Origin Energy Ltd Ord

Thank you for standing by and welcome to the Origin Energy full year results teleconference. All participants are in a listen only mode. There will be a presentation followed by a question and answer session. If you wish to ask a question, you will need to press the star key followed by the number one on your telephone keypad. 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 origins 2021 full year results uh thank you all for joining us um and probably acknowledging that many of you like us are in lockdown and uh just to let you know that uh lori and i are presenting remotely and we also have the rest of our executive team in attendance as you would normally expect um i'll give a short introduction uh then lori 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 and 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 their elders past present and future and with that I'll move straight through to slide four and you can see there a snapshot of our financial results the statutory loss was foreshadowed the market on the 30th of July when we announced 2.2 billion in non-cash charges which were really associated with impairments to the generation assets to some goodwill and energy markets and also the recording of a deferred tax liability to APLG. 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 APL&G, 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. It's down a further just over $500 million to $4.6 billion. And we have, as a board, determined that a seven and a half cent final dividend taking total dividends for the financial year to 20 cents per share so now turning to slide five I just thought I'd give a some highlights obviously operating conditions were challenging this year 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 continue 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 for 94%. We have demonstrated our ability to ramp production up and down during the year to based on demand. Early part of the year it was obviously subdued and then we ramped back up into the stronger demand period and overall was able to achieve production levels similar to the prior year. We've achieved record low unit costs and the distribution break even is also a record low and we finished the year with a cash distribution to origin from APLG 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 extend our lead at the lowest cost to serve retailer in the market. We secured gas and supply and transportation deals through the APOMG APA deal into the southern markets from 2023. We increased our customer accounts by $30,000. We now have 250,000 customer accounts migrated onto 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 continue 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 and small to medium sized enterprises. In particular, sectors 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 at 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. I 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 quarter engagement score at 74%. And I think like many others, there's been a real focus on mental health and wellbeing to support people over these last 12 months, including areas like pandemic leave. And we've 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 one and a half 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 non-binding 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 seven I think I'll pass over to Laurie now to go through the financial review and then I'll come back and talk operational strategy outlook and guidance so over to you Laurie thanks Frank and good morning everyone

I'll start with the underlying profit bridge on slide nine. 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 amortisation expense was higher due to the accelerated amortisation of our retail IT systems as we implement the Kraken platform and higher amortisation 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 two material non-cash charges. Firstly, an 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 our RRing. The outlook for long-term renewable power purchase agreements and the lower gas earnings have also impacted Goodwill's valuation. Secondly, the recognition of 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 is fully utilised to carry forward 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 is 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 three 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 assessable. 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 unwired 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 APL&G, lower capital expenditure and lower interest in 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 ASX 200 average. Focusing in now on AP LNG 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 US $43 a barrel. Origin also realized oil hedging gains net of premiums paid of $92 million. With the contract pricing lag, approximately half of the FY22 oil exposures have already been priced at US $68 a barrel. At this level, for the full year, we estimate distributions in excess of $1 billion, again, net of origins oil hedging. APLNG continues to be levered around US $500 million per annum before distributions to shareholders. Dealing 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 APING, debt reduction and risk management remain key priorities. given the higher proportion of earnings will be oil length. We ended the year with net debt of $4.6 billion, with debt to EBITDA at the top of our targeted range at 2.9 times. We continue to target debt to EBITDA at two to three times through the cycle and target a net debt level over the median 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 7.5 cents per share takes the full year dividends to 20 cents per share. 31% of free cash flow and a dividend yield of 4.5%. Dividends will continue to be unfranked in the near term. Moving to costs on slide 15. We've established a track record of driving operating costs lower. Our successes in APOMG 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 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 shown in the chart to 2022. Discipline management of capital expenditure resulted in materially lower spend in 2021, particularly in generation. Some of this saving comes from re-phasing of shutdowns with a major O'Reilly 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 Breedaloo. 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 via a combination of swaps, puts, and producer collars, as well as some purchase calls to increase upside participation. Hedge positions have been established for 2023 and are shown on the second chart. will 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. Either Dar was down $468 million, or 32%, with a 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 flying 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 CNI and retail tariffs reflecting the competitive environment, while our procurement costs increased as a result of price reviews and higher JKM link supply costs due to strong demand and 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 bad 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. And 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 flying into LNG contract pricing. The realized oil price was US $43 per barrel compared to US $68 for 2020. This was partially offset by lower operating costs. Lower earnings from OPLNG 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, Laurie. 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 Laurie, 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 that 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 the swap will have a little bit of a lag 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 that our Gas Connecting League provides and increasingly particularly of the financial year where we saw significant volatility in those energy prices. I'll expand a little bit further on therefore the role of ARARing 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 ARARing 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 our RRing is 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 exposure to the low 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 supplied beyond FY22. We want to be balancing that based on an outlook for pool prices. And I 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 laying 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 Araring plays as we continue to think about the transition of the portfolio Turning to slide 23, Laurie outlined those gas margins declining through the year. We give a little bit more colour to that. What you can see there is that there's been lower prices on CNI sales. What we saw is really an oversupplied domestic market as the electricity market in particular came under weaker demand. We also saw gas by 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 to CNI 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. If I then turn you to slide 24, we set out to transform our retail business three years ago. And I think you can see on this slide that we have continuously improved over those three 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 FY18 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 making very good progress on building our new retail business, which is what we call RetailX. It now has 250,000 customers on the Kraken platform. It's being 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 in customer experience. It's also a key drive of reducing our cash costs by a further $100 to $150 million by 2024. So very good progress on the retail business and it continues to advance. Touching on then slide 25 shows that Origins 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 a 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 Crack-On platform and the Every Day 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 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 cracking in our own 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 UK. They're growing those customer accounts anywhere between 70 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's evaluation 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 they'll drive 250 million pounds of revenue over the next three years. In addition to that, they've acquired Octopus Renewables, which is a renewables assets fund management business, and they have about 3.4 billion pounds 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 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 in 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 foil 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 continue to advance. Just go a little deeper on that on the next slide, page 30. And we really just highlighted to you And when it comes to that estimated ultimate recovery of the EUR, it's largely driven by improvements over the last 12 months in the Talinga Rurana 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 through appraisal, and that's shown on the right-hand side of the chart. And you can see they've identified at the bottom there, peak flank, ram yard south and the 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 April and G 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 in turn reduces development activity. And also the theme 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 is also lowering our distribution break even. And that's achieved a new record at $22 US a barrel. And you can see that that's more than half what we achieved only three years ago, so we have now a very strong resilient business under all commodity prices. I'm now turning to slide 32 which gives more insight into the APL&G operational performance. I touched on that development activity and 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 were 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 very important 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 . 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 $3.50 Australian a gigajoule through to FY24. So our focus really does remain on continuing to create value through efficiencies and well at work over activity. We'll optimize production and we'll invest in infrastructure where we see benefits that can utilize available processing capacity. And that's where our focus is in terms of creating more value through APMG over the coming years. And then just turning to exploration, clearly at Beteloo, we have the Kyla 117 world that did flow liquids-rich gas. and you can see there 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 sputtered the Valkyrie 76 well in August and production tests at Amungi 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 Karajan well has been drilled, will be drilled in August with options for a production test being developed. And in the Kuparana and Anga, there's some activity there around the obelisk 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 realised oil price for the FY22 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 net back prices, and we do expect that to continue. We've largely closed out that JKM exposure in FY22. Sorry, I just had a bit of a slide issue there. And the JKM rally will be beneficial to APL&G, but I do note that the majority of APL&G 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 megawatt reduction in wholesale electricity prices that's in the customer tariffs is the key driver to the FY22 earnings. And we have stated in our announcements on the 30th of July that we do expect a rebound in the FY23 for energy markets, and that is provided and assuming that the current forward prices for electricity continue and those actually 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 FY23 if those commodity prices continue. So against this background, our priorities are clear. 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 maximise the value of those existing businesses, and I think you've got an insight into the cash engine of APLNG, the changing role of Araring. Laurie talked about the discipline, 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 for Beedaloo 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 of both distributions to shareholders reducing debt and importantly to pursue growth and in those two 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 then 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 roadmap. 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 on 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 two 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 and AP LNG. And that all just leads to that strategic focus of maximising that value through the transition, accelerating renewables and clean energy and growing integrated customer solutions. I will just now turn to guidance. 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 realised oil price and an Australian US exchange rate of 75 cents. 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 that I think it's plus 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. Laurie gave you an indication as to where our CapEx is going, and that's particularly our RRing. some of which we deferred from the recent financial year. And we do have further instalments of the $200 million in deferred consideration for Octopus. Some of that's been brought forward from FY23 as a result of the higher Brent price, which was 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 APL&G guidance there in integrated gas production, CAPEX, OPEX. They've all, I think, consistent with what we provided, all of which at a realised oil price of $68. We expect to have a distribution back to origin of more than a billion dollars net of origins oil hedging. We also, I did say, 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 FY23, which we did give you a range of rebound expectations for FY23 of $150 to $250 million. I did say that that assumes current forward commodity prices continue and that they flow through to tariffs. and just to draw out what that really relates to that's about a five to ten dollar a megawatt rebound electricity forward price is flowing through it does assume that we have a reconnection of the JKM net back and east coast domestic gas pricing and that we will achieve crack and 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.

Thank you. If you wish to ask a question, please press star 1 on your telephone and wait for your name to be announced. If you wish to cancel your request, please press star 2. If you're on a speakerphone, please pick up the handset to ask your question. Your first question comes from Tom Allen from UBS. Please go ahead.

Good morning, Frank and Laurie. Over 21, the key driver of two of the downgrades have come from getting caught exposed to higher spot or short-term commodity prices. So that was in the case of JKMLNG 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?

Yeah, so just on a couple of points there, Tom. So first, I certainly acknowledge that the JKM in the second half, but I don't think any coal prices really had anything to really play into our results this year. It was really the JKM and the beach announcement, which were the two 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 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. Our risk management, I think, is robust. There's no doubt that when we look into the FY22 that we've closed down a lot of that. I mean, we've certainly, I think, closed down or tightened a lot of positions around that. And so you would expect us to you would expect us to continue to adopt a 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 FY22. Well, that's contracted now. And I think really we would be in terms of then contracting with FY23. I think the way we think about coal is, you know, 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, you know, 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. Yeah, that...

Thanks, Frank. So just extending your last comment there, so recognising that two-thirds of your contracted coal supply to Ararang expires at the end of FY22, can you share what your average coal price assumption is implied in your FY23 Energy Markets EBITDA guidance?

Yeah, 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 about export quality coal it tends to be a lower index so we're not expecting it to be um significantly higher might be a little bit higher but not significantly higher

might be a small small one small uplift in that number that we've assumed all right thanks frank if i can just sneak one last one in just on the way that you use the aurari 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 six months of the year by turning off uh capacity from aurari completely rather than just cycling the output up and down throughout the year

Yeah, 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 three 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 four 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 that 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 pricing 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, you know, we have to continue to plan for those scenarios going forward. Greg, did you want to add something on the RRing operations? Look, Frank, you covered it well.

Look, just to give what we did last year, we are certainly cycling those units down to, you know, mid-gen levels around 200 megawatts and then cycling 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, you know, look, we'll just assess the market all the time and we'll take those opportunities as they arise going forward.

Yeah.

I think, Greg, the only question as to whether you turn more units off or not is always just a risk management question about us protecting. It's just a risk management question of protecting against semi-price events. Yep. That's right. That's all it is. Yep.

Okay. Thanks, Greg. Thanks, Frank.

Thank you. Your next question comes from Dale Conders from Baron Joey. Please go ahead.

Morning, Frank and Laurie. Just a question on AP LNG production guidance, SLAT versus FY22. Just questioning this, given it's in contrast to your statement of having asset flexibility to adapt to markets, giving FY22 as managing maintenance, and as we look into FY23, we're seeing record spot LNG prices relative to oil. Just a question there. Can you actually produce more gas?

uh yes we can produce more gas it is there's a lead time so really um they'll answer it in sort of two parts the first is the ability obviously to flex the production within a year it isn't able to go down and come back up to use that 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 when we're giving that guidance around that 700 petajoules now, it's a function of the development activity decisions that the joint venture is making in advance of that production, probably 18 months to two years. So it'll be subject to those decisions. And therefore, that would be APLNG. That would be the ones that it'll 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 flex.

That does. I guess the second question in the actual report, there was the comment the board's considering a combination of hot water and dividends and on-market share buybacks in the future. I just wanted to marry that with leverage being at the top of settings in FY21 and FY22 either 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 loads in EBITDA before the balance sheet starts to open up?

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

Sure. Hi, Dale. Yeah, look, six months ago we changed that narrative around how we might distribute cash. Because, well, firstly, 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. We haven't done it this time based on a 7.5 cent per share dividend. But, yeah, we want to preserve the ability to do that. If we look at our balance sheet today, yeah, we've headed up to 2.9 times. Obviously, it could go higher in 2022 with lower energy markets earnings. But exactly where our balance sheet ends up depends, obviously, on oil price. But, you know, we do expect in the midterm for – for that gearing to head back down into our target range pretty quickly. And so therefore we would have the full range of capital management levers in our hands.

And just to add to Laurie's response, strategy for us is clear, but we obviously operate within the prioritisation 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 either 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 and renewables and storage will be determined by the balance sheet. And therefore, that's why we continue to look at ways where we can optimise that over time.

Okay, thank you.

Thank you. Your next question comes from Max Vickerson from Morgans. Please go ahead.

Good morning, guys. And look, I just want to circle back around on O'Raring as well, if I could. So just having a look back at the historical commodity prices, I apologise for being a bit of a backseat 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 seemed to be an opportunity to do that quite cheaply. Obviously, you didn't anticipate Callard or any of those other things. But just wondering if you could maybe give me a bit of the colour and the thinking there. Am I oversimplifying how I'm thinking about that? And then just looking forward with the RARing, IGL's made comments that their baseload fleet is maybe less effective as a means of hedging retail risk. or retail demand. I know Ararang's a pretty flexible power station, but are you seeing something similar? Should we think that maybe in the future Ararang's going to play potentially a less critical role in covering some of that peak demand?

Yeah, sure. I might just, the first one, I'll just put Greg on notice about just whether or not there was a trade to be done in the wheat 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 RRing and base load 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 market, and it does play a risk management role for us. And with a 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're 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 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 very 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 a raring 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 win CNI load, so we generally cover swap there. Just with the way we ran a raring, 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 certainly the Cali plant issue and the Yallourn issue down in Victoria, we ran raring as hard as we could, right? So we really ramped up. and you can see that we actually achieved quite a higher pool price outcome there. But look, we're always in the market buying swap if it's cheap enough, but that's predominantly to cover our CNI load.

That's great, thanks.

Thank you. Your next question comes from Mark Samter from MSP. Please go ahead.

Yeah, morning, guys. A couple of questions, if I can. Just first, I apologize. You might have covered this earlier. I have a bit of a homeschooling emergency, so apologies if this is a duplicate. That's okay. From what I can garner, at least from clients, the chairperson today is because people are panicking about the integrated gas EBITDA gardens, and without insulting your accounting sensibilities, Laurie, I would have thought for Origin, EBITDA is pretty relevant in cash distribution. is the only really pertinent number with APL&G and I mean certainly what it 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 some of these what 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 you know to confirm your point that the distribution of cash is the most important aspect of IPLG which is why we're also providing the 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 realised oil price and currency assumptions, and we just should make it clear again that that's at 68 and 75 cents.

Yeah, I agree. Seems a very strange reaction to me. But just a bigger picture one for you, Frank, we're seeing... on the EMP side of things, there's the increasing trend of go big or go home. I guess APLNG is biggish, but in the scale of EMPs more broadly, it's not big, and B2B is exciting, but you're arguably constrained by the balance sheet capacity. With everything that's going on in the world, do you still think, and I'll 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 within?

Look, I think I've been clear to you as well, Mark, over time, is that clearly we have priorities to maximise the value of those assets. We have talked about crystallising value in the shorter term for the E&P, but there's some investment we think we need to undertake to achieve those goals. HNG is a very valuable asset to us. The cash flows are valuable assets. But clearly, you know, 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 yeah, we just continue to read our portfolio and make the best choices available to us. Perfect. Thanks, Chris.

Thank you. Your next question comes from Peter Wilson from Credit Suisse. Please go ahead.

Thanks. Morning. Just a couple on your gas and your coal costs. To start with gas, the JKM, just so I get this right, the $51 million impact this year, have you calculated 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 FY22, 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 gross and net, firstly, just as it relates to 22 versus 21, the gas position is not, it is not a material uplifting gas position. 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 views 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'll 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 we just give that, I'll get someone to come back while we're on the call, just to make sure I just don't get out of territory here and I'm not sure, okay?

Yeah, that'd be great. The reason I ask, I guess, is if you add up FY21 and 22, you know, the cumulative loss, you said earlier, I think you expect that to unwind in 23, right?

I think what you should be walking away with though is that gas is not a big driver between 21 and 22 at all. It's not a big driver of difference. It's nearly all electricity. 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'd be good. I'm wondering how much of a factor the rowing coal cost is. So, I mean, I know that the change in rowing output is a factor, but if you just look at the coal cost and perhaps just think on a like-to-like 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.

Yep. 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. We've purchased a further 1 to 2 million tonnes. And that is at about $30, $40 a tonne higher. So the total blended cost in FY22 is $100 a tonne.

Okay, compared to... Track that down, yeah. Yeah, so those contracted volumes, I assume, were the same in FY21. 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 four plus one to two million tonnes, you're looking at similar volumes year on year.

Just one last one if I could. To follow up Dale's question on APL&G production growth, you mentioned that lag between investment and actually getting the 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 and then in FY21, 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?

Yeah, it's quite similar in terms of development activity, in terms of number of rigs and wells we intend to drill and bring online. We are continuously assessing and implementing opportunities to maximise the base production 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're being cautious in terms of ramping up activity to hit a production or to hit a market in a couple of years' time.

And Peter, I've just had someone send me a message that the JCAM is a gross impact for the second half.

Perfect. Thank you.

Okay, great.

Thank you. Your next question comes from Rob Coe from Morgan Stanley. Please go ahead.

Hi, Rob.

Your next question comes from Daniel Butcher from CLSA. Please go ahead.

Hi everyone. Just wanted to follow up maybe on the last question about APLNG. You've given some good guidance to FY24 and about the activity levels. I'm just sort of curious how you see activity levels after that ramping up in terms of number of wells and activity needed to maintain production as you step out to less productive areas?

Andrew, do you want to just open up and I can add to that as well? I don't think we see it dramatically shifting between 24 and 25, for example, Daniel, but we'll give you a sort of more thematic around that and then we can open up. So, Andrew, are you happy to give some colour to that?

Yeah, that's fine. So, obviously, giving guidance out, making some guidance out to 24 on total CapEx and OpEx. Within that, you see FY22 being $3 to $3.40. expect over the next couple of years for production and activity and wells drill to be pretty similar. Don't see any big step up beyond 2024. Would make the point that we've, I think, have been made on these calls for a number of years that we do develop our best fields first. Those fields decline, we replace them with less productive wells and so there is a challenge as we go forward. don't see any material step up immediately and obviously we have our levers program there to try and offset the declining field with productivity improvements and efficiencies as we go forward.

It's not an immediate step up but gradually it was sort of a five-year process towards the end of the decade. How much higher activity do you think you might see as a sort of rough ballpark guess?

I agree with what you said there. There's no immediate step up and it's very difficult to give anything and the reason we don't go beyond 24 is that there's obviously choices as we just talked about around what production we're targeting and so that's the reason we haven't given guidance beyond 24.

Okay. Second question if it's okay. Just with the MRCPS ending at the end of FY22, I imagine it's a lot less tax efficient for Conoco to get its cash back to HQ in the States. So they're probably getting about 30% less cash distributions back from the project. Do you think that lowers their interest in holding the project, even if it's the last big one in AsiaPAC? And I guess, would you be interested in picking up an extra stake in it, given how well it's performing, if you had the capacity to do so?

I don't really know what Conoco's intentions are, Daniel. I certainly, they've been, everything we've heard from Conoco is they're very pleased with their investment in in this asset and it continues to perform. It's obviously net cash producing for them, but you'll have to ask them as to how they think about their investment. I haven't really contemplated that we would step up our investment in APOMG. I haven't seen that as a sort of a base case as to where we would work from. It always depends on opportunities presented to us, but that's not in our plans at the moment.

Okay, fine, thanks. Maybe one final one, I mean you sort of talked about investing in new energy and just sort of noting that the industry as a whole has taken some big write downs or legacy PPAs that were locked in at much higher prices. Yeah. How do you, I mean I've probably asked this before but just maybe start to try again, how do you sort of think about the cost curve falling and when to get in given that you could be in a position of, you know, if you invest early, writing down those same contracts or assets in five years' time?

Yeah, well that's one of the... one of the reasons why I think the investing, firstly the investing in dispatchable capacity to start with that, whether that's storage or other assets, you're really against a falling cost curve. That's one of the reasons why you don't go too early and particularly when you've got new policy settings like the new roadmap for New South Wales, which is going to underwrite some of those, that you are actually, you know, you're going to wait for those to be in place to then to make investments. As it relates to renewables, I think the way renewables and I think business models over time for renewables will be that you will be working with customers and others in terms of the offtake for all those. And so you have to really be thoughtful around the model and how much capital you deploy to that at the right time. And that's one of the reasons why we haven't deployed large amounts of capital into those assets over recent times. If you think about it, there's been very little commitment to that And that does really all centre back around getting the right policy settings for that to occur and working with customers and governments to get the right outcomes.

Alright, thanks a lot. I'll leave it there. Thank you.

Thanks.

Thank you. Your next question comes from Rob Coe from Morgan Stanley. Please go ahead.

Yes, can you hear me this time?

I can hear you loud and clear.

Okay, great. Apologies for the last issue. I'm not sure what happened. Anyway, my question goes to the anticipated uplift in EBITDA for energy markets in FY23, the kind of plus $150 to $250. I just want to make sure I understand the composition of that as best as possible. I guess you're saying coal is in de facto a $5 to $10 pool price is a factor and then I'm guessing the cost to serve improvement is maybe 50 mil or so and the gas normalisation is a factor. Is there anything else in that 150 to 250 we should be thinking about?

No, I think you're right. Cost to serve, there'll be a gas is a factor. You're right about the $5 to $10 a megawatt hour. um whilst uh and what i will say around that is you're making assessment of range i i think the coal price might be i mean when we think of it about it we're thinking that it might be up modestly but not a big driver does that make sense if it but i do understand that depending on the volumes of that if you're up five or ten dollars in coal you know a ton um then you're you're certainly still going to have a few tens of millions associated with it but making an assessment around the range of those outcomes to be honest Rob so when rather than say coal not a factor I probably wanted to just temper my comment a little earlier to say that it's not a massive driver in the way we've currently formulated that and based on where we are in terms of advanced negotiations in replacing volumes for that coal in that year.

Yeah, okay. Yeah, thank you.

Yeah, appreciate it. Yeah, and so that's probably the reason why, you know, you're in, we're always in negotiations for that, but that's when you're producing a range of outcomes. So rather than leave the view that coal doesn't have any impact, I would just say that, you know, I was trying to put that into context as to where I'm thinking at this point in time.

Okay, yep, that makes sense.

And based on, by the way, I should say lastly, because we've talked about forward prices, So that coal price is in backwardation. And when you think about the discount for $5,500, so that's informing our thinking. Obviously, if markets change, then that could have some impact, but that's the way we think about that now.

Yep. Okay. That makes sense. And then if I can ask a second question around the octopus investment, just if you could share how you guys think about the valuation for that and your thoughts on, I guess, options for exit strategies going forward. And I guess this year you've called out maybe 200-ish million of investment, some of which is the deferred consideration, which was always part of the deal. Are you contemplating an extra 75 mil investment in the origin this year? Is that the way I should be interpreting those comments?

No, just... So the investment that's actually going in this year is all part of the deal. If you're talking at FY22, it's associated with all part of the deal. Octopus from time to time may contemplate whether it's going to raise more equity, at which point we have to consider our position, but that's not contemplated in our capital investment guidance that we've given. It's just all part of the deal that was done when we made our initial investment. It's just a third consideration for that deal. As it relates to octopus, the growth has exceeded our expectations in almost every facet. So we think a bit about that in terms of our retail business plus the licensing revenue on the technology business. They're probably the two key drivers to it. Both of those exceeded our expectations. And therefore, just very happy with the investment at the moment, haven't contemplated the exit. But clearly, we're a minority shareholder. in a vehicle rapidly growing. So we'll continue to assess it as time goes on, both opportunities, whether or not we should invest more or whether there's realisation opportunities, but very happy at the moment and don't have an intention to realise that at this point.

Okay, cool. Thank you. And then finally, just a minor one, I guess within the new group EBITDA guidance, where you've kind of combined integrated gas and corporate, should we be thinking as corporate roughly

Yeah, I think that's the best way. Laurie, that's probably the best way to think about it, isn't it?

That's right. I also, in responding to Mark, I forgot to mention as well as corporate, there's some originally costs in the integrated gas business and also the hedging program, which which in the fine print on the guidance slide, we talk about $134 million worth of hedge losses at the assumed oil price and exchange rate that the forecast is underpinned by.

Great. Thanks very much.

Thank you. Your next question comes from Ian Miles from Macquarie Group. Please go ahead.

Good morning, guys. Just firstly on your net debt, you talk about a circa $4 billion or trying to get it below that. Given the structural change in energy markets' earnings power, has there been any reconsideration of those targets of sub-three times as being the appropriate net debt to EBITDA, or should we refer to it as sub-two times, should I say?

Yeah, that's why. I think that two to three times still works and that will still be consistent for our current rating. But having said that, because earnings will decline in FY22, we felt it relevant to provide guidance of the fact that we're sitting at net debt of $4.6 billion and we would expect it to continue to come down and we would be targeting for it to continue to come down. So obviously if you're focused just on the ratio, you might think all's well, no need to pay down debt, but it is our ambition to continue to pay down that debt to get it below that $4 billion that we called out.

I guess, how does that then constrain the opportunity set to try and grow the business? Assets like, for instance, the Meridian assets, which may suit Origin or progressing with battery developments or even some of the hydro. How has that been affecting it? Are we looking at a very tight balance sheet that needs to use new equity to facilitate then the growth?

Yeah, I think I'd describe it as prudent capital management. And, you know, we've been... I guess we've been focused on debt reduction over a period of time. And so the language has changed to say we're now allocating our capital in a more balanced way. So it's not all going to be debt reduction. We can moderate the rate of debt reduction in order to create some capacity to invest in other things. The other message is we can see sustained capital trending down which again releases a bit more capital for growth. We've also said that we would look to bring other capital into our projects and so we would partner to bring in some of that new capital that's required.

Okay. And Frank, just from a perspective of opportunities like Meridian, are they consistent or suitable for someone like Origin, or are you far more looking at just developing Kraken and growing the business, what you've got?

I think, Ian, we will always look at those opportunities. Every one of them is a slightly different one. You could see Meridian as an example, distinct brand, PowerShop, good customer base, smaller customer base, you know, and also has a renewable portfolio. And so you have to think about both of them in combination. But we do continue to look at, I would call those retail opportunities. I know I just, I caveated on this one a little bit because it's also got a renewable portfolio, but we do look at those opportunities and you would expect us to be exploring them and they just come down to the individual characteristics of them. But yeah, we would look at inorganic opportunities for that retail and growing that customer base. Yeah.

Okay. And in terms of batteries, are we a long way away from seeing Origin actually pull the trigger? Because it seems like nearly everyone else around you is actually committed to some sort of leash one hour or two hour battery. Yeah.

I think if you looked over the last, we certainly have been very close to pulling a trigger. Then you actually see that more capacity gets added into a market. And so you want to be mindful about the nature of those contracts that you're entering into. I think that if you really looked at it in advance, I mean, You've got Tallawurra and you've got the gas plant that comes in. I know they all perform different roles and you've got a falling cost curve. So you do want to make sure that when you're bidding into these things, they generally are supported by a revenue stream of some form. And if we looked at New South Wales, then you'd clearly be looking to that roadmap as the basis upon which you'd entered into them. Unless, of course, you were thinking we'd make them purely on a merchant basis. You could do that in a modest way, to be honest, Ian, and that would be fine, but it won't it won't be in the more material way. I think you'd want to be thinking about that market risk a little bit more, and particularly given just how quickly those costs are declining. So I think it's just all timeliness really right now and as this evolves. Okay, and we've seen we've got a number of sites ready to go, so it's just picking up right now.

Okay, that's great. Thank you, guys.

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

Well, thank you very much. Can I pick up a comment that you're going to undertake a major turnaround, a maintenance set of roaring this year? Can I just get some background on that and when you're taking it and how you put it in voltage?

Thank you. Yeah, sure. Greg, are you happy to just describe just the outage that's underway, just so that it puts it into context for everyone?

Yeah, look, just by coincidence, we are having a major outage on Unit 4 to Roaring as it starts today. It's a nine-week outage. This is an outage that we delayed from last year. But, you know, you get to a point where you certainly don't want to delay it any longer because you just need to do that maintenance, and that's underway as we speak.

Yeah, just one of the units, they sort of write every year there's generally one unit, isn't it Greg? They're on a sort of four or five year cycle. So that tends to be, it's just.

But where the industry is going is that, you know, especially for the black coal fire units, you know, certain major outages are sort of out to the, you know, we look at these, you know, it's been pushed out to five years and once upon a time was, we did it every three years, but they're sort of, we've moved it out to five years and we can safely and reliably run these assets with these major outages. Okay, thank you.

It's all from me.

Thank you. Your next question comes from Dale Conders from Baron Joey. Please go ahead.

Thanks for taking the follow-up question. I just want to ask on slide 16, when you look at the two charts compared for FY22 and 23, the effective price after contract lag line, the dotted grey line, is that correct? or does the line in 22 actually include the hedging? Because as it shows in terms of price re-opening in ABLNG, that's reducing both downside price protection and realized prices.

Dale, my understanding is that the lines definitely are inclusive of hedge premiums.

Okay, so there's no change in the contract. That's good to know. Just in terms of your hedging activity, As we roll through this pinch point on balance sheet in FY22, how are you thinking about, I guess, volume and directional risk in hedging activity?

I hinted at it in my presentation commentary that with lower energy markets earnings, our earnings have a greater exposure to oil. And so we obviously have to think about that, and we have done so, and I suggested... So we're unlikely to change the FY22 position, but in 23 with, what is that, 4.4 million barrels hedged effectively and a total exposure of just over 20 million barrels, it could be that we'll hedge some more. probably during this financial year and ahead of the 23 financial year. But, you know, we'll make that decision from time to time and most likely it would be layered in over time if we did it.

Okay, and finally, yeah, that does. I guess finally where I'm kind of a bit confused is why you continue to hold APLNG at the current level given there's an argument for selling down the asset to fix the balance sheet and facilitate growth if Origin doesn't want to wear the oil price exposure?

We're always thinking about our portfolio though. That's as far as I'll go. We're always thinking about it.

Okay, thank you.

Thank you. Your next question comes from Alastair Rankin from Royal Bank of Canada. Please go ahead.

Yeah, good morning, guys. I just had a question around the wholesale energy price forecast that you guys have beyond FY23. So you think there's going to be a bit of a rebound there. Can you comment just on what you think is driving that rebound?

Sorry, I just missed you. I'm sorry. I'll say that just one more time, the rebound and what's in there. Just say that one more time. Sorry about that.

No, you're right. So you've got in your results that there's an FY23 rebound in wholesale energy prices. What do you see as driving that?

Really, what that is, is really the commodity. The wholesale electricity price now is relative to what's sitting within the FY22 number. The current forward prices, they're about $5 to $10 higher. and on the premise that those $5 to $10 a megawatt higher retain based on the fact that there has been, I would say, more risk premium that's come back into the market based on the events over the recent months, if those persist, then we would get the benefit of that wholesale price benefit. If it continued, and that's why you always have to be very mindful about when you make these that you're careful that, of course, it would need to continue such that it actually translated through the tariffs in the FY23 year. But currently where those forward prices are, they're better than what was done to set the ones in FY22. So hopefully that explains what sits behind our rationale.

Yep. Just another one, I guess, on some of the longer dated forward earnings that would sort of drive your valuation for your generation assets, in particular erroring. The post FY25 market redesign, Kerry Schott has spoken about capacity payments and some other market payments as well. Have you considered that in the valuation for those other generation assets?

No, not really. What we have thought about is what's the right settings for the market for really what would drive the investment in new generation, but also at the same time, where we've got rules that require us to give 42 months notice for existing generation. How do we make sure that those plants, while they are in the market, providing those services that everyone says are so valuable that they're adequately rewarded to do that? So that's what it really is factoring in. And so that's really around getting the right settings because we actually all need this market to transition away from the existing fleet of sort of coal assets in a pretty orderly way and also facilitate to the earlier question for me and others that you'll invest in new dispatchable capacity and drive that trigger because no one's really been investing that in any meaningful way over recent time so that's really our it's really around getting that right for the services that those plants provide in a market that is clearly very different in a world of high renewable low marginal cost production of energy.

Okay, thanks. That's all from me. Matt.

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

Okay, so thank you very much for joining today and really appreciate all of the questions. Just further to Mark's comment earlier, I hope people have got some greater clarity around that that guidance really does include not just integrated gas and energy markets. It includes corporate and IG only costs so that hopefully that everyone can see their way through that and therefore that's clear for you. We look forward to catching up with many investors over the coming days and look forward to speaking to you soon. Thanks very much everyone. Bye.

That does conclude our conference for today. Thank you for participating. You may now disconnect.