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 1 on your telephone keypad. I would now like to hand the conference over to Mr Frank Calabria, CEO. Please go ahead.

Thank you very much and good morning everyone. Thank you for joining the Origin Energy 2020 full year results call. This is Frank Calabria here and I'm joined by my leadership team today which includes Laurie Tremaine, Greg Jarvis, Mark Schubert, Tony Lucas, John Briskin and Kate Jordan. So Laurie 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 a previous presentation so I'll take you through the performance highlights for the year and I'm just trying to get slides to move on if I'm controlling them for you as well. Laurie will take you through the financial overview and then I'll provide an operational review and outlook. Just starting with performance highlights, I'll take you to slide 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 our record cash distribution of just under $1.3 billion there so that's up $300 million from the prior year. Now 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 the board is determined to pay an unfranked final dividend of $0.10 million. per share which does equate to just underneath the 30% of our free cash flow and Laurie 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 five. I did just mention the record production and cash distribution from APL&G. but also there's a 5% increase in the APL and G2P 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 the 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. Very pleased to see that we, for our people, that we've been able to lift our engagement to the 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 six, 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 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 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 two 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 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 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 off 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 decarbonisation. 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'll just point out on a couple of these that many of these have not yet received the full impact because in the case of APL&G there's a lag between those prices flowing through to the sales contract so that's very much a feature of the FY21 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. 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 re-contracting in the CNI 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 talked 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 CNI and FME customer market and it's offset by modest increases in the residential demand. 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've sort of almost got a two 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 Beedloo Exploration Program when planning to recommence this quarter next to get back going on that. 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 our sites, our LPG terminals and our gap 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 these terms has firstly focused on the health and safety of our people, that's where it starts and then you can see there that it's very much focused about supporting our customers. We've paused the default listings, disconnections and late payment fees. We continue the hardship and payment extensions and as you know 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 wellbeing 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 in the operational review. The two probably big examples of that are really the flexing down of the way we can run a RARing and also run a 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 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 further cost out that will be part of the octopus proposition of both customer experience and cost. Also what's happened is that over the last month or so we've extended our debt maturity profile and Laurie will take that through to you so we've got significant headroom and liquidity. We continue. We've made response. operationally we're resilient and we continue to respond to the circumstances and 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 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 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 policy makers, 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 networks supported, but it is going to be support that I believe the cost of which must be borne right across the supply chain I think it'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 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. 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. 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 two 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 OwnConnect, a US-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 fleet management solutions underway including a trial that was recently announced in the ACT. You can see we've reduced our break even in integrated gas down to being US$29 a barrel. That's a distribution break even and includes I think somewhere in the vicinity of US$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 Beedaloo 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 Laurie and he'll take you through the financial performance.

Thanks Frank and good morning everyone. I'm going to start on slide 14 and 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 high 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 owner's contract provision charges announced in July. Underlying ROCHI 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 AP LNG and have recognised 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 Link price plus a fixed tolling fee. We assume onward sale at JKM prices. The owner's 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 US 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 work over cost 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, the stable year-on-year. 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 non-repeat of last year's remediation provision increase. Adoption of the new leasing standard explains most of the increase in DNA 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 served. 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 re-regulation, and to a lesser extent, unplanned outages at Araring 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 to serve down $40 million year on year and we 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 off-takers 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. Realised 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. Finally our 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 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 unfavourable movement in electricity futures exchange collateral which will unwind as positions are settled. and also a high 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 Octopolis 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 two to three times range and I'm pleased to say we're currently at the low end of the range at 2.1 times. Staying within the range will be tougher this coming year as EBITDA reduces with lower commodities. 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 realised 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.

The conference is now being recorded.

Slide 22 shows that we've remained active in managing our debt book, increasing our return to maturity to 3.9 years. Since 2018 the annual interest paid is reduced by more than $160 million and the average interest rate is reduced by 170 basis points to 4.8%. Around $900 million of undrawn liquidity has been cancelled 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've built resilience of the company progressively over recent years as Frank said earlier. Most importantly we've 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 US$29 per barrel. We will further reduce APLNG CapEx by US$300 to $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 reductions in cost while also delivering a radical improvement in customer experience. Our preference is to build our resilience through these structural levers. However in the medium term we'll maintain an appropriate level of commodity hedging. For 2021 we've hedged 6.4 million barrels, about 22 million barrel exposure. At July 3.7 million hedged barrels have been realised at a price of approximately US$55 per barrel. At current forward prices we estimate an oil hedging gain of around $100 million in the current financial year. With that I'll hand back to Frank for our operational performance review.

Thanks very much Laurie. I'll just take you through some slides on the 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 in response to the lower demand and as wholesale sales contracts have expired, shorter term contracts, we've then redirected that gas into gas fire generation and you can see that's how we've adapted. In the case of gas you can see there that we've increased the amount of gas that we've purchased 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 two financial years. You can see that in terms of the supply portfolio. Really expanding on that a little further, here is an example really over the month of June as to just how we've been changing the way we operate Harare 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 or prices are and you can see that profile and how we really are operating a raring 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. The plant has performed very well over the last year and you can see that that's a feature of 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 non-firm 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 non-firm just a renewables PPA without that firming cost to be marketable. 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 of the generation and storage at the moment but what we're doing is making sure we're ready for that should that situation change. 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 have reduced and it's 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 that's one we purchased rolling off that attribute a benefit and that's one of the key drivers of the guidance of 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 continue to actively be in the market for gas supply. There are, as you should all be aware, price views 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 FY21 and a 35 petajoules repricing in FY22 across those three 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've 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 costs off our supply. I say relatively fixed costs because we're always in the market buying coal and gas but nevertheless that's how you should think about that 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 APL and GE before we formed that joint venture. Fuel costs we remain, we have 4 million tonnes per annum. We're currently using 5 to 6 million tonnes so we're certainly not 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 continued 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 volume drivers that we saw this year repeating next year when we think about guidance. The one thing we are leveraged 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 to 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. Our churn is continuing to reduce. You can see the moves and 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 looked at the retail strategy, I said before NPSR, the clearly big 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 any 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 onto 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 market's opened back up but it'll be a little dependent on that but certainly performing as we would have expected and remain very focused and on track to deliver the platform. They are progressing well with the eon migration of customers onto their platform into the UK. Clearly a feature that we've described and 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 have been migrated. That's driving cost efficiencies in our business but also performance improvements. The data 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. 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 optimise 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 Trail 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 localised level so we're starting to see the use case and benefit of this work playing out and will continue to feature going forward. I will now take you to Integrated Gas and the first thing there is I'm very, very pleased to see on slide 36 just how we've progressed our reserves. Over the last three 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 de-risked. We have now 70% of that in 1p or produced and we've seen very strong operating field performance that has continued to strengthen over the last 12 months. It's across Cambabula, Condebrae, 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 Bow and Deep's pilots are flowing first gas. So really very, very pleased with the performance of the fields and the reserves progress that we're making and APL&G 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 base is. We're 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 TOG. 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 that's working on all of the various wells to optimise 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 in upstream inventory in the financial year and obviously we've got flexibility through the way we lift volumes through our non-operated assets and also optimising the way we think about pipeline line pack and inventory. Obviously our purchases, not our inventory was less than the prior year and the last year so we'll continue to use gas purchases based on commercial and operational opportunities. The LNG 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 $13 Aussie or just over $9 US in MMBTU. We sold 187 petajoules to the domestic market, an average price. At $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 at on average. Our revenue has been down significantly. in FY20 that Laurie touched on but that's really around the average realised 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. I'll then take you to the guidance for next year or for this year that we've just commenced but the one for FY21. You will see there that we have now guided firstly to production to being lower. I mean we really have got very strong field performance. You can see that higher production and lower cost that we've delivered. It's enabled us to manage our scope, optimise our schedule and it's also meant that we have chosen to not participate in less economic non-operated 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 FY21 and that's why we've given that. and we have strong field capacity should that demand and the outlook certainly improve for that demand that we'll be able to respond and we'll be able to respond quickly. Our costs will reduce for APL&G in this year. They'll come from improved field performance. We are reducing our drilling activity and ANA activity. Our work overs 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 another level again. When it comes to the distribution break even, It really is a combination of the wider production outlook, a lower production but it's the wider production combined with that 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 break even that really drives that. We're 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 they're down with quantity tolerance or DQT for this calendar year. We did receive cash for the deferred cargo, five 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. We've also increased our equity share in a block called the Murrungama block up to 100% and that gas will 100% go to local manufacturers. In terms of TriStar proceedings there's really not much new information. The position really remains unchanged. We filed the defence, our amended defence I should say and the counterclaim. We did that in May and the defence and counterclaim in the markets proceeding in April so we've certainly been busy progressing that. The next step really is for TriStar to file its response so once those pleadings are finalised There will be obviously all of the 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 Beedaloo, we announced it's pausing and what we will do is we're recommencing this quarter next back into Kyella. We expect as a result of that pause due to COVID that the results will be available for Kyella in 21 and that will then inform our options. to either further evaluate this play or then commence activities in relation to the Valkyrie Shire 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 aware of the Falcon, a 7.5% increase that we executed recently. Just in terms of outlook, I've got two 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 caveat. You can see there in our energy markets underlying EBITDA goes to $1.15 to $1.3 billion. I've talked through the integrated gas APL&G guidance. and you can see there the net benefit through the LNG oil hedging and trading and our corporate costs and capex that Laurie 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 ARARing lower over the next year and therefore be more exposed to that market 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 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 in the DMO and then the final determination. 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 have rolled off and the cost to serve benefit flows through. 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 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. 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.

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 are on a speakerphone please pick up the handset to ask your question. Your first question comes from James Byrne from Citigroup. Please go ahead.

Hi, thanks. Good morning. Murray, first one for you. Just wondering where you see the leverage ratio for FY21 capping out at your current outlook for oil price. And 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 Betaloo 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 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 two to three times range given the outlook that we currently see for FY21. 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, if that makes sense, and the efficiency of how we do that. 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 gas demand. I'm wondering whether you have any line of thought 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. And if 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.

Yeah, we've seen a weakening in both gas and electricity demand as a function of COVID. So that remains an uncertainty going forward as to 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 term generation is brought into to help renewables, but we're not structurally seeing anything in CNI outside of COVID.

Okay, great. That's all from me. Thank you.

Thanks, James.

Thank you. Your next question comes from Tom Allen from UBS. Please go ahead.

Hi, Tom.

Tom, your line is live. Please go ahead, Tom. Your next question comes from Max Vickerson from Morgan Financial. Please go ahead.

Hi, guys. 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 FY20 outcomes. Just want to understand how much of that is baked into the FY21 guidance and obviously that's 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 see 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 most of the states except for Victoria, not quite to existing levels but has recovered somewhat. CNI we saw less of a reduction equally that's recovered but not quite to existing levels. Victoria remained in the exception there. We think COVID obviously uncertain but we're sort of expecting some demand recovery to occur once Victoria perhaps comes out of lockdown. Time will tell whether that comes from existing levels but it's not a huge amount off existing levels.

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

Good stuff. Okay, if I can just ask one more just around firming costs, probably more of a medium term question with the change to five minute settlement. I see in reference AMO's data around OCGTs, just wondering With five-minute settlement coming in, does that potentially change your view on the cost to use OCGC to firm? And then how do you think about competing technologies like aero-derivative turbines? Does that change the picture much?

Yeah, it's great to hear, Max. Look, definitely open cycle aero-derivative 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, two to three hours. Pump hydro is also going to be important but definitely aero, gas and resip 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.

Yeah, so I think AMO's view that there's not going to be any gas required, gas peaking required, probably doesn't accord with our view. They've got a particular scenario that's 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 just what.

Okay, thanks. That's it for me. Thank you.

Thanks, thanks.

Thank you. Your next question comes from Mark Santa from MST Marquee. Please go ahead.

Yeah, morning, guys. A couple of questions, if I can. The first one is probably really unfair to ask you on future year guidance after you've just given us FY21 guidance, but I guess if you look back at UN, maybe your peers over the last couple of years, you give a year 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 FY21, is it fair to say you see still a continuation of the headwinds that are hitting this year and is there anything that you think we should be thinking about that could be offsetting some of that?

I think probably the key calls in relation to this, Mark, really centre 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. 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. Then I think that's probably the key one that I would have. you'll have a view on that in that gas price that's sitting in mass market tariffs. 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 looked 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 is you'd look to FY22, Mark, as the strongest guy.

Just a point of clarity on the, I realise when you're in arbitration it's hard to make too much comment on the gas volumes rolling off, but can we say, does the guidance assume a range of outcomes from that as the guidance done on a 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. You don't see that big material.

Just one final question if I can. There's the comment around the capital structure and dividend charts and you talk about the lower cash flow expectations in FY21 Should we assume that that comment predominantly relates obviously to the earnings guidance that's been impacted and obviously the LNG received price, or is there something a bit more, should we expect energy markets free cash flow generation to perform broadly in line with the earnings outcome there, or is there anything else we should think about in cash flow and energy markets?

Mark, it's just a factor of EBITDA moving down, nothing else. You know, I've I talked about futures collateral being an impact on FY20. You know, that could reverse, depending on the point that Frank has made about wholesale electricity prices. And so, you know, 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, you know, I still am expecting that our debt will continue to move down in FY21. So I think overall we continue to head in the right direction.

Perfect. Thanks.

There's nothing that's buried in the cash conversion, Mark. You know, 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 things. That's the only thing. Otherwise we'd expect to see... reasonably strong cash conversion.

Perfect. Brilliant. Thanks very much.

Thanks, Mark.

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

Hi, guys. Just to extend that collateral question, should we interpret the fact that you're paying more in margins into the reserves means that you've gone long in the market under sort of baseload contracts and because the price has been falling, you're actually effectively able 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 and your cost base to that lower level?

Yeah, Ian, it's Greg here. Look, 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 it accrues. So if the market flips back up you'll have less margin in that account balance. Typically CNI contracts, we contract over one to three years so those futures contracts are very short in duration so you'll see those rolling off as you go through time.

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. Whereabouts are 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 then what do you need to see change to make that commitment?

Yeah, a 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 we 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'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, 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, Mortlake is the place to put that there. So, you know, 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.

Yeah. And one final question on that, and one final question, I guess. Just how much do you think batteries take away from revenue for 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, I really find you've got to have a combination of technologies here. I can easily see Mortlake as a good example. You can see some very fast battery adding FCAS services. They run out of 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 cold comes out, cold provides some swing at the moment. You can see that with the raw ring swinging into the evening peak. As you get cold out, batteries we think will do some short term work and then some of that more sort of seasonal swing will be taken up by gas. So batteries will take some of the very fast start revenue away but we think on the longer duration which is perhaps being provided by swinging, cold will be replaced by gas over time as well.

Thanks guys.

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

Thank you. Good morning. First one, on APLNG sales volume, so you've got it to production of 650 to 680. Where should we expect sales volumes to fall, i.e. should we expect continued build in inventory and potentially reduction in third-party purchases?

Yeah, Mark, good question. We've got it 650 to 680. I think what's within that as well is the underlying field performance is really, really strong. Embedded in 650 to 680, there's 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, but you expect sales within that range of 650 to 680. Would that be a way to interpret it?

Well, yeah, obviously you've got to get from production to sales. You've got to look at 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%.

Okay. Then on energy markets guidance and bad debts, can you clarify whether or not you've included any increase in bad debt expense in FY21?

We have not included any increase, what we provided for this year and that would be – so it's certainly got no material increase in bad daffodils 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 Agile and EA have for example guided to an increase. What would be the reason why your increase might be less than theirs?

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 widen the range as part of our thinking towards that. Everyone has made assessments as to what they've done at June 20 as well and what I would say is that our historical bad and doubtful deaths expense including provision had 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 in 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 at the moment that's how we've thought about it.

Okay, got it. That's all from me. Thank you.

Thank you. Your next question comes from Baden Moore from Goldman Sachs. Please go ahead.

Morning, Frank and Laurie. 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 just wondered 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, are you signalling 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?

Yeah, you've asked some tough questions there, 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, you know, the affordability of that dividend in the future. So I haven't asked the board to give us a view about FY21 dividends but you can rest assured we had the future in mind when we made that decision this time. 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. Again, I'm confident again that we've made the right choice. and in six 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.

That's all from me, thanks.

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

Thank you. Good morning. Just in relation to the energy markets guidance, you called out a few items. Within the gas margin headwind, there's a 70 mil or so kind of non-recurring capacity sales. So that was in the FY20 result but not in the FY21 guidance. Could you give us some colour on what that is and I guess is there a prospect that that business could come back at some point?

Yeah Rob, it's Greg. Look, the colour is, when we were commissioning the QSN which is the pipeline that comes from Wollongbilla down to Murmba, 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 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 they've rolled off. So that's why we called it out, Rob.

Yeah, okay. Thank you, Greg. So does that imply then that if the whole headwind is 100, 150, 70 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 repricing on the whole book. It's actually tariff decline that flows through under the mass market more than that, Rob. It's actually not the repricing on... That's what actually flows through on the terrace.

That makes sense. Then for the electricity headwind, there's a network cost absorption of about 40 mil and you may wish to come back to me, but which distribution or transmission networks was that specifically?

I'm going to... John, are you there? Yeah, hi Rob. So it's primarily Endeavor and then the rest was split between Energex and a bit of SAPN.

Endeavor, it was the most material.

Mostly Endeavor, okay. Right, thank you. And then I guess in a sense you're making a commercial decision to... 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?

We're still very competitive in those patches and I think what you can see there is that We've gained customers where we've seen the value, so CES has been electing particular patches but then also the gas book has continued to grow. I think in those areas clearly Endeavor, a key priority for us is to make sure we protect value and continue to defend our share there and we'll continue to do that. thinking more broadly around how we apply our data analytics, but also we've got what we perceive 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 extend that share.

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

No Rob, what we've done in the Generation Stay in 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 March, April just to, 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?

Yeah, 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 non-repeat Rob. Where do we get some of the offsets in that guidance number is we've got the five minute settlement system this year is probably one of the key ones. That's probably the thing about that. That's probably the key and Laurie might have some further comments.

I just add that in 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. A little bit less generation sustaining and a bit more around the execution of crack in the retail business.

Thank you very much. Appreciate it. Good luck. Cheers.

Thanks, Rob. Thank you. Once again, if you wish to ask a question, please press star 1 and wait for your name to be announced. Your next question comes from Tom Allen from UBS. Please go ahead.

Good morning, Frank, Laurie and the broader team. 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 imported LNG?

Hello 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 is growing up 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 pipes or just development of gas fields down in the south but there's no doubt that import terminals are in the equation.

Okay, thanks Greg. Now a question for Mark. Can you please provide more colour on the timeline 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 working out which part I'm going to answer and which part I'm not. So what Frank said was, you know, we're obviously restarting operations in the BLE. We said Q3, Q4 of the calendar year. Of course, we're in Q3 now. So I'm sure you can figure that out. You know, we see an opportunity now to look at the Kyala results. Just because we've started with the COVID delay, we've got an opportunity now to look at the Kyala results before we make the decision to move across to the Valkyrie. The rationale there is, like Frank and Laurie were saying before, we're very thoughtful about how we spend origin capital. We'd prefer not to have to build the 70-kilometre road out to Velkeri if we don't need to this year. If we had a success on Kyella, we'd likely decide to drill another well at Kyella and confirm it rather than go across to Velkeri. 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 two of the farming agreement is to flow 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 a success and what is not because Success will be determined by exactly the settings, 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'll be very transparent about how it's going, as we put those results out, we'll explain what we think of them as we go.

Okay, thanks, Mark. That's all from me. Okay, thanks, Tom.

Thank you. Your next question is from Bruce Lowe from Merrill Lynch. Please go ahead.

Hi, good morning everybody. I've got two or three questions actually, if I may. Firstly, there's 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 had actually been shelved completely. Is Shell Haven still on the agenda or is it really looking pretty unlikely at this stage?

There was no new information this week. It was consistent with what I'd 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 tunnelling is higher than we thought and I think I said that to the investors some time ago and so nothing has 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. Great.

The new information came out because we did 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 said previously, but we'll have it available should we see the circumstances and the economics improve.

Yeah, okay, no problems. 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 is seems to be moving ahead and keen to build the first renewable energy zone. 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 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.

Then I think over time Bruce is that more renewables coming in we will have a decision 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. Today it's been, I think, an easy trade-off as you were coming at the end of the LREC 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 a raring, on slide 27, I think it was, you have that chart showing the flexibility and the targets of change in the way that you've operated a raring 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 of the market, in particular price, over the last even just six to nine months. How are you sort of viewing a raring in terms of its flexibility and ability to ramp up quickly? You know, the 880 to 288, that you're kind of talking in that chart, does that mean you can kind of run it consistently at around 880 megawatts without having to shut units in or with minimal impact on cost and maintenance?

Yeah, 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 a raring for some time to make sure it's flexible. Fortunately, when we bought that off 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.

I think probably 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 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 four 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 pretty keen to talk more about hydrogen, Frank, but we can do that offline. Thanks very much, guys. Cheers.

Very happy. Okay, thank you.

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