with you.

Sure. So overall, the principle, we buy swap to cover our -- if we went C&I load. So we generally cover swap there. Just with the way we run Eraring, the prices were quite depressed from a pool perspective in summer, and we actually took the opportunity to take a unit off. But as we saw the -- certainly the Kyalla plant issue and the Yulon issue down in Victoria, we ran Eraring as hard as we could, right? So we really ramped up capacity. And you can see that we actually achieved quite a higher pool price outcome there. But look, we are always in the market buying swap if it's cheap enough, but that's predominantly to cover our C&I load.

Your next question comes from Mark Samter from MST.

A couple of questions, if I can. Just the first, and I apologize, you might have covered this earlier, I have a bit of a home schooling emergency. So apologies if this is a duplicate. From what I can get, at least from clients, the share price reaction today is because people are panicking about the Integrated Gas EBITDA guidance that went out insulting your accounting sensibilities. Lawrie, I would have thought the Origin EBITDA is pretty better than any cash distribution. It's the only really percent number with APLNG. And I mean, certainly, what -- from your -- implicit in your guidance is that cash distribution growth is outstripping EBITDA growth. Could you maybe just talk through why that's the case and maybe help placate them on these feel to me irrational fears?

Okay. So firstly, the additional guidance we provided was all of Origin guidance. So it does include reductions for corporate costs as an example. So maybe if there's an issue, Mark, maybe it's just that. And I guess, to confirm your point, that the distribution of cash is the most important aspect of APLNG, which is why we're also providing the better than $1 billion cash distributions information as well.

And the other thing would be, I think, Mark, just from my perspective that everyone will have different realized oil price and currency assumptions. And we just should make it clear again that that's at $0.68 and $0.75.

Yes, I think it seems a very strange reaction to me. But just a bigger picture on for you, Frank, what we're seeing on the E&P side of things, that there's the increasing trend of go big or go home. I guess APLNG is biggish, but in the scale of MPs more broadly, it's not big. And B2B is exciting, but you're arguably constrained by that balance sheet capacity. With everything that's going on in the world, do you still think -- and I ask you this question in a different way pretty much every result. But does Origin remain the right vehicle for your upstream aspirations to sit with it?

Look, I think I've been, I think, clear to you as well, Mark, over time. Is that clearly, we have priorities to maximize the value of those assets. We have talked about crystallizing value in the shorter term for the E&P, but there's an investment we think we need to undertake to achieve those goals. APLNG is a very valuable asset to us. The cash flow is a valuable. But clearly, we continue to look at portfolio as we go forward and actively do that and we're proactive around thinking about all of those aspects, all of the time, Mark. So I certainly observe what's happening in the sector. And yes, we just continue to read our portfolio and make the best choices available to us.

Your next question comes from Peter Wilson from Credit Suisse.

Just a couple on your gas and your coal costs. Just start with gas, the JKM, just so I get this right, the $51 million impact this year, is that a -- how do you calculate that? Is that a net impact, so the difference between JKM and the domestic price? Or is it gross? And when you say it's closed out in FY '22, the loss, if it's a net loss position -- or the net position in '22, how does that compare to '21, that 51 in '21?

Okay. I might -- when you talk of gross and net. Firstly, just as it relates to '22 versus '21, the gas position is not -- it is not a material uplift in gas. So the gas earnings contribution year-on-year, I think it's a few tens of millions lower but not significantly lower as a result of JKM. So the JKM impact combined with price reviews is not the most -- it's 90% of the drop over year-on-year is coming from electricity. So it's not a big driver. I just need to check with the team maybe just in terms of the way that calculation of that particular JKM number is gross or net. Can I just take that on notice to make sure we answer that question for you? If you just keep that, I'll get someone to come back while we're on the call, just to make sure I just get out of territory here, and I'm not sure, okay?

Yes, that would be great. And the reason I asked is, I guess, is if you add up FY '21 and '22, the cumulative loss you said earlier, I think you would expect that time line in '23. So if you go back...

I think what you should be walking away with though is that gas is not a big driver between '21 and '22 at all, okay? It's not a big driver of difference. It's nearly all electricity, okay? So we'll just make sure you get clarity of what that '21 number calculation is so that you can make an assessment of that year-on-year.

Got it. That would be good. And then Eraring. I'm wondering how much of a factor the Eraring coal cost is. So I mean, I know that we -- the change in Eraring output is a factor. But if you just look at the coal cost and perhaps to think on a like-for-like [ production ] basis...

For '22?

For '22. How much more coal are you buying on spot and short-term contracts compared to '21? And then I guess the expectation around the difference in the price of that volume?

Yes, happy to be clear about that. So we've got the 4 million tonnes that rolls all the way through the same as '21 through to '22. So we have purchased a further 1 million to 2 million tonnes. And that is at about $30, $40 a tonne higher. So the total blended cost in FY '22 is $100 a tonne.

Okay. That's compared to...

Track that on. Yes.

Yes. So that is contract advise. I assume whether it's the same in FY '21. Did you purchase the same amount of contracted volume in '21 that you are in '22? Or did you, for example...

Similar volume -- I'll just check with the team. Similar volumes year-on-year, I think you're fine. And that's one of the things is how much we consume this year will just be pool price driven. But if you think about 4 million plus 1 million to 2 million tonnes, you're looking at similar volumes year-on-year.

Okay. Just one last one, if I could. To follow up Dale's question on APLNG production growth. You mentioned that lag between investment and actually getting to production. Right now, is any investment in future production growth going on?

The development activity is set. So it would be a little bit more, Andrew Thornton's on the line, but it would be a little bit more activity than in FY '21, but still less than what it was in prior years. So just, Andrew, did you want to add just in terms of orders of magnitude in terms of development activity to give Peter a sense?

Yes, it's quite similar in terms of development activity in terms of the number of rigs and wells we intend to drill and bring online. So we do -- we are continuously assessing and implementing opportunities to maximize the base production within what we -- within the existing activity level. But clearly, not planning or not seeing the price that exists today necessarily being in place for the duration. And so we've been cautious in terms of ramping up activity to either production or to either market in a couple of years' time.

And Peter, I just had someone sending a message that the JKM's a gross impact for the second half on second half.

Your next question comes from Rob Koh from Morgan Stanley. Apologies, your next question comes from Daniel Butcher from CLSA.

Just wanted to follow up maybe on the last question about APLNG. You've given some good guidance to FY '24 and about the activity levels. Just sort of curious how you see activity levels after that ramping up in terms of number of wells and activity you need to maintain production as you step out the most productive areas.