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, CEO. Please go ahead.

Okay. Thank you very much, and good morning, everyone. Thank you for joining Origin Energy 2020 Full Year Results Call. This is Frank Calabria here, and I'm joined by my leadership team today, which includes Lawrie Tremaine, Greg Jarvis, Mark Schubert, Tony Lucas, Jon Briskin and Kate Jordan. So Lawrie and I will take you through the presentation and at the conclusion of which, there will be an opportunity for you to ask questions, and we look forward to that. Our format is consistent to previous presentations. So I'll take you through the performance highlights for the year, and I'm just trying to get slides to move on as I'm controlling them for you as well. And Lawrie will take you through the financial overview, and then I'll provide an operational review and outlook. So I think we're good on going. So just starting with performance highlights. I'll take you to Slide 4. Our summary of financial performance, our statutory profit for the full year was $83 million, and that reflects a stable underlying profit of just over $1 billion. And it also reflects in the statutory profit, the previously announced year-end impairments and adjustments, which were primarily driven by the revised oil and LNG price assumptions that we made over the medium to longer term. Our underlying return on capital employed is at 8.8%, slightly down from last year. I'm very pleased to say that our free cash flow increased by over $100 million to $1.6 billion, and that's driven by the record production by Australia Pacific LNG and also a record cash distribution of just under $1.3 billion there. So that's up $300 million from the prior year. Our adjusted net debt decreased by just under $800 million. You can see they're down $773 million to $4.6 billion. We've reported the number there, excluding the lease liabilities, but for transparency because the accounting standards have now included those lease liabilities, if you include them at $5.2 billion, but I think the key story there is that debt is reduced by just under $800 million. And we -- the Board is determined to pay an unfranked final dividend of $0.10 per share, which does equate to just underneath the 30% of our free cash flow, and Lawrie will take you through further that at the moment. When I reflect on the financial year just gone, I really am very pleased about the strength of our operational and financial performance, and we've included some highlights there, just on Page 5. I did just mention the record production and cash distribution from APLNG, but also there's the 5% increase in the APLNG 2P-operated reserves before production. We're on track for our $100 million reduction to cost to serve in retail, and we've now achieved $73 million of that at the end of this financial year. That's a target to achieve $100 million by the next one, financial year '21. From a customer experience perspective, we've recorded our best-ever Net Promoter Score, which is one measure of customer satisfaction, but across all of our customer satisfaction measures, I think we've had a record year. I'm very pleased to see that we -- for our people, that we've been able to lift our engagement to be top quartile at 75% score. And also, there's been a very strong improvement in our safety performance over the year, following a more disappointing result to that measure last year. The increased cash flow has enabled us, as you can see, to underpin both debt reduction, the payment of dividends, but also the investment in future growth. And you know that one of those decisions over the recent months was the investment in Octopus. We remain committed, if I take you to Slide 6, delivering for all of our stakeholders, our customers, the communities, our people and shareholders. You can see there in terms of customer and transforming that experience, that increase in our Net Promoter Scores that I just mentioned. In terms of community, a couple of things, pleased to see that we have reduced our Scope 1 and Scope 2 emissions by about 9% over the last financial year, largely due to the changing way in which we're operating Eraring in response to those market conditions. And also, you can see in terms of support for local communities, the percentage of our total spend that now is through regional suppliers has increased from 12% to 14%. There, on the right-hand side, are those 2 measures on both improved safety performance. Our total recordable injury frequency rate, you can see there is at 2.6. That's a 40% improvement year-on-year, which I'm very pleased to see from the commitment of our people. And also very pleased to see that through these -- what's been an extraordinary year, I'm sure you'll all agree to see our staff engagement increasing to 75%. We are driven by our purpose of getting energy right for our customers, communities and planet. And I think if you look at the last 12 months, it's been extraordinary by any measure. There's been drought, bushfires. There's been extreme events, particularly storms that caused issues in Western Victoria as well as the COVID-19 pandemic. And firstly, what I would say is that we've been very much focused on supporting our customers through those events through relief. There's been reduced prices that have occurred throughout for our customers on 1 July. And very pleasingly, through all of these circumstances, the way we've been able to maintain reliable energy supply has been fantastic. We continue, as you will see in the slide following that, that experience and the way we operate our business is responding to those changes as well. That's another feature, I think, that we've seen. For our communities, we spent $365 million in regional businesses. The Origin Energy Foundation, which is just 10 years old now, contributed a further $2.9 million over the last 12 months. And you can see donations to bushfires, drought initiatives and volunteering. It really is a feature of what we stand for at Origin in terms of supporting communities, both broadly and locally. I did mention our Scope 1 and 2 emissions reducing by 10%. We've set a Scope 1 emissions reduction target to reduce by 10% on average over the financial years '21 to '23. That's off the baseline that we set with the science-based target initiative in 2017. And I think that equates to being a further 7% reduction of the -- what we achieved in 2020 financial year. We have an aim to achieve net zero emissions by 2050. And you'll note that through the course of the year, we published a scenario analysis to show our wholesale electricity supply portfolio, all of our generation and other contracts of what that scenario of 1.5 degrees would look like. So really pleased to see the ongoing progress in relation to decarbonization. It really has been an unprecedented year in terms of commodity markets, and I think Slide 8 really does highlight what all of you will know. The key commodity markets we've highlighted there are the JCC because that links through to our LNG sales contracts, the domestic gas price, where we're both a buyer and seller in that market and also the forward electricity prices, and you can just see the extent of the change that's occurred over recent months. The one thing I'd just point out on a couple of these that many of these have not yet received the full impact because, in the case of APLNG, there's a lag between those prices flowing through to the sales contracts that are very much a feature of the FY '21 year. In the case of the domestic gas prices, certainly, we've been able to adapt our portfolio and buy gas in that market and be able to manage that, so that we did receive the short-term benefit of those less gas prices by buying and taking those opportunities over recent months. And in the case of electricity, it really takes time for that to flow through to both underlying tariffs in the mass market and also the recontracting in the C&I book, which is underway. The best way to think about that exposure, though, is that if you think we've got a fixed cost generation position of somewhere between 15 to 20 terawatt hours depending on how we run the portfolio. Otherwise, the balance of our energy is being purchased in the market, so you tend to get the lagged effect of the benefits of both buying and selling in that market. We'll take you through further that in a moment. And if I then talk about just really the response to COVID, and I'm sure all of you are hearing this from the various companies you're investing in, the key impacts to COVID if you've seen really with that prior slide, when we're looking at the commodity prices, and probably in the case of the domestic electricity and the global and domestic gas prices, they sort of really are a reflection of the demand that we're seeing in our markets and also the linkage in the case of gas to international markets that's having that flow-through impact. You can see there that the average electricity and gas demand is down about 5% to 10% overall, which is really a reflection of the reduction in the C&I and SME customer market, and it's offset by modest increases in the residential demand. And that's obviously played out. We put it in our quarterly report, you would have seen how that pattern evolved over the last quarter. Obviously, since the end of the year, we sort of almost got a 2-speed scenario going on in Victoria, going back to what it looked like in April, and the balance of the states continuing the trend you would have seen that finished that financial year or towards the end of June. We did announce a $40 million increase in our bad and doubtful debts provision. There was a postponement of the APLNG major shutdown until July '21, and we temporarily paused the Beetaloo exploration program and planning to recommence this quarter next to get back going on that. And really, overall, I think we've been able to transition safely 4,000 people working from home. And just as importantly, we've been able to continue to operate our sites, our LPG terminals and our gas fields under strict health and safety measures. And I really am very pleased to see that we've been able to maintain a very reliable supply. Our response in this sense is firstly focus on the health and safety of our people. That's where it starts. And then you can see there that's very much focused about supporting our customers. We paused the default listings, disconnections and late payment fees. We continue the hardship and payment extensions. And as you know, that was -- we moved early on that. It's at least aligned, if not better than what was required under the AAR statement of expectations and recently announced that, that statement of expectations would continue through to 31st of October, and that continues to be the way we support our customers. We're very much focused, as I say, on the health and safety of our people. And clearly, as this continues, both mental and physical well-being of our people is key and providing the flexibility and support is important. I think one of the features of both our Energy Markets and Integrated Gas business has been our ability to be able to adapt to those changing market conditions, which I'll take you further through on the operational review. The 2 probably big examples of that are really the flexing down of the way we can run Eraring and also run our gas fleet of power stations, but also flexing the output of APLNG in response to that lower demand. We did announce a couple of months ago, what we were targeting in terms of cost reductions, APLNG costs coming down between $300 million and $500 million. Origin CapEx outside of APLNG will also be lower and we've really made some inroads into that. As I've mentioned before, the $100 million retail cost to serve is on track, and that's before you consider the further activity underway to take that -- to take further cost out, that will be part of the Octopus proposition of both customer experience and cost. And also, what's happened is that over the last month or so, we've extended our debt maturity profile and Lawrie will take that through these so we've got significant headroom and liquidity. So we continue -- we've made response operationally. We're resilient, and we continue to respond to the circumstances in the market that we face. Just in terms of that economic recovery, I think it's very important to see that, that's going to be something that needs to be coordinated between business and government, and that does provide policy opportunities. I think the -- in terms of importance, the key area that I think the electricity markets need to respond to is what we call the introduction of firming capacity in the market. The renewables have grown. And whilst it may have slowed in recent months, there's still a wave of renewables that are coming into the market being constructed and coming in. And it really is the addition of what we call that flexible firming capacity, which we see as a combination of batteries, hydro and fast-start gas. And investing in those requires an understanding of how we see those risks over time, and that's where policies become important to the investment confidence there. Gas development, it's been well reported that one of the key things to bring gas prices down is to increase gas supply. And therefore, one of the areas, and I've seen comments coming through from governments is that the focus there, and we agree completely regarding removing restrictions, streamlining approvals and regulation, releasing acreage are all ways in which governments can work with the industry to actually bring more supply on. I think associated with that investment in firming generation is really, I believe, it's important when we see the changing electricity markets that the national electricity market, and I think this post-2025 market review being led by the ESB, is I think where we see that everything should be brought together in a coordinated way, and it's a great opportunity, I believe, to produce better outcomes over time. And that's got to be the key focus, I think, of both policymakers, industry and governments to work together to give confidence longer term. And clearly, that leads into the next one about longer-term integrated energy and carbon policy. That's what we see there. So the economic impacts of the pandemic are still being -- obviously, they're likely to be significant and ongoing, and therefore, customers will need support. You can see that retailers and for the early months network supported, but it is going to be support that I believe the cost of which must be borne right across the supply chain. And I think that's one of the key things that we need to continue to do as an energy industry as a whole. Our strategy is to create value in this changing energy landscape. You've seen this slide before. You can see that's all about the transition from coal to renewables firm by what we call that fast-start gas and storage. It's about being a low-cost producer of that gas because of the linkage between gas and those electricity markets, but also to the gas demand here and in the Asia Pacific. There's been good progress in technologies. The Octopus, Kraken platform, we've developed a VPP, and we're also pursuing opportunities in new areas of energy, such as we're actively pursuing in hydrogen, e-mobility and small-scale LNG. And clearly, our strategy remains on continuing to advance that customer experience including the investment in the right technology solutions and culture that actually enables us to gain that trust over time. So you can see that there's been good progress towards that across both of our businesses. We have step-changed our customer experience and cost even over the last 2 years, but I think Octopus has the opportunity to go again, and that's exciting for us. We are progressing brownfield generation and storage opportunities, but I just talked about both the settings and also the market signals that would need to be there. It's just about our ability to respond when they are appropriate. We now have 85 megawatts being orchestrated through our virtual power plant. That's greater than 11,000 customers, and we announced a partnership with OhmConnect, a U.S.-based demand response business. And jointly, we've launched the equivalent of that in the Australian market in the last week, what we call Spike. And we've got EV charging and fleet management solutions underway, including a trial that was recently announced in the ICT. You can see we've reduced our breakeven in integrated gas down to being USD 29 a barrel. That's a distribution breakeven and includes, I think, somewhere in the vicinity of $12 of project finance. So we are becoming, every year, a more competitive and lower-cost upstream gas producer and we continue to see opportunities to improve that. Clearly, we're very focused on the Beetaloo opportunity, which is an opportunity to take what we're doing in the APLNG as upstream operator and translate that, and I'll talk a little bit about the way that program progresses. And I've discussed with you that we're actively pursuing green hydrogen and small-scale LNG. So on that note, I'm going to pass over to Lawrie, and he'll take you through the financial performance.

Thanks, Frank, and good morning, everyone. I'm going to start with -- start on Slide 14 on our strong set of financial results. These have been made possible by good execution in a challenging environment. The highlight is the record distributions from APLNG, contributing to a 7% increase in free cash flow to over $1.6 billion. This higher free cash flow enabled us to reduce net debt by over $770 million to $4.6 billion or $5.2 billion with the impact of lease liabilities. Underlying profit was stable at just over $1 billion, however, statutory profit declined due to the APLNG impairment and Cameron onerous contract provision charges announced in July. Underlying ROCE reduced slightly, reflecting stable profitability and returns from our upstream business, offset by lower returns in the Energy Markets business reducing down to just over 10%. Moving on to Slide 15. We've booked a $746 million impairment of our investment in APLNG and have recognized an onerous contract provision of $455 million post-tax associated with our 20-year Cameron LNG purchase contract. In both cases, these charges largely reflect lower short- and longer-term commodity price assumptions. The impact of lower oil and JKM prices on the APLNG investment was partially offset by stronger field and operational outlook. Under the Cameron contract, Origin purchases LNG at a Henry Hub linked price plus a fixed tolling fee. We assume onward sale at JKM prices. The onerous contract provision is the result of an assumed contraction in the spread between Henry Hub and JKM prices. We currently estimate an after-tax cost of around $25 million per annum. Under accounting standards, this cash flow is then discounted at U.S. Treasury bond rates, the average over the contract period was a low 0.81%. Moving to Slide 16. And this is just a reminder that we've adopted the new lease standard, and we've also changed our treatment of dewatering and workover costs at APLNG. This is consistent with our treatment at the half year. The impact of both changes on underlying profit in 2020 is minimal, but you'll need to take note of the expenses moving around between EBITDA, depreciation and financing costs. We've provided additional disclosures in the OFR and financial statements to make these movements clearer. Underlying profit on Slide 17 was stable year-on-year. Again, a great result in a challenging environment. Lower earnings in our Energy Markets business was consistent with the midpoint of guidance. This was more than offset by lower integrated gas commodity hedging costs and lower corporate costs which were helped by the nonrepeat of last year's remediation provision increase. Adoption of the new leasing standard explains most of the increase in D&A with offsetting lower lease charges across each of our business segments. Net interest costs are again lower due to lower debt and lower average interest rates. On Slide 18, you can see Energy Markets earnings were down $115 million or 7%, with all of the decrease coming from the electricity division, partially offset by higher gas gross profit and lower cost to serve. Electricity gross profit decreased $203 million with lower margin and volumes. Margin was down $136 million, mainly due to the introduction of the VDO and DMO price reregulation, and to a lesser extent, unplanned outages at Eraring and Mortlake power stations. Lower sales volumes impacted earnings by $67 million, primarily driven by milder weather, lower usage from solar and efficiency gains and COVID-19 impacts on demand. Gas gross profit was up $29 million with lower procurement costs, partially offset by lower volumes due to the roll-off of short-term wholesale contracts in the prior year. Our cost-out program is well underway with cost of serve down $40 million year-on-year, and remain on track for the $100 million cost reduction to cost to serve against the 2018 financial year baseline. Turning now to Integrated Gas on Slide 19. Our Integrated Gas business EBITDA was down $44 million or 2%, excluding the impact of the accounting changes. LNG revenue was down $100 million, mainly due to mix, with contract offtakers exercising their full downward volume flexibility from the second half. This resulted in a higher proportion of spot LNG volumes sold into a weaker market. Realized LNG contract prices were flat in Australian dollar terms. Domestic revenue was down $45 million with reduced volumes and average prices. Lower revenue was partially offset by operating cost savings, including lower gas purchases. Also offsetting lower revenue was lower Origin oil and LNG hedging and trading costs. And finally, a recovery of Origin overhead costs from APLNG is based on the level of direct operating and development spending. As we have reduced direct spending, we are now under recovering against those overhead costs. This has increased these overhead -- these net overhead costs year-on-year. Turning to cash flow on Slide 20. Operating cash flow was $951 million, down $374 million. This was more than explained by a $465 million unfavorable movement in electricity futures exchange collateral, which will unwind as positions are settled and also a higher tax paid on prior year earnings of $105 million. We delivered strong free cash flow, an increase of $105 million on the prior year, excluding the Octopus Energy investment. This strong performance was driven by record distributions from APLNG of just under $1.3 billion and a significant further reduction in interest paid. The result represents a free cash flow yield of 16% and a cash conversion, excluding the futures exchange collateral of 93%. Moving next to capital structure and dividends on Slide 21. We continue to target debt-to-EBITDA in the 2 to 3x range. And I'm pleased to say we're currently at the low end of the range at 2.1x. Staying within the range will be tougher this coming year, as EBITDA reduces with lower commodity prices and lower energy market earnings. A final unfranked dividend of $0.10 per share has been declared, bringing the full year distribution to $0.25 per share, which apart from the franking is in line with the prior year. We have previously foreshadowed a low franking account balance due to the timing of tax deductions from realized foreign exchange losses on debt maturities. We're also planning to accelerate debt reductions related to our Poseidon asset. The full year dividend represents 27% of free cash flow, slightly below our target range of 30% to 50%, but appropriate given the uncertain business conditions we currently face. Slide 22 shows that we've remained active in managing our debt book, increasing the average term to maturity to 3.9 years. Since 2018, annual interest paid is reduced by more than $160 million, and the average interest rate has reduced by 170 basis points to 4.8%. Around $900 million of undrawn liquidity has been canceled in the past year or so, substantially reducing commitment fees. We currently hold $4.1 billion of liquidity predominantly to fund the debt maturities due over the coming 18 months. Turning now to Slide 23 and how we're responding to the current environment. We feel resilient to the company progressively over recent years, as Frank said earlier. Most importantly, we have reduced our gearing. We've also structurally lowered capital, operating and financing costs in our upstream business. The distribution at breakeven has been lowered to USD 29 per barrel. We'll further reduce APLNG CapEx by USD 300 million to USD 500 million in 2021. We are structurally lowering the cost in our retail business. And our partnership with Octopus Energy will enable us to achieve further material cost reductions in cost while also delivering a radical improvement in customer experience. Our preference is to build our resilience through the structural levers. However, in the medium term, we will maintain an appropriate level of commodity hedging. For 2021, we have hedged 6.4 million barrels of our 22 million barrel exposure. At July, 3.7 million hedged barrels have been realized at a price of approximately USD 55 per barrel. At current forward prices, we estimate an oil hedging gain of around $100 million in the current financial year. So with that, I'll hand back to Frank for our operational performance review.

Thanks very much, Lawrie. Okay. I'll just take you through some slides on operations of both Energy Markets and Integrated Gas. Starting with Energy Markets, and I'm now on Page 26. I did mention earlier about our ability to adapt to these changing market conditions. And highlighted on this slide is how we've done that through the course of the last year compared to the prior financial year for both electricity and gas. You can see in electricity what we've done over the last year is we've reduced the output of Eraring in response to lower demand. And as wholesale sales contracts have expired, shorter-term contracts, we've then redirected that gas into gas-fired generation, and you can see that's how we've adapted our portfolio. In the case of gas, you can see there that we've increased the amount of gas that we've purchased regarding -- linked to oil and JKM, and that's probably one of the key things we've done there. That's led to a lower cost of gas purchases between the 2 financial years. So you can see that in terms of the supply portfolio. Just really expanding on that a little further, here is an example, really, over the month of June is just how we've been changing the way we operate Eraring in response to those changing conditions. You can see there that their average is over the full month. And what we really are doing is responding to the changing profile throughout the day where volumes and oil prices are low, and you can see that price profile, and how we really are operating Eraring in a far more flexible fashion. Now we're able to do that by virtue of both the inherent flexibility of the plant, but also by virtue of the fact that we remain flexible to the way we purchase our coal and get it delivered and manage our inventories and arrangements with coal. And therefore, that's giving us the choices to be able to do that. And as you can see there, we're sort of running them much lower volumes early morning in the middle of the day when solar comes in. We've -- the plant has performed very well over the last year, and you can see that, that's a feature -- that's strength for Origin. On the next Slide 28, just showing you where wholesale electricity prices have really moved. And I'm sure you've all observed just how low they've become. What we've done here, though, is to show just where they sit relative to the cost of new generation, both firm and nonfirm. And you can see now that the wholesale prices across the national electricity market are actually below the cost of new generation firming and even now makes even nonfirm, just a renewables PPA without that earning cost to be marginal. So as I stated earlier, we are progressing those brownfield opportunities, and I did touch on both the policy settings being right but you can see also that the market signals would need to be right, making it more difficult to invest in any other generation and storage at the moment. But what we're doing is making sure we're ready for that, should that situation change. And I should add to that the fact that we're not needing to invest in that based on the current portfolio we have today in terms of the capacity available, but we remain ready to it as the market continues to transition. Turning to Slide 29. You can see there that, that's the supply portfolio for gas that's continued to perform well. And you can see we increased our natural gas gross profit over the last 12 months. It's based on the competitive nature of that supply portfolio. I talked about the increased proportion being linked to oil and JKM purchases, but also we've taken advantage of shorter-term purchases as the gas prices are reduced. And it continues to be a feature of strength for the business. In financial year '21, we have a couple of long-term transport capacity sales contracts and so on. We repurchased rolling off that have attributed a benefit, and that's one of the key drivers of the guidance of the gas market over -- the gas business over the 12 months next year. There's always things coming in and out of that portfolio, but we just thought we'd highlight that given the nature of those being there and one of the drivers year-on-year. Our portfolio continues to be supplied well medium term, and we continued to actively be in the market for gas supply. There are, as you should all be aware, price reviews underway, BHP and Exxon, both in respect of Longford and also Beach. What we've done in the bottom point there on that slide is highlight the volumes that are subject to those reviews, which effectively equates to be about 35 petajoules per annum, but in FY '21 and the 35 petajoules repricing in FY '22 across those 3 price reviews. And we are underway in all those price reviews at the moment, negotiations and arbitration depending on the counterparty. We presented this slide before just to make sure that everyone is aware of what the drivers are for the business. Wholesale prices, as you can see, have reduced, they reduced demand. We do expect based on where you can see that new build, but also where prices are in the electricity market relative to short-run marginal costs in the middle of the day that we're going to see the movement around. We think there'll be more volatility, and we certainly see that, that's driving decisions across the national electricity market of lesser maintenance, reductions in CapEx, and we remain confident that they're certainly not going to go further down. In fact, if anything, they feel to us that they're unsustainable at these levels, but that's where the wholesale price is. And we have about 15 to 20 terawatts of relatively fixed cost out of our supply. So relatively fixed cost because we're always in the market buying coal and gas, but nevertheless, that's how you should think about that, our exposure to it over time. Similarly, as we've reported previously, we've got 3 million certificates of fixed cost PPAs. Stockyard Hill will come on and reduce that over time, and we're expecting that towards the back end of this calendar year. But nevertheless, you should think about the exposure to that market through those 3 million certificates. And in the case of gas, we've got 50 to 60 petajoules of long-term fixed cost supply, and I'm sure many of you will be aware that the large majority of that or a significant majority of that is a long-term contract that was struck between APLNG before we form that joint venture. Fuel costs, we remain -- we have 4 million tonnes per annum. We're currently using 5 million to 6 million tonnes. So we're certainly out sitting with a long take-or-pay position on coal, and we continue to be in market for that. And also we continue to actually be in market as lower short-term prices for gas are available, that we continue to be a buyer of gas in that market. In terms of firming capacity, we are covered for our peak demand. It is a flexible portfolio, as I think we've highlighted. We have certainly continue to look at storage and other opportunities, and we believe they will come in, and I think it's about the opportunities they present and as those costs reduce. In terms of volume demand, over the course of the next 12 months, we expect volume demand to be reasonably stable. There will be the same thing, population growth offset by usage. There will continue to be some solar penetration efficiency, but we're certainly not seeing the demand in the volume drivers that we saw this year repeating next year when we think about guidance. The one thing we add leverage is a little bit more than our competitors is that the solar increase is occurring more in New South Wales than other markets, and we've obviously got a higher exposure of electricity in that market, and we remain disciplined in our customer lifetime value approach. If I just take you to that customer lifetime, you can see that we grew customers largely underpinned by residential gas and our community energy services business. Churn is continuing to reduce. You can see the moves in new connections, they represent a greater proportion of what's going on in the market. And you can see our customer satisfaction scores regarding those channels, and that's been a strength. We continue to just manage, as I said to you earlier, just a disciplined approach to that lifetime value and increasingly able to target customers through our data and analytics. If you look at the retail strategy, I said before, NPS up, the clearly big drives of increase -- drivers of increase in the terms of the way we interact with our customers digitally, highlighted by those statistics on the left. The cost to serve, I've stated earlier, and you can see there the progress against that. And also, you can see the growth in that community energy services business, which is very good to see that we've both done that organically and through bolt-on acquisitions. And we continue to organically grow the broadband business, improve its customer experience, and going forward, same with our solar business. Octopus Energy, we announced several months ago, that's on track. We expect to have 50,000 customers migrated on to the platform by the end of this calendar year. Octopus continues to grow customers in its market. COVID certainly for a couple of months there, had that growth slowing and that growth has actually rebounded as that markets open back up, but it will be a little dependent on that. But certainly performing as we would have expected, and remain very focused and on track to deliver that -- the platform. They are progressing well with the EON migration of customers onto their platform into the U.K. Clearly, a feature that we've described are now taking shape in a number of forms is really this ongoing convergence and leading in that way between data and energy. For the cloud migration of all of our systems, we will have them by the end of calendar year '21. So we're very well advanced. Over 65% of applications are being migrated. That's driving cost efficiencies in our business, but also performance improvements. The data and analytics capability is playing out, not only in our core business and across it in many, many ways, but also it's playing out in terms of the build-out of our virtual power plant and the artificial intelligence in that and the continued propositions that will flow from that. And you can see there that, that's also now translated through our orchestration layer there to have over 85 megawatts that we're now connected to that platform, and we're continuing to optimize customer energy use, wholesale portfolio, and that will continue to grow. As I said earlier, we've launched the demand response business that's gamified that demand response in the last week called Spike and developing a portable battery product with Orison and the EV smart trial underway. And clearly starting to expand now what data sharing ecosystems are, we've started a collaboration with one of the network businesses where data is now being provided on grid stability at a very localized level. So we're starting to see the use case and benefit of this work playing out and we'll continue to feature going forward. I will now take you to Integrated Gas. And the first thing there is very, very pleased to see on Slide 36, just how we progressed our reserves. Over the last 3 years, we've replaced our 2P reserves at 90% of production, which is an outstanding performance. And you can just see the progress over time since 2012, just what we've added in 2P before production. So our reserve base is largely derisked. We have now 70% of that in 1P or produced. And we've seen very strong operating fuel performance that has continued to strengthen over the last 12 months. It's across Combabula, Condabri, Talinga and Orana. We really have seen increases in estimated recovery across all of those fields, and we've been able to add the Peat Flank reserves after successful appraisal. We continue our E&A program and mature the resource base. The Peat Flank pilots are confirming an area that's feasible for development and the East Bowen Deeps pilots are flowing first gas. So really very, very pleased with the performance of the fields and the reserves progress that we're making in APLNG and it's a great credit to the team. If you look at what we delivered in terms of operational excellence, and we set out on an ambition a few years ago to now be producing well over 700 petajoules, and you can now see where those cost bases were down at $3.50 a gigajoule across all of that. And you can see there some of the infrastructure projects that occurred called ERIC and TOGGS. So it really is -- we've completed a lot of connection to infrastructure. It's very strong performance in the field, but also the facilities, and you can see they're very, very high facility reliability. So very pleased with how APLNG is delivering that operational excellence. What you can see there is just how the flexibility of APLNG is adapting to that market demand change. We reduced our operated production by 11 petajoules in response to the lower demand over recent months to COVID-19. We can ramp that up in quick recovery times. We have got good artificial intelligence. It's working on all of the various wells to optimize that and that's proving to be very, very flexible, and we will respond to the demand as we go forward. The upstream inventory management has obviously reduced the increase -- sorry, 15 petajoule increase in upstream inventory in the financial year. And obviously, we've got flexibility through the way we lift volumes through our nonoperated assets and also optimizing the way we think about pipeline, line pack and inventory. Obviously, our purchases, not our inventory, was less than the prior year in the last year. So we'll continue to use gas purchases based on commercial and operational opportunities. The APLNG sales mix, you can see there. You'll see that we sold 481 petajoules to LNG contract in the spot market. The average price was just under AUD 13 or just over USD 9 in MMBtu. We sold 187 petajoules to the domestic market at an average price of $4.61, as you can see, well below what we sell to the LNG market. And even if you excluded the contract that comes from APLNG historically to Origin, that number is really just only just above $5. So it certainly is much lower than what we export out on average. Our revenue has been down in FY '20 that Lawrie touched on, but that's really around the average realized LNG price coming down 4% because of the higher spot volume sales and also the average domestic price came down over the course of the year despite the stronger production. But I then take you to the guidance for next year -- or for this year that we've just commenced, but the one -- for FY '21, you will see there that we have now guided, firstly, to production to being lower. I mean the strong -- we really have got very strong field performance. You can see that higher production and lower costs that we delivered. It's enabled us to manage our scope, optimize our schedule and it's also meant that we have chosen to not participate in less economic nonoperated developments. So that is actually playing out well for us economically. It is really that guidance on volume is based on an expected lower demand in FY '21, and that's why we've given that and we have strong field capacity, should that demand and the outlook certainly improved for that demand that we'll be able to respond, and we'll be able to respond quickly. Our costs will reduce for APLNG in this year. That will come from improved field performance. We are reducing our drilling activity and E&A activity. Our workovers will be lower. There'll be less infrastructure spend, and that's all translating through as you can see to that CapEx and OpEx, excluding purchases being somewhere between $300 million to $500 million lower. I think it's fair to say that we think that, that CapEx will be close to as we currently see at $400 million lower today. So certainly bringing it down. And you can see that in the unit costs that we're going down and then level again. When it comes to the distribution breakeven, it really is a combination of the wider production outlook, a lower production, but it's the wider production, combined with our CapEx and OpEx that delivers those range of outcomes. We obviously have a strengthening currency this year, and that's why we've got that wider range of breakeven that really drives that. But very pleased to see that we're responding and continuing to respond through the good performance and operational excellence. In terms of commercial for LNG, both of our LNG customers declared their downward quantity tolerance or DQT for this calendar year. We did receive cash for the deferred cargoes, 5 of them in relation to one of those customers, we received that in January. And obviously, we've reported that we've done the first price review under the LNG contract with Sinopec with no change to that price, and we've also increased our equity share in a block called the Murrungama block to 100%, and that gas will 100% go to local manufacturers. In terms of Tri-Star proceedings, there's really not much new information. The position really remains unchanged. We filed the defense -- or amended defense, I should say, in the counterclaim. We did that in May. And the defense and counterclaim in the market's proceeding in April. So we've certainly been really progressing that. The next step really is for Tri-Star to file its response. So once those pleadings are finalized, there will be obviously all discovery and document disclosure. And potentially, we'll get court-ordered mediation and a hearing, but it's still progressing as we would have expected when we previously reported to you. In terms of Beetaloo, we announced its pausing. And what we will do is we're recommencing this quarter next back into Kyalla. We expect as a result of that pause due to COVID that the results will be available for Kyalla in '21. And that will then inform our options to either further evaluate this play or then commence activities in relation to the Velkerri shale liquids play. The results today, I have to say, are showing good reservoir continuity, and conductive natural fractures and continuous gas shows. So we're very pleased to see the way it's progressing. It's really around the delay and scheduling the program and making sensible decisions based on the results we see in terms of how we progress that, and you'll be well aware of the Falcon, a 7.5% increase that we executed recently. Just in terms of outlook, I've got 2 slides on outlook because I think there's -- just want to make sure we're clear on that. You can see there on Slide 44, we have provided outlook. Clearly, there's some more uncertainty that's associated with this year because of the potential ongoing impacts of COVID-19, and so we do make this guidance subject to any further material impact on demand and customer affordability. That's probably the key thing I would call out, but we are providing our guidance in the normal fashion subject to that COVID. You can see there in our Energy Markets, underlying EBITDA goes to $1.15 billion to $1.3 billion. I've talked through the Integrated Gas APLNG guidance, and you can see there the net benefit through the LNG oil hedging and trading at our corporate costs and CapEx that Lawrie touched on earlier. I'll just make a few comments regarding those guidance, particularly Energy Markets. The first is that it's driven by electricity gross profits reducing. That really is the flow-through of the electricity tariffs and gas tariffs through and the lower green certificate prices that are flowing through. We will adapt the portfolio and are likely to run Eraring lower over the next year, and therefore, be more exposed to that market if that -- if the market continues to present that opportunity, and that's one of the benefits in our portfolio, but it is really the overarching decline in those prices that against that fixed cost generation that really has that impact. In relation to the tariff and network costs, I say, they're $40 million absorbed. What really occurred there is that the DMO was actually issued a final DMO. And subsequent to the DMO decision, we received a higher network determination in some of the patches where we have a large amount of customers that was higher than was allowed under the DMO. We're certainly hopeful and working with the regulators and would expect to recover that in coming years because it really is a mismatch between the network determination and the DMO and then the final determination. In the gas gross profit, it's really down about $150 million. It really is retail and business tariffs coming down with lower gas prices. But we've got some of those transport sales contracts that rolled off, and the cost to serve benefit flow through. Really, I don't -- I think I've raised all the comments that I think I needed to raise on the Integrated Gas guidance. And in relation to corporate, you can see there, it's moved up modestly to the sort of $75 million, $85 million. And really what we've got sitting in there is an ERP replacement, which we should be implementing over the next few months. And we've got some gains and self-insurance costs not repeating from the last financial year. I should just mention that the depreciation is expected to be higher as we announced at the time of Octopus due to the sort of acceleration of that with the decommissioning of some of our retail IT systems, and we have a slightly higher depreciation associated with restoration provisions. So on that note, I'm very happy to conclude the presentation and now open up to questions. And as you know, we've got the team here, both virtually and also present with me today to answer those, and we look forward to them.

[Operator Instructions] Your first question comes from James Byrne from Citigroup.

Lawrie, first one for you. Just wondering where you see the leverage ratio for FY '21 capping out at your current outlook for oil price. If you do get towards that ceiling, how that is affecting your capacity to allocate capital? Now you've obviously done a good job already at providing disclosures on your cost base for '21. I'm more interested in understanding how it's affecting your propensity to pay dividends here because your payout ratio was below your own policy. And so I was surprised to see you sort of commit capital to the Beetaloo again, which starts up late this calendar year. So just trying to unpack that capital allocation, please?

Yes. Thanks, James. I think you called out all of the moving parts, right? So we're trying to do a bit of all of that, but it is true that we will move up towards the upper limit of that 2 to 3x range, given the outlook that we currently see for FY '21. So for that reason, we do want to continue to invest in our business. And so therefore, we were cautious around the level of dividend. But again, I think $0.25 per share consistent with the prior year is a good outcome, again, under the current conditions.

So I might just add another comment regarding that. Implicit in my comments regarding Beetaloo, James, is that if you looked at that would be that we certainly are looking at the sequencing, the schedule and the timing of spend around that. And that's certainly in our minds, and that's the reason for making some of the comments around Beetaloo as well because we'll be taking the right steps there, not to spend unnecessarily because that makes sense and the efficiency of how we do that. And that's what -- that was really what was implied in my messages on Beetaloo.

Got it. Okay. Next question just around gas market. So you're calling out lower some gas demand. I'm wondering whether you have any line of sight as to whether the lower demand is cyclical and related to effectively the end use of various industrial products or whether it is going to become a more structural issue. I mean you do think it's more structural, how that may or may not influence contract pricing?

I'll get Tony to talk a bit about demand and what we're seeing in the market at a deeper level.

Yes. We've seen a weakening in both gas and electricity demand as a function of COVID. So that remains an uncertainty going forward as the recovery. We don't see structurally -- we're not forecasting a big change in domestic gas. Still, the biggest swinger in I guess domestic gas demand will be around power generation and how thermal generation broadened to help renewables, but we're not structurally seeing anything in C&I outside of COVID.

Your next question comes from Tom Allen from UBS. Your next question comes from Max Vickerson from Morgans Financial.

I just wanted to ask a little bit about the dynamic with higher domestic consumption versus C&I consumption that you mentioned in the fourth quarter report and obviously impacted FY '20 outcomes. Just want to understand how much of that is baked into the FY '21 guidance. Obviously, they're still playing a part right now. How long do you see that continuing for?

So during COVID, we saw a lift in both mass market -- most gas and electricity domestic -- in the domestic market as a function of people working from home and businesses closing down or shutting down for a period of time. Probably the biggest impact we saw in terms of business was in the small to -- as you'd expect in the SME segment. And that yes, and that has come back in the most of the states, except for Victoria, not quite to existing levels, but has recovered somewhat. C&I, we saw less of a reduction equally. That's recovered, but not quite to existing levels. Victoria remaining the exception there. So we think, COVID obviously uncertain, but we're sort of expecting some demand recovery to occur once Victoria perhaps comes out of lockdown as time will tell whether that comes from existing levels, but it's not a huge amount of existing levels.

Yes. So it would be largely a continuation of what you saw, our quarterly would finish at the end of the year, except some reflection of the Victorian situation now.

Good to know. Okay. If I can just ask one more. Just around firming costs, probably more of a medium-term question with the change to a 5-minute settlement. I'm seeing referenced AEMOs data around OCGT. Just wondering with 5-minute settlement coming in, does that potentially change your view on the cost to use OCGT to firm? And then how do you think about competing technologies like aeroderivative turbines? Does that change the picture much?

Yes. It's Greg here, Max. Look, definitely, open-cycle aeroderivative technology is really quite fast. And I think it goes well with increasing renewables coming into the system. I could equally say that around batteries, there's all different technologies, which are probably all required. Batteries are the quickest, but obviously, there's only small duration in life, 2 to 3 hours, but pump hydro is also going to be important. But definitely, aero gas and recip engines, if you like, are definitely the type of technologies that we need in this market going forward when coal starts coming out of the system.

Yes. So I think AEMO's view that there is not going to be any gas required, gas peaking required. Probably there was an accord with our view -- it's -- I think I've got a particular scenario that's, I think, more aggressive in that regard. There's no doubt directionally, Max, that it will go to faster start firming capacity, which lends you towards some of those other technologies as costs reduce, but you will need a blend of all, we believe, over the various events through the course of the year because you need some duration as well as the sharp response based on different events through the year. So that's probably the better view from our perspective that you'll need that. But no doubt, directionally, it's going towards more battery, very fast-start and hydro because of their responsiveness, but we don't think that means that we know this far.

Your next question comes from Mark Samter from MST Marquee.

A couple of questions, if I can. The first one, it's probably really unfair to ask you on future year guidance as you've just given us FY '21 guidance. But I guess, if you look back at you and maybe your peers over the last couple of years, you give a view of guidance, and everyone seems shocked when you get to the next year's guidance and things are a bit softer. As we look beyond FY '21, is it fair to how you see still a continuation of the headwinds that's hitting this year? And is there anything that you think we should be thinking about that could be offsetting some of that?

I think that probably the key calls in relation to this, Mark, really center around that forward curve for electricity over time and the way it translates through to tariffs because embedded in this guidance would be an average forward price of around $70. So it will depend on how you think about that over time in terms of the forward curve. That's probably the most material one, and then probably to a lesser extent, I think a lot lesser extent as to where you see the forward curve for LGCs or certificates. So it really is a view of that forward electricity. And therefore, the mitigation around that really is how we run our portfolio and how much we outside of, let's call it, the peak summer period, how much we work really in terms of shortening our position and remain exposed to that. And that's an opportunity. And I think we're set up for that, given the amount of capacity we have to protect us against events, but that would be our key mitigation there. And then I think that's probably the key one that I would have. Obviously, gas price, you'll have a view on that. I mean that gas price that's sitting in mass market, it's a lot less of a pull-through into earnings, but it's still higher than where those sort of forward prices are today on gas, but I'd probably leave you with the view that electricity is probably the key one. And yes, so if you look at forward prices today, they're less than $60. Do you think they'll sustain? And if so, then we'd have another $10-or-so exposed to that subject to the shortening of that position, reducing our coal and gas costs, if they continue to remain low, will be an offset. That's probably the key thing that I think as you look to FY '22, Mark, is the strongest guide.

Just a point of clarity on the -- I realize when you're in arbitration, it's hard to make too much comment on the gas volumes rolling off, but can we take -- does the guidance assume a range of outcomes from that? Or is the guidance done on an x price review basis?

We obviously, when you put a range, you have a range, but we haven't called it out as a specific feature, Mark, and that's deliberate on the basis of the -- yes, we don't see that being material.

Yes. Okay. And then just one final question, if I can. Just the comment around the capital structure and dividend charge and you talked about the lower cash flow expectations in FY '21. Should we assume that, that comment predominantly rates, obviously, to the earnings guidance has been impacted in the -- obviously, the LNG received price? Or is there something a bit more, should we expect Energy Market's free cash flow generation to kind of perform broadly in line with the earnings outcome there? Or is there anything else we should think about in cash flow in Energy Markets?

Yes. Mark, it's just a factor of EBITDA moving down, nothing else. I talked about Future's collateral being an impact on FY '20, that could reverse depending on the point that Frank just made about wholesale electricity prices. And so yes, there are some upsides as well from a debt and capital structure position. But some of those other factors are uncertain, but all I was worried about in the point that I made was EBITDA, and I can say I'm still expecting that our debt will continue to move down in FY '21. So I think overall, we continue to head in the right direction.

I think there's something sort of varied in the cash conversion, Mark, like we really would expect that the EBITDA would be a good proxy for Energy Markets as operational cash conversion with the one exception, if collateral can move around just depending on how those zings. That's the only thing. Otherwise, we'd expect to see reasonably strong cash conversion.

Your next question comes from Ian Myles from Macquarie Group.

Can I just extend that collateral question? Should we interpret the fact that you're paying more in margins into the reserves means that you've gone along in the market with under sort of baseload contracts? And because the price has been falling, you're actually effectively having to pay that amount now. But I guess, how long are these sort of contracts going to go for? When do you sort of get your reset in your cost base to that lower level?

Yes. Ian, it's Greg here. Look, what -- how the book works, as we win some C&I load, as prices come down, we go into the futures market to hedge those loads. And so the market has kept on drifting down. So therefore, the initial margin and plus deviation margin, if you like, that's why accrued. So if the market flips back up, you'll have less margin in that account balance. So that's -- and typically, C&I contracts, we contract over 1 to 3 years. So those futures contracts are very short in duration. So you'll see those rolling off as you go through time.

Okay. Can we just sort of -- your competitor has been a bit more explicit about batteries. And it seems to be quite a trendy word within everyone trying to put batteries into the system. I think New South Wales has funded a few the other day, there's tenders going on in Victoria. Where about do you actually in the process of actually putting a battery in? Because based on your commentary, it seems that you don't see the market settings to be correct today to justify batteries. And maybe what do you need to see change to make that commitment?

Yes. Ian, really good question. Just the first question, Frank mentioned it in the presentation, we will certainly be ready to put batteries into our portfolio. So nearly all our sites right across the country, we have good battery options. As the market -- I mean, we see technology costs in batteries, we see that decreasing over time. So want to be very careful about how much batteries you put into our portfolio. There's one thing which is really important about batteries, they are very good at providing FCAS services. Right now, the FCAS services predominantly are supplied by the existing coal-fired power stations because they're on, and they can add order. They're providing the bulk of that. So as you see coal coming out, you probably want to see more batteries coming in. So we're going to be entrepreneurial here, if you like, or just getting ready to bring those batteries. If I was looking at a state where I think you could -- it's more likely, I think Victoria would probably be a better place for a battery. And certainly, in our portfolio at Mortlake is the place to put that there. So we're going to be ready as the market changes.

It's really a falling cost curve on the technology and getting your timing right.

Yes. One final question on that, and one final question, I guess just how much do you think batteries take away from revenue of your gas-fired plants? So if you think about that revenue pie of 100%, when batteries start to emerge, how much does the gas plant sort of lose?

Look, Ian, I really find you've got to have a combination of technologies here. I can really -- I can easily see Mortlake as a good example. You can see some very fast-start battery adding FCAS services. They run out charge in a couple of hours, and then you've got your open cycle gas turbines coming in.

I think also the other thing to take into account is, as coal comes out, coal provides some swing at the moment. You can see that with Eraring, swinging into the evening peak. As you get coal out, batteries we think we'll do them short-term work and then some of that more sort of seasonal swing will be taken up by gas. So the batteries will take some of the very fast start on revenue away, but -- so we think on the longer duration, which has perhaps been provided by swing in coal will be replaced by gas over time as well.

Your next question comes from Peter Wilson from Crédit Suisse.

First one on APLNG sales volume. So you've guided to production of 650 to 680. When should we expect sales volumes to fall, i.e., should we expect continued build in inventory and potentially reduction in third-party purchases?

Yes, Mark here, good question. Well, I mean we've guided 650 to 680. I think what's within that as well as the field -- the underlying field performance is really, really strong. Embedded in 650 to 680, there is a 40 to 70 petajoule sort of upswing that we could make if we see demand in line. So it's a bit hard to answer, therefore, what's the sales volume going to be in terms of the range within 650 to 680, but also that ability to swing up to more -- post 700 if we see demand come on.

Okay. You expect sales within that range of 650 to 680, would that be a way to interpret it?

Well, I mean, yes, obviously, you got to get from production to sales, you've got to look at a certain amount gets consumed in the LNG plant before you get out the door of the train. That's the key deduct that you've got to make for LNG sales, which is sort of 2% or 3%.

Yes. Okay. And then on Energy Markets guidance and bad debts, can you clarify whether or not you've included any increase in bad debt expense in FY '21?

We have not included any increase what we provided for this year, and that would be -- so it certainly got no material increase in bad debt provision embedded in that guidance. And therefore, that would be one of the key things that we'd make an assessment of through the year. We've obviously given you a range, but that's what we would need to make the assessment.

Okay. And the explanation for that because both AGL and E&A have, for example, guided to an increase. What would be the reason why your increase might be less than that?

No, we've widened the range for guidance. So that's the first thing. And we can't predict every single one of those outcomes, but we certainly widened the range as part of our thinking towards that. We -- everyone and all have made assessments as to what they've done at the -- at June '20 as well. And what I would say is that our historical bad debt or debt expense, including provision have been at 0.7%, we increased it to 1.1%. So historically, we've been, I think, lower. It's hard to predict every single one of those outcomes, Pete, but that's what we've, therefore, just made an assessment of what we've done at June. And therefore, if there is further, then we'll have to make that assessment, and we'll let you know if there's something that sits outside that fairway. But like at the moment, that's how we've thought about it.

Your next question comes from Baden Moore from Goldman Sachs.

Frank and Lawrie, I was just wondering if you could just revisit your commentary around the dividend again. When we think about your payout ratio, 30% to 50%, you've missed the bottom end on your payout. I appreciate you want to be conservative. I'm just wondering if you could make some comments, given you've said that Energy Markets is a good representation of cash flow, other utilities in New Zealand, Australia paying out closer to 100% of at least the utility. How do we think about your dividend guidance for '21? Do you think, given you've missed, is that -- are you signaling that essentially the $0.25 per share is at least repeatable again in the forward year? Is that why you've gone short? And then how do you think we should think about the progress of the dividend over time?

Yes. You've asked some tough questions here, Baden. Look, obviously, when you decide on a dividend at any point in time, you have to have in your mind the past, but also the future, the affordability of that dividend in the future. So I haven't asked the Board to give us a view about FY '21 dividend, but you can rest assured we had the future in mind when we made that decision this time. And it's our job to manage the resilience of the balance sheet and the company. And so in doing that, we've got to make some choices from time to time. And again, I'm confident again that we've made the right choice. And 6 months' time, we'll make another decision based on the world we face then. But I will say, we've talked about Energy Markets' EBITDA, but the other factor is oil price. And so if the oil price continues to strengthen, well then we can be less cautious, basically.

Your next question comes from Rob Koh from Morgan Stanley.

Just in relation to the Energy Markets guidance, you called out a few items. The -- within the gas margin headwind, there's a $70-million-or-so kind of nonrecurring capacity sales. So that was in the FY '20 result, but not in the FY '21 guidance. Could you give us some color on what that is? And I guess, is there a prospect that you could -- that, that business could come back at some point?

Yes. Rob, it's Greg. Look, the color is when we're commissioning the QSN, which is the pipeline that comes from Wallumbilla down to Moomba, we sold some transport to other counterparties going in both directions, one going north, one going south, if you like. We really don't see that as a recurring business. So that's why we specifically called that out. So that was the nature of those transactions. We did that many years ago, and they're rolling off -- and that rolled off. So that's why we called it out, Rob.

Yes. Okay. So does that imply then that if the whole headwind is $100 million, $150 million, $70 million of which is for the QSN secondary capacity sale, that the rest is the repricing on the 35 petajoules?

Yes, that's correct. Not the 35 pricing. It's actually tariff decline that flows through under the mass market more than that, Rob, it's actually not the repricing on price reviews.

Okay. Profile?

It's actually -- it's what's allowed in the -- yes, that's what actually flows through on the tariffs.

That's it. Okay, yes, that makes sense. And then for the electricity headwind. There's a network cost absorption of about $40 million, and you may wish to come back to me, but which distribution or transmission networks was that specifically?

I'm going to -- Jon. Jon, are you there? Jon, do you want to...

Yes. So it's primarily Endeavour and then the rest was split between Energex and a bit of [ Safen ].

Endeavour, it was the most material.

Mostly Endeavour. Okay. Right. And then I guess, in a sense, you're making a commercial decision to pass on DMO proportionately. Do you anticipate with that kind of setting that you'll be able to hold market share? Or how are you thinking about that, Mr. Briskin?

Yes. I mean we're still very conservative in those patches. And I think what you can see there is that we've gained customers where we've seen the value. So see, yes, there's been a latent particular patches, but then also the gas bookers continue to grow. I think in those areas, clearly Endeavour, key priority for us is to make sure we protect value and continue to defend our share there, we'll continue to do that. We'll continue to do it through thinking more broadly around how we apply our data analytics, but also, we've got 1 week perceived as a strong cost-to-serve advantage that continues to improve. And if you apply that cost-to-serve advantage over a lower churning market, I think that puts us in a very good position to defend that share.

Yes. Okay. Sounds good. All right. Just last question for me, if I can have one more. The reduction in CapEx for Origin year-on-year, it looks -- just looking at the column chart there, it looks like the main reason for that is the nonrecurrence of the major scheduled outages in generation. Was there anything in particular, canceled or deferred? I see Shoalhaven's fallen down the merit order perhaps.

No. Rob, what we've done in the generation standard business CapEx is we deferred the Eraring outage, which was going to take place about now into next financial year. Now just to -- we did a bit of work around sort of March, April, just -- we went into the machine, had a very good look and did some maintenance so we could defer that outage. So that's the main driver there.

Yes. So it really is probably -- in terms of really in that generation, BAU CapEx, it's come down quite a lot. It's probably come down 50%. It's been both deferral and nonrepeat, Rob. Where do I get some -- where do we get some of the offsets in that guidance number is we've got the 5-minute settlement system this year is probably one of the key ones. That's probably to think about that. That's probably the key. And Lawrie might have some further comments.

Yes. I'd just add that within the past, we've provided guidance that says that you should expect capital to be around about $400 million a year plus E&A expenditure. And I would say this year pretty much meets that longer-term guidance that we provided you. Little bit less generation sustaining and a bit more around the execution of Kraken in the retail business.

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

Following up a comment earlier, your Energy Markets contract gas chart on Slide 29 points to sharp declines in contracted gas demand. It looks like your portfolio demand is well covered over the next few years. Origin has previously spoken about being a strong advocate for imported LNG. Is there any change to your view with respect to Origin wanting to supplement its portfolio with import of LNG?

Yes. Tom, it's Greg here. Look, there's a few -- we're definitely needing more gas in the southern part, the southern states as Gippsland's rolling off, but we're in negotiations with a number of counterparties. There's no doubt that we're talking to import terminals as well, that's part of the solution. There's other solutions as well, such as getting gas down from Queensland through the pipes or just development of gas fills down in the south, but there's no doubt that import terminals are in the equation.

Okay. And now a question for Mark. Can you please provide more color on the time line for a drilling result in Beetaloo? What flow rate or condensate-to-gas ratio would confirm success? And how does the broader economic backdrop affecting the upstream sector influence your development plan?

Yes. Thanks, Tom. I'm just looking at which part I'm going to answer and which part I'm not. So what -- as what Frank said was we're obviously restarting operations in the Beetaloo. We said Q3, Q4 of the calendar year. Of course, we're in Q3 now. So I'm sure you can figure that out. We see an opportunity now to look at the Kyalla results just because we've started with a COVID delay. We've got an opportunity now to look at the Kyalla results before we make the decision to move across to the Velkerri. The rationale there is, like Frank and Lawrie were saying before, we're very thoughtful about how we spend Origin capital. We prefer not to have to build the 70-kilometer road out to Velkerri if we don't need to this year. We had a success on Kyalla, we'd likely decide to drill another well at Kyalla and confirm it rather than go across the Velkerri. And so we're just quite thoughtful. In terms of timing, we'd expect in Q4 to be talking about what the results are. Of course, our joint venture partner, Falcon will do that as well and obviously put out their own releases. The purpose of stage 2 of the farm-in agreement is to -- is the flow of liquids. That's what we're trying to do, and we just won't be setting -- we're not going to be setting public expectations about what is the success and what is not because success will be determined by exactly the setting, how we get the frack away and this sort of thing. And so we have to translate the frack placement versus the results. But obviously, as we put out, and we're very transparent about how it's going. As we put those results out, we'll explain what we think of them as we get.

Your next question is from Bruce Low from Merrill Lynch.

Yes, just got 2 or 3 questions actually, if I may. Firstly, there was some press during the week, and I think it might have even been an Origin spokesperson, suggesting that Shoalhaven, you did mention in your presentation that the costs have kind of blown out there, but there was talk this week that it actually had been shelved completely. Is that -- is Shoalhaven still on the agenda? Or is it really looking pretty unlikely at this stage?

No. There was no new information this week. I mean it was consistent with what I had said at previous results. I know it was picked up by a journalist and so forth. It was just really around the economics, the geotech and tunneling is higher than we thought pre -- and that's -- I think I said that to the investors some time ago. And so nothing's ever shelved completely. We will retest the economics of it over time, but at the moment, we can't see that being the most economic thing to do based on costs. Greg?

The new information came out because we did a feasibility study based on ARENA. But after doing that feasibility study, that's where that news came from, but Frank's absolutely right in what he said.

It's just consistent with what we've said previously, but we'll have it available should we see the circumstances and the economics improve.

Yes. Okay, no problem. And also, maybe this is a question for Greg as well. The ISP has been pretty supportive of the New South Wales careers and obviously, the New South Wales government seems to be moving ahead and keen to build the first renewable energy zone. Does that -- how do you look at that? Does that create opportunities for Origin? Or are you still kind of very firmly of the view that Origin is not really the natural owner of renewables?

It creates opportunities in the sense that we think renewables, more renewables coming to the system is a given and opening up those zones enables more renewables, but that then focuses our mind on just bringing the reliability into the system. So we'll look at both, but reliability is going to be a key piece of the puzzle when more renewables come into the system.

And then I think over time, Bruce, as that more renewables come in, we will have a decision around at the right time, whether or not we think contracting or investing in them is the best thing for Origin at that time. We remain open to both of those. To date, it's been I think, an easy trade-off as you're coming at the end of the old rent to actually contract those and do that. But we remain open to what's the best thing overall in terms of allocating capital.

Yes. Sure, no problem. And then just very last question, if I may. And this is probably for Greg. On Eraring, on Slide 27, I think it was, you have that chart showing the flexibility and the targets are changing the way that you've operated Eraring through the day. Given the market's kind of evolving pretty quickly, I think most people in the market have been surprised at the change in some of the dynamics in the market, in particular price over the last even to 6, 6 to 9 months. Has your -- how are you sort of viewing Eraring in terms of its flexibility and ability to ramp up quickly the 880 to 288 (sic) [ 2,880 ] that you're kind of talking in that chart. Does that mean you can kind of run that consistently at around 880 megawatts without having to shut units in or with minimal impact on cost and maintenance?

Yes. A couple of things. We weren't so surprised about the middle of the day being carved out by solar. So we've been working on Eraring for some time to make sure it's flexible. Fortunately, when we bought that off the some years ago, they were newer machines. They did a lot of work. So they are very flexible machines, and we have operated in the low 200s right up to 720. So it really does flex up in the megawatts per unit, but the other key ingredient to this is that you need also a flexible coal supply. So just railing in coal when we need it or not is really important. So we don't have a big take-or-pay issue. So a very flexible power station, and it's working really well, really well.

And I think probably over the -- if you're talking about a medium term, then sort of how we think we're going to run those and trading off maintenance and so forth, there's probably a few different options that we're pursuing now. But certainly, in the shorter term, what the way we're running today and have run to date feels like we can sustain that for a period of time. I think it would then get to us if it starts to really become when you're cycling units very hard, how do we think about those 4 units and how do we actually operate. So there's a few different choices around the operating regimes there going forward, Bruce.

Okay, cheers. That was great. All right. I'm very keen to talk more about hydrogen, Frank, but we can do that off-line.

There are no further questions at this stage. That does conclude our conference for today. Thank you for participating. You may now disconnect.