Origin Energy Ltd Ord

Good morning everyone. It's Frank Calabria here and welcome to our Origin Energy 2020 half year results. I'm joined by all of my leadership team and I'm sure there'll be questions for a number of them. Laurie Tremaine, our CFO, Mark Schubert, our Executive General Manager of Integrated Gas, Greg Jarvis, our EGM of Energy Supply and Operations, John Briskin, who heads retail, and also Tony Lucas, who heads up our future energy and business development, amongst other colleagues. So thank you for joining us. It is a familiar format. We will be... I'll take you through some of the performance highlights, then Laurie will come back with a financial review. I'll then discuss some of the operational review highlights and outlook, and then we'll turn to questions. So firstly now, just turning to the... performance highlights. If you move to slide four, you should see on the screen there, you'll see that our underlying profit is down 11% for this half compared to the first half of the prior year. We've had good performance in APLNG driving growth, but that's been more than offset by the decline in energy markets and the three key drivers are outlined there being the regulated retail price, for electricity. We had some generation outages that were unplanned in the half, and we'll talk further about those and the recovery of them in the second half, and also some lower electricity volumes. That translates to an underlying ROCE of 8.3%. Very good to see a strong cash flow that's grown by 22% to $680 million, really on the back of the higher distribution from APLNG. And then you can see that we've continued our trend of reducing debt down to $5.1 billion. Laurie will talk through the lease accounting impact on that debt, but the key message is on a like-for-like basis, down $340 million. On the back of that strong cash flow, I'm pleased to say that the board is determined to declare a $0.15 a share fully franked dividend, and that compares to $0.10 per share for the first half last year, and it represents 39% of the free cash flow that we took investors through over the last 12 months as part of our distribution policy. Just now turning to the strong operational performance in the first half of 2020, and I'd start by giving you a message that's been a very good half and a continuing trend I hope you'll see over the last 18 months of good performance in integrated gas. And the simple message there is that a combination of good performance of the wells, the subsurface, in addition to very good performance on the surface facilities and bringing that all together has resulted in record production and it's also therefore allowed us to re-scope the program, it all performing better for less and that's allowing us to reduce costs to deliver the same production. You'll see there that in the last six months we've been able to increase that production at 358 petajoules and you can see that's really comparing to circa 340 petajoules over the last four periods. So a great performance there and that's translating into being a lower cost operator and making us very resilient under all market conditions. When it comes to energy markets, I did mention that we did have two unplanned generation outages and that's the first time we've had those of that nature in the last six months. I'm very pleased to see how those assets return to service. In particular, to bring Mortlake back from the event it did within six months and have it available through January has proven to be very important. And I'm very pleased with how the team performed in that respect. We continue to take a disciplined approach to managing customer lifetime value, but we'll talk a little bit further about that in terms of the competitive markets for retail. The lower wholesale gas prices are benefiting the wholesale business and our cost of gas into that market We continue to reduce cost to serve, and the retail team have reduced that by a further $28 million and a half. And importantly, at the same time, we really are advancing the transformation of our customer experience. So overall, a strong operational performance, notwithstanding we had a couple of those outages in generation. It really is important that we deliver for you, our shareholders, but at the same time, we remain committed to delivering for all stakeholders. And here are just some of the measures that we do to track our progress. What you can see is that we really look across customers, the community environment and our people. Touching on the key highlights, that is the highest ever strategic net promoter score that we've had at Origin, representing a continuing trend over the last several years. So very good to see that progress. It's worth noting that our interactions that net promoter score you'll see has dipped. Through the course of the period, we had a significant offshoring as part of that reduction in cost to serve and managing through that change. And we're very determined to see that continue back on its upward trend over the coming periods. In terms of care and battery impact, there's many ways you could assess that. The two that we've shown here are the continuation of renewables coming online, but the key event this year will be the construction of Stockyard Hill. And secondly, that we continue to support regional suppliers to our business. And you can see we increased our percentage of total spend. When we reported last to you in respect of safety of our people, we were disappointed by the performance of June. There's been a very concerted effort across the business. And you can see there on a rolling 12-month measure that we've made some improvements. We clearly have more work to do to continue to reduce that. And you can see there we measure the women in senior roles. It's a measure that takes quite a bit of coordination and effort to continue to move. I'm pleased to see the positive direction over the last six months as part of increasing our diversity of our workforce at senior levels. Just extending that further then to our purpose of getting energy right for our customers, communities and planet, it's probably worth highlighting just how much does happen across those aspects of our business in the last six months. The most significant event has been the bushfires and you can see that Origin, I'm very proud of the role that Origin's played in respect to those bushfires. Firstly, the $4 million bushfire relief package that really has gone to assisting customers right across the regions in which we operate and serve. And then if you looked underneath the communities column, you'll see that in addition to that, there's been over $870,000 donated to drought and bushfire relief and recovery by the organisation and our people. And we continue to respond and clearly there's still customers facing hardship challenges and we're continuing to provide that support. Turning back to customers, clearly I raised the customer experience. In addition to that, we've obviously had the regulated price for Victoria introduced on the 1st of January as its next review point. and we extended beyond the regulatory requirements to what we believe was an implementation of the right thing for our customer base. The other thing is that APLNG has signed further domestic contracts with manufacturers including Orica and Aurora and it's good to see further gas agreements being signed and it's also good to see for those manufacturers that those prices are coming down. I talked about our regional spend for customers. Just a note that at Origins Foundation, you know, really worth saying in terms of the community has now donated over $25 million to causes in education and disadvantaged people over that last 10 years, a tremendous achievement. When it comes to the planet, we did release a one and a half degree scenario for our wholesale electricity portfolio that showed that it was resilient under that scenario. We continue to support the national goal of net zero emissions in the electricity sector by 2050 and earlier. And as I said earlier, we're actually on track to have 25% of our generation capacity by renewables by the end of this calendar year. I'm sure you'll all then, if we turn to the next page, been noticing that the energy markets continue to be very dynamic and rapidly change, and it is evidenced by really these trends in gas, electricity prices and also intraday volatility. The electricity forward prices, you can see over the last several years have moved up and down and over recent times have moved down. As the influx of renewables, some despite bushfires and other activities, a milder summer for weather in some regions, but nevertheless it's demonstrating that introduction of new supply into the market. At the same time, what it's doing, and because a lot of that supply is renewables, you can see at that middle chart that that shape is starting to continue to accentuate as it hollowed out in the middle of the day and it creates those peaks, meaning that the way we efficiently supply our customers continues to evolve and that's where you want that flexibility of portfolio. Lastly, it's both globally and locally you can see that gas prices have declined and that chart there really shows the domestic and JKM spot prices and the relationship between the two. Those trends are ones we've spoken about previously, but you can see them playing out, and really what Origin is setting itself up to do is to execute our strategy to deliver in that changing market, and you can see that we have, and on our Invest Today was another time for us to present that, but we really are executing a clear strategy that sets across accelerating towards clean energy, the low-cost operator developing growing gas resources. Gas will be critical to the increased adoption of renewables, but also... to the markets near Australia, embracing that decentralised and digital future and also clearly it's very important that we continue to ascend and become an increasingly customer-centric retailer. We continue to build the track record that sits alongside that and that's therefore setting us up to do a number of things across our business. cost to serve reduction of $100 million is on track and you can see the progress and we are now in the planning phase for the next wave of that transformation. We talk about building a digital IoT capability and those words may not mean a lot to everyone on the call, but I just really should describe the fact that what we've done is we now are orchestrating distributed assets. for our customers using our platform. And firstly, for our large business customers, we have tens of megawatts that we are running demand response successfully through our artificial intelligence platform. And they've already been contracted and there were three demand response events over the course of January. And so we're building trust and demonstrating that and in the underway in terms of growing greater volumes of those assets on our platform. The key benefit for our customers is both a reduction in cost and also a reduction in carbon emissions. At the same time, we've extended that capability to our residential and mass market customers, and we have now built that retail capability such that we're in live customer testing where we've now sold and onboarded to our customers air conditioner control programs, and we've run about five demand response events over summer. The reason I raise that is that it's just demonstration of the fact that as retailing the market and a distributed world changes, so are the capabilities that we're building around it. We've continued to grow revenue streams in our centralised energy service business, and you can see the customer growth. We'll talk a bit about broadband. Brownfield generation opportunities continue to be progressed, and those that are being progressed are responding to that changing market. We continue to exercise some caution around making those decisions given that we're currently in a period where governments are playing a role in terms of underwriting those and you would expect us to just make sure we've got a clear line of sight to the future benefits associated with those investments for both our customers and the economics. In integrated gas, our focus is really about exploring multiple plays in APLNG, continuing to reduce its costs, and we're very much now focused on the program associated with Beetaloo and they're the key opportunities and further afield we've done quite a bit of work in terms of pursuing the hydrogen and ONG transport opportunities. So we continue to execute our strategy for this changing energy market and positioning ourselves for the future. So just turning back to then the operational performance that's driving the returns in this financial year. We therefore, and we will cover this further in guidance, but really our view now for APLNG for the full financial year is that production will be improved and it's at the upper end of the range we previously guided to, or 690 to 710 petajoules. The distribution break-even at APLNG has now reduced to $29 to $32 US, a barrel equivalent, And when we give you that distribution break even, I think it's worth pointing out that that does include principal repayment of project finance of the US $8. So the operating break even is therefore now into the low 20s. And that will translate that performance now into a higher cash distribution to origin that's now up in the range of $1.1 to $1.3 billion Australian dollars for this financial year. We do expect improved generation performance in the second half of 2020 with a non-repeat of the unplanned outages. And we continue to target the 150 million company-wide cost out by next financial year. That includes the 100 million energy markets cost to serve that you can see we've already realized $43 million. That has allowed us to translate into a 15 cents a share, fully frank dividend, and as you would expect, continue to manage our capital. in a disciplined way. I'll now pass you over to Laurie who will take you through the financial review.

Thanks Frank and good morning everyone. Thanks for joining us on the call. Like Frank, I'm pleased to be able to present this morning a strong set of financial and operational results and like Frank, I'd call out cash generation as particularly being the highlight Free cash flow increased, as Frank said, 22% on the back of strong performance at APLNG, as well as proceeds from the Ironbark sale. Excluding the impact of the leasing standard change, net debt reduced by over $300 million in the half to $5.1 billion. But across the full 2019 calendar year, net debt is reduced by over $1 billion, again, excluding leases. Both statutory and underlying profit declined half on half. Underlying profit was lower than statutory profit, almost entirely due to backing out of favourable non-cash fair value adjustments. Underlying EBITDA was down, driven by lower earnings from energy markets, consistent with both our expectations and guidance. But I'll speak to that in more detail later. As foreshadowed at our investor day, we've adopted two accounting changes in this result. Firstly, consistent with the requirements of the new leasing standard, all leases are now recognised on balance sheet and the lease expense previously accounted for in EBITDA is now booked to DNA and financing costs. Right of use assets of just under $500 million have been recognised along with a lease liability of $540 million. As a consequence, underlying EBITDA increased by $42 million in the half. offset by a $50 million increase in depreciation and financing costs. Secondly, APLNG dewatering and workover costs have previously been capitalised. Having achieved steady state operations, dewatering and workover costs are now considered ongoing and operational in nature and will be expensed as incurred. This resulted in a $56 million reduction in our share of APLNG EBITDA offset by a $63 million decrease in our share of APLNG depreciation charges. Overall the adoption of these two accounting changes had minimal impact on underlying profit. Speaking of underlying profit, we presented a bridge on slide 14. Our profit was impacted by lower earnings in our energy markets business. particularly the electricity division, partially offsetting this with higher earnings at APLNG driven by higher production and sales and lower origin commodity hedging and trading costs as well as lower origin tax expense. Adoption of the leasing standard explains most of the increase in V&A with offsetting elimination of leasing charges across each of our business segments. Corporate costs increased by $14 million. including a one-off self-insurance cost of $7 million relating to the electrical fault at the Mort Lake Power Station. Now digging into energy markets in a bit more detail in slide 15. Earnings were down $129 million or 15% with almost all of the decrease coming from the electricity division partially offset by lower costs to serve. Electricity gross profit decreased $170 million and a half with the impacts of the business split between three factors. Firstly retail price regulation, specifically the introduction of the VDO and DMO. One-off unplanned outages at Araring and Mortlake power stations. In the case of the Mortlake we expect insurance recoveries this financial year. And then finally lower sales volumes. The impact from lower volumes was $46 million. split relatively evenly between expiry of certain large but lower margin business contracts, lower usage with solar take-up and increasing energy efficiency and changes in retail customer numbers and mix. This mixed element includes a growing proportion of lower volume but higher margin embedded network customers. Gas gross profit was lower due to some short-term wholesale contracts rolling off partially offset by lower gas procurement costs and favourable repricing of business contracts late in the comparative period. Our Cost Out program is well underway with cost to serve down $28 million and we remain on track for a $100 million reduction by the end of financial year 2021. Integrated gas on slide 16.

I'm going the wrong way, sorry about that everyone. Definitely operator error.

Our upstream businesses delivered a strong operational and financial result over the first half with EBITDA up 7% excluding the accounting changes. Record production to AP LNG and higher volume nominations from LNG customers resulted in a higher proportion of LNG contract sales relative to domestic sales. Realised LNG prices were flat in Australian dollar terms, APLNG's average domestic gas price was lower, reflecting a reduction in short term sales volumes at market prices, resulting in a higher proportion of lower priced legacy sales. Record production resulted in less gas purchases, partially offset by higher royalties which count but much of the $25 million shown in the other category on the slide. We had lower oil and LNG hedging costs in the period, partially offset by higher other costs, including $15 million to reduce our share of an overriding royalty in the Betaloo Basin. Next to free cash flow on slide 17. Free cash flow was up $600 million for the half, an increase of $124 million or 22% on half year 2019. Operating cash flow was down $202 million, reflecting lower EBITDA and higher tax paid on prior year earnings. Distributions from APLNG increased 32% to $520 million. The other movements in the half, higher capital expenditure, proceeds from the ironbark disposal and lower interest costs were all consistent with previous guidance. Free cash flow was allocated to debt reduction and dividends. As our debt balance reduces to the lower end of our target range, we can direct more free cash to growth opportunities and increase shareholder distributions. Moving next to capital expenditure on slide 18. The guidance of this year is higher than recent years driven mostly by higher than average planned power station overhauls and exploration and appraisal at Beetaloo. Much of the generation activity including major overhauls at the Araring and Irunquinti power stations occurred in the first half along with the reinstatement of the Mortlake power station following the electrical fault experienced in July. Expenditure in the second half will include continued spend in our LPG, solar and service hot water businesses, flexibility upgrades to the quarantine power station, ongoing activity at Beetaloo, system changes to meet the five-minute market settlement initiative and our ERP implementation. Now, APLNG cash flow. The pricing structure of APLNG's LNG contracts means that 93% of the financial year oil exposure has already been priced at US$68 a barrel as at the end of January. Based on this price outcome and the lower forecast break even, we expect a full year cash distribution from APLNG of between $1.1 and $1.3 billion for the full year. That's up from $943 million last year. Our current estimate of losses on oil and LNG hedging and trading for the full year is $102 million, $97 million lower than the prior year. Now looking at cash flow on a proportionate basis on slide 20 and a reminder the proportionate basis includes APLNG consolidated on that proportional consolidation basis. The results remain stable reflecting lower energy market cash flows and higher tax paid offset by the Ironbark proceeds I mentioned earlier. Proportionate free cash flow over the past 12 months excluding the impact of asset sales represents an annual yield of 12% of the current share price. 12-month rolling Roche is 8.3% down from 9.1% last financial year reflecting sustained improvement in integrated gas. but was more than offset by the impact of lower electricity gross profit in the energy market result. And finally I'll move on to our balance sheet on slide 21. We continue to target debt to EBITDA in the two to three times range. We are currently well within the range at 2.7 times. We've remained active in managing our debt book, increasing the average terms of maturity to 4.1 years up from three. and lowering the average interest rate for the first half to 5.6%. If you exclude the impact of commitment fees and amortised borrowing costs, our actual average interest rate for last month, for January, was just 4.1%. We continue to expect an $80 million reduction in net financing costs in the current year. Around $700 million of undrawn liquidity was cancelled during the first half reducing commitment fees but we do continue to hold substantial liquidity in the form of cash and undrawn debt to fund the large debt maturities due over the coming 18 months or so. So with that I'll pass back to Frank to discuss our operational performance. Okay, thanks very much Laurie.

Just now I'm turning to the operational review and firstly we'll cover energy markets. If I take you through to slide 24 you can see the sources and uses of electricity. Firstly, you'll note that we actually produced less electricity as a result of those outages at Araring and made up for that through really the supply from our gas-fired generation. Our volumes were down 7%, a combination of expiry of business contracts and changes in retail usage that Laurie just talked about earlier, solar efficiency, customer numbers and mix. If you then turn to gas, you can see that The sales for gas, natural gas are lower. They're predominantly all in those short-term wholesale trading contracts in Queensland which have rolled off and you can see that we've actually made higher sales through that period in the retail and generation segments. I touched on earlier on the next slide about more like back in service and certainly bringing it back has been beneficial through the summer months. A very good job to get that back. We do have some increasing capacity now as a result of some improvements we've made to those units. And what I'd also point out is that we expect the costs associated with the repairs and business interruptions to be recovered through insurance and that's where we stand. In terms of Maud Lake, we do see a brownfield growth opportunity there to expand its capacity to respond to the tightening market in Victoria that we're currently doing the feasibility and work around. And there's an option for us to also put some adjacent grid scale battery there in addition to these fast start gas turbines. We don't mention Shoalhaven. We continue to review the Shoalhaven proposal. And why we do that, we're continuing to really assess really the geotechnical costs and what they've come out is they've come out higher than we originally had thought. And I think that's around really the contention for that tunnelling activity that's going on right across both the construction and other markets. But we continue to assess that opportunity amongst others in our fleet. The gas position should be a familiar story to you all. Probably the key point around that is that there are 70 petajoules to undergo price reviews over the next two financial years. They really are set price review mechanisms that typically take into account comparable long-term wholesale contracts, volume term, also the capability of seller's facilities. Clearly, the downward trend on gas prices is a good trend to be going into price review for the business. Returning to retail, we have taken a disciplined approach to customer lifetime value. You'll see embedded in the volume losses has been some loss of some SME tenders that are at new low margins, and we've continued to adopt that disciplined approach. It's worth noting, though, that if we look at conduct in the market and we continue to see people pursue share, that we will make sure we respond appropriately in the market and but we always start from the foundation of a customer lifetime value. But that's actually something we will continue to assess depending on the conduct of those in the market. You'll see that churn overall is reduced and we call it in situ churn because clearly that yellow section of the graph on left is really people moving house. I'm pleased to see that we've actually really improved the experience for that over the last period of time. And you can see that overall, that therefore that's taking activity out of the market as evidenced by the wins and retains combined activity. And there you can see the net position of customers is a net 10,000 down in relation to electricity losses offset by gas gains. If we then go to the cost to serve on the next page, you can see really some further detail as to what's driven the progress against that target over the last six months. We're on track to achieve our savings by FY21 of over $100 million. The customer activity has reduced. We haven't seen that to be a material driver of it yet, only on the basis that there's been quite a bit of cost just in the transition around the regulatory pricing and other reforms. We will call out over time, the impact of that lower activity if it continues. And as you know, we were always calling up 100 million would be on a like for like activity basis. We are planning now for the next wave of transformation on both customer experience and cost and see that as the core directional trend, but also a core capability that we need to continue to pursue in the electricity markets. If we turn to the The transformation underway in retail, you can see both first customer experience, cost position and revenue streams just to draw out some of the achievements over the last six months. We certainly simplified products and customer journeys. We now have the number one rated app. You can see that's really transitioning a lot more interactions with our customers through digital channels, including that app online and also live chat. That's actually having the benefit of of both increasing the customer experience as measured by our net promoter score, but it's also driving to cost efficiency, so it's delivering both for us. You can see that also through the middle chart in terms of online sales increasing, e-billing customers up, and we really do increase our automation of our activity across the business. Lastly, in terms of revenue streams, you can see the growth there for our centralised energy service business, and we've made growth both in solar and broadband as well as part of our offering to customers. Just in terms of medium-term drivers and energy markets, and these are not different to what we would have communicated to shareholders before, but just to remind shareholders, that is that wholesale prices clearly, we have about 15 to 20 terawatt hours of supply of generation that are therefore relatively fixed costs so the forward wholesale price as it declines will reduce the contribution of those. We do have fixed cost PPA position coming in on 3 million certificates so in terms of our LREC or what you call our LGC position that's coming in at lower cost but we do have 3 million certificates that are actually exposed to those prices as well. In terms of fuel costs you can see that we use about 7 million tonnes per annum. We've got 4 million tonnes contracted, 22. The rest are actually contracted on a shorter term basis. And the same goes that as we continue to reprice and recontract in the gas market and both of those lower prices improve our supply position and we're in market all the time and you can track the trends of where those gas and coal costs are going. So they're actually moving in our favour. Similarly, as you look at that intraday volatility, we continue to be covered for peak demand. and continue to now enhance and you can see that through the Mortlake project recently to get increased peaking capacity and explore opportunities that actually cut right across that firming capacity from batteries, pumped hydro and gas fired generation. In terms of volume demand we do expect grid demand at least into the medium term and we think very longer term there's obviously electrification would increase demand, would still remain flat in the grid Customer growth really being offset by what we say as usage being solar penetration and efficiency. And we clearly demand will fluctuate by weather and any other competitive positions we adopt in the market. We are more leveraged to solar due to our incumbency in areas where penetration areas have been lower. So that combined with efficiency, we continue to see about sort of 1.5% to 2% as the ongoing trend in our business. As I said to you earlier, a disciplined customer lifetime value approach, but one that we will continue to assess in light of what's happening in the market. Coming to integrated gas, you can see there record APLNG production. I talked about that improved both subsurface and surface performance. Production's up 5% for the equivalent half to 358 petajoules, and we did record, I think, We broke the record for daily production several times, but you can see the record of 1,612 terajoules a day on the 3rd of December. It really is driven by that field performance and also – and facility performance, but also the performance of the non-operated joint ventures has also improved, contributing to that. And one of the things we did that unlocked utilisation of processing capacity was the commissioning of the ERIC pipeline through the six-month period. So very good to see all of those come together to produce those production results. That record production and lower capex is resulting in lower unit costs. The unit costs reduced to $3.50 a gigajoule. That's down 12% for the equivalent half last year. And that description of the lower costs on the right-hand side is compared to that first half last year. Clearly, we had targeted... The million-dollar well, we had targeted getting the operating costs down to $1 a gigajoule, and those things have all played out. And it's also, on a like-for-like basis, we've seen less wells being drilled by QGC, this half, than the equivalent half previously, and that's also contributed to it. There was also a settlement of a claim with the constructor that was settled favourably to us over the last six-month period, contributing to it. When we say focusing on further cost efficiency, it's worth reminding everyone that the dollar a gigajoule, a million dollar well represent about 30% of our cost base. So the key cost elements we now focus on are the costs of fracking, work over costs, work over frequency and horizontal well costs. These are the key future cost drivers of the business and focusing on them now represents further opportunity for improvement. There has been a movement because of the accounting classification between OpEx and CapEx, but if you were to actually do that on a like-for-like basis compared to the prior halves, you'll see that there is sort of a consistent – so that operating cost that you're seeing there go up is only really due to the – in that component is only really due to the accounting change. If we then go to the APL&G sales mix and realised prices, What you can see there is that there was no DQT declared for calendar year 2019. It has been declared by our customers for the calendar year 20, which has meant that the higher proportion of our gas went to LNG contracts for that period and also to meet customer nominations. So the realised prices are really a weighted average of what we sell into the LNG market and the domestic price market. And so the higher proportion of those LNG prices is really been the driver as to why we have a slightly higher overall realised price in Australian dollars for gas. Just turning to that upstream fuel performance and how that then translates to the full year, you can see there that we've upgraded the guidance in respect of both the CAPEX and OPEX. So that's now down from a range of $2.8 to $3 billion down to $2.5 to $2.7 billion. That's translating into that unit cost I described of $3.50 in the first half and a range of $3.50 to $3.90 for the full year. And that's therefore translating through to a distribution break-even that's now lower at $29 to $32 US a barrel. And that therefore means that the increased distribution from APLNG expected to origin is in the range of $1.1 to $1.3 billion. If you looked at the improved field performance resulting in those lower costs, it's due to not only the strong field and facility performance here today, both operated and non-operated, but you'll note we've made a comment there including a decision to defer or not participate unless economic non-operated well packages. Really, that strong performance is allowing us to now choose the most economic packages. We've created a low-cost operating platform. and as a result of that we're really being disciplined around the packages we do and that means that there are decisions we would make to not pursue some of those less economic ones from our non-operated joint ventures and therefore we'll make decisions whether to defer or not to participate in those and we do that on a balanced way but nevertheless to make sure we're making good decisions for the economics of the development of that field. The other thing was that there was lower well work overs than expected and you can see they're due to better field recovery post-plan maintenance. That's really in relation to our Reedy Creek field which we went through the turnaround activity over the last six months and they came back much better than we had anticipated and that's also been a driver. So another evidence of good performance of the subsurface. Just an update on some of the key AFLNG commercial matters. Firstly, I did mention to you that we have our long-term LNG customers declaring DQT for the year 2020, which wasn't the case in the prior calendar year. We received cash flow in January 2020 in relation to the deferred cargoes arrangement that we have previously communicated to shareholders. The first price review under the AP LNG's LNG contract with Sinopec has recently been triggered and discussions are currently underway. They're done in accordance with the terms of the SPA that we previously communicated. No force majeure notification has been received from our LNG contract counterparties in respect of the coronavirus outbreak in China. What the Queensland government has done is introduced a 14-day quarantine period for ships departing China. That's currently working effectively. and APLNG is working effectively within that, and there's no really significant disruption expected to the cargo schedule based on current circumstances. Not surprisingly, having DQT, that's one of the benefits of DQT has actually been in relation to also managing that as well. In terms of TriStar proceedings, the position just remains unchanged since our previous communication regarding the prospects for that claim, but there will be progress Over the course of this year, we will file our defences, and then there will be the amended statements of claim, and that will all happen over the next few months. And you can see that, therefore, there's a series of steps that would lead us to the court hearing, and so that's still some time away. We don't update our reserves base. So what you can see on the left-hand chart of slide 37 is the reserves base at June 19, but we really... We would like to communicate to you all that the field is performing in line with expectations. We continue to mature the resource through our exploration and appraisal plays and also through the recent acquisition of ironbark. We have those five or six material plays underway. What we've chosen to draw out is one of the particular plays, the East Ballin Deep. People should think about that as a spring gully type cold that's deeper underneath the conderbri and we're quite excited by that play. It has the opportunity that we'll be drilling from the same lease pads as Condabri and we've drilled two pilot wells. They're waiting to be fracked and we expect to have them online before the end of this financial year and we'll be then interpreting results from that. We continue to participate obviously in gazettals as well and there's been activity over the last six months in that respect. In relation to Beadle, we're obviously a key... a key growth prospect for us in Origin and in particular in the integrated gas business, the Kyala Shell Liquids Rich Gas Play. We've drilled the vertical section successfully. We communicated in January we had some operational issues with the initial horizontal section. We've now completed the second horizontal section that was drilled in February. You can see the metre, depth and length there. We're down to depths of 3,800 metres and also now nearly a 1,600 metre lateral section. Look, the results to date are promising and we continue to be excited by the prospect and we expect results from the production test of this well to be over the last quarter of this financial year and then into the first quarter of next financial year. We have environmental approvals to drill the Valkyrie shale liquids play and also to frac that well. We expect to be able to commence that in Q4 2020. Remember the stage two objective of these is to flow liquids rich gas to the surface during the production test. So good progress there and we're all excited to see how that plays out. Just in terms of outlook then, we have covered most of this but just to balance it out, the guidance for energy markets just remains unchanged and you can see the key drivers to that and clearly we're expecting a better second half performance in relation to electricity and we continue to make progress and expect to achieve what we've always expected to achieve over the course of this financial year. We've upgraded guidance that I won't repeat again in relation to integrated gas and you can see there the oil hedging and trading is consistent with what we previously guided to you. The corporate costs are up a little but they're really due to the self-insurance of Mortlake and we've commenced an ERP implementation so outside of that the underlying activity remains the same. So on unchanged for energy markets and the upgrade in relation to integrated gas. So now I might pause and we'll open up for questions and remembering I've got all my colleagues here with me, so we'll look forward to hearing your questions.

Thank you. As a reminder, if you wish to ask your 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 a handset to ask your question. Your first question comes from James Byrne with Citigroup. Please go ahead.

Morning, team. I wanted to ask about the ROSI for the group, which is sub-9% at the moment, but I recall, Laurie, your target here is to improve that to 10%. Now, notwithstanding an expectation for electricity in the second half being stronger, to what degree is the group reliant on APLNG continuing to as well as it has as opposed to energy markets being able to increase that ROCE which is currently low 8%.

Thanks James. I think we would look for improvement in all of our businesses as we go forward and I think that's what it takes. You know, getting to 10% and beyond will require improvement throughout. You know, we know ROCHI is an accounting measure. We understand for many LNG projects struggle to get a decent return on capital in the early years following commissioning the start-up. The same has been true for APL&G. So we do expect that to improve. And, you know, the improvement that we've seen as the team have stabilized that business for the first few years and now can focus on growing it has been great. So thinking back, I'm sort of off the top of my head. I think we're ahead of expectation from Roche from that business just at the minute.

I wanted to ask about contract prices for gas on the East Coast. I think I recall seeing just in the last few days headlines, the ACCC, who are quite good with their transparency on where contract prices are. We're still in the $9 plus range depending upon where you are and how you're cutting the data I suppose. With the redirection of LNG export gas to the domestic market, how are you expecting that to translate into potentially lower contract prices and by when?

Yeah, it's Greg here. Just with the ACCC report, that is a lag indicator, so he's talking about a different period, but since then the market has decreased substantially. And you can also see just how much gas is coming down from Queensland into the East Coast gas market. So we've seen changes already. You can see it in the graphs that we've got in our presentation today. You know, gas prices have come down. And so the market is working as expected. So it's in line with some JKM prices coming down.

Okay. This will be a very open-ended question because I appreciate that contracts are going to be specific to the requirements for the buyers and the sellers, but if you were to sign a vanilla contract in Queensland at the moment, what sort of prices do you think you would be able to achieve?

Yeah, I mean it's the JKM price plus a little bit... That's the wellhead? That's the wellhead, yep.

Okay. Okay, retail electricity, which I think that the volumes there had surprised the market when you disclosed them a few weeks ago. I want to understand whether you still think that your managed for value strategy has been successful in that regard. I note that you've lost some share here to AGL who were able to do so on a flat OPEX basis and they effectively said we didn't cut our prices to be able to achieve that outcome. So I wanted to understand how you're thinking about your performance over the half in retail electricity please.

Yes, thanks James. We've, as Frank said, taken a commercial approach and quite a distant approach to how we think about customer lifetime value. You can see there that in terms of the changes in customer numbers and mix, we've called that a $17 million reduction. There is actually an offset in our CES business of around $7 million, which is reported in that line. When we think about it, we think that's the right long-term strategy. But there is no doubt, as Frank said, that we will respond in market depending on what those competitive circumstances look like. The only other thing to think about here is obviously the counterfactual around high discount rates, which will therefore see the impact hitting on our discount spend line.

Got it. Thanks, Tom.

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

Good morning, Frank, Laurie and the team, and congratulations on an encouraging result. A couple of questions from me. Firstly, just on capital management, if growth remains challenging in energy markets, and I know that you mentioned there's that brownfield option at Mortlake, but with APLNG forecasts to distribute back more than $1.1 billion in cash annually, net debt now comfortably within your target range, can you comment on when investors might expect capital management?

I thought we were going to talk about CapEx. We're obviously talking about dividend Yeah, look, we have to make decisions from time to time. Our debt to EBITDA, we ended the half at 2.7. And so obviously there are two elements of that calculation. One of them is the debt level and the other is the EBITDA. And underlying EBITDA was a little bit weaker in the half. And also there was the impact of the leasing, which had a point or two impact on the measure. So we still, and I've been very clear, we still want to track our debt down towards the low end of that range. particularly as we approach potential investments, like, for example, an investment in Betaloo. So we're not comfortable. We're not even below the middle of that range, so we're still anticipating some future debt reduction. But by the same token, you know, you shouldn't expect us to sit on cash if we don't need it. So... And... Again, we're happy to have been able to provide a $0.15 per share dividend. It's up on $0.10 from the same half last year. It's the same as the final, and we get another chance later in the year. So we'll see.

Okay, Laurie, I think that's clear. Thanks for that. Now on retail electricity markets, and just following up on one of the prior questions, I note there's another small negative delta over the half on electricity customer accounts. Given that retail churn is coming down, I guess the question is why aren't you growing your customer base? Is it possible that there's too much focus on cost out rather than pursuing customer growth?

Well, you're right. We have seen customer churn come down, losses reducing, particularly those in situ losses. We have seen the loss of some large SME tenders in those electricity numbers. So they're at very low value or new value on that. What we have seen is that we have been able to grow customer numbers in particular areas where we've seen value. So as I mentioned, you've seen in the The lower volume but high value CES business, we're competing well across parts of New South Wales and parts of South Australia. I think that going forward, we're certainly not going to compromise on growing customer numbers for the sake of customers. reducing our operating costs to target. So where we see value, we will invest. We will invest for the long-term growth in those customers. And as I said earlier, we've certainly had an ethos of taking a value-based approach, but where the market shifts, we'll continue to make sure that we're defending and growing that share.

Yeah, OK, John, but I guess if they're low value, shouldn't we see a retail pricing come up? I'm looking at it looks down 10% year-on-year.

Yeah, I mean, what we see, if you back out the DMO video impact, is that, yeah, unit margins are not hugely different year-on-year. What we probably see is that Queensland's a little bit down, but they're broadly flat across most of the other states.

Okay. All right. Thanks, John. And then just finally on APL&G, continue to perform well in difficult market conditions. There's obviously lots of jitters in the market at the moment about whether Sinopec might call force majeure on cargoes. I recognise it's difficult to comment in detail, but can you provide some commentary on the types of things that the APL&G commercial teams will currently be doing to help Sinopec through these difficult conditions? I know there's a couple of planned outages coming up at APL&G. Can you use those windows and bring them forward to support Sinapec? And then also, how do you expect some of these current factors in oil markets to affect the repricing of that Sinapec contract?

Yeah, so Mark here. So thanks for the question. I mean, I guess in Sinapec, our biggest customer, but also a significant shareholder in APL&G, so we have a daily discussion with them about how we coexist together and and what we can do for one another and the state of that relationship through coronavirus and, you know, sort of the re-contracting discussions is really, really strong. I think you're right. We do have... The first thing they did is they declared DQT this year. Like Frank said, that's had the help of just slowing down the ships in rotation, which helps the coronavirus 14-day quarantine requirements almost perfectly. So there's very, very limited impact there. And then obviously, you know, we're really flexible with Sinopec in terms of where they want to take the cargoes. Obviously, it's an FOB contract, so they've got much more flexibility in their portfolio than you would have if it was a traditional DES-style project. So a lot of the flexibility that they enjoy, they naturally have anyway built into the contract. And then, of course, you're right with the downstream turnaround. It's on the bulletin board. It's in May. One of the trains, that's the four-yearly turnaround. And, of course, we're busy sheltering our own maintenance under that in the upstream, and obviously there'll be less cargoes coming out, which will obviously help during that period as well. So, I mean, just probably just reiterate, you know, obviously going well. And as Frank said on the recontracting, it really is as stated in the OFR. I mean, we've been pretty transparent, I think, as to how that contract works, how this price review works, and it's pretty much clearly set out there. Yeah, well, is such a major exercise.

There's virtually no flexibility to move it around.

That's right. I mean, these things get planned and, you know, and scheduled quite carefully with resources. It is a major operation up at Gladstone. That's correct. OK, thanks, all. That's enough for me.

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

Good morning, guys. Correct me if I'm wrong on the results. A couple of questions. On the energy market side, we're seeing softness in the electricity and the gas price, gas price probably leading to electricity. How much of your book is coming up for sort of contract renegotiations or rollovers during that period in gas and electricity, which may have an impact into fiscal year 21?

That's great. Look, on the coal side, You know, we're contracted to 2022 with 4 million tonnes. The rest we can buy from the market at current pricing, right? So that's one. With gas, again, you can see the gas chart there. You've got the gas volumes. A lot of that gas comes up under price review as well. But equally, we can still buy from... You know, we're buying gas today. So for the next couple of years. So... So we'll continue to do that. Just with the, you know, CNI, I think if that's your question, Ian, just what comes up, there is, I can't quite use the number of teratials coming up for the market. Maybe that's something I can come back to you, but we will be repricing that, but we do have choice about how we reprice those CNI customers. We can buy from the market or we can use our own generation portfolio. So we have choice around that. So, yeah. Thank you, Greg.

be fair to say that you've just got the average contractors between two and three years and therefore you'd expect there's not something unusual about that profile and so you'd expect that to be playing out in a reasonably on the CNI front. The 70% price review you're aware of, coal flexibility on that and also still flexibility in the gas portfolio to buy at current prices.

With that pricing pressure, do you think it makes it challenging for an energy markets business to be able to grow earnings in a falling price environment?

Look, we always try to expose the portfolio so we can buy fuel at different prices. We try to make sure... that we have, you know, we can take advantage of those prices. So, you know, it's somewhat favourable for the book. But equally, the other side is that the forward curve comes down. So we try to balance the portfolio, if you like. I think we're in a reasonable position on that.

Yeah, I think in reasoning, responding to it, the key thing that sits really above that comment is that at lower wholesale prices, you don't make the return... At lower forward electricity prices... you don't make the same return on the generation, in particular the eraring asset, and the lower REC prices, you still expose to the $3 million. So those are the two, in our view, they are the two key headwinds, and so therefore it does make it more difficult in lower wholesale. We have an ability to respond and reposition it the way we've set our book, but they become the key headwinds overall.

Mm-hmm. Just one brief more question on that side. Stockland Hill, will that actually be able to connect into the market or is it going to run late and delayed because of AEMO connection issues?

Look, Ian, so far so good. You know, those towers are getting constructed. We... You know, they're building the facility to make sure that it can get to grid. You know, that's... You know, we were pretty careful when we had that option to make sure that we connected to the 500 kV, so it has good connection. So, so far, so good. We're not hearing anything different at this point in time.

Okay. Now, on the APLNG side, cost performance continues to be excellent. How should we be thinking about that longer term? You talk about now focusing on the other two-thirds of the costs. How much further down can you bring break-evens? in a realistic sense?

That's a good question. Well, I think I'm going to start with sort of like, so the field performance is good. The facilities performance is matching the improved field performance. And so what we are seeing is that lower cost then gives us the ability to sort of re-scope and reschedule the program going forward. And that sort of underpins some of the decisions that Frank talked for around the non-operated deferrals and whatnot. So, you know, we've always said that we want to position integrated gas to be able to sort of, you know, to beat US shale into Asia on a marginal basis. And so that's exactly what we've been working on. We're not going to give sort of forward guidance for... But what we would say is, you know, we've got some really strong momentum flowing out of FY20 and we'd see that continuing nicely into FY21 because, you know, it is after all just a continuum of month after month of activity and programming.

Okay. And one final question for Laurie. When you talk about your range for net debt to EBITDA, of two to three times you want to be at the lower end. Are you now including leasing in that so effectively the new range would be 1.8 to 2.8 otherwise?

I haven't changed the range. Obviously, I've known that the leasing change was coming for many years. But really, it's had, I think, a 0.2 range. change on the metric so I knew we were going to need to absorb that for the range stasis.

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

Thank you. Can I start by asking on the Sinopec re-opener, as I understand it's on a best endeavours Can you give us an idea of what your opening position will be or is, i.e. are you going into it expecting or offering a reduction in slope?

Mark here. So maybe I'll just point you to the OFR and it's very much as it's stated there. So as Frank said, the trigger, the price review, it requires the parties to use reasonable endeavours. So, key words there being reasonable endeavours. Obviously, in the absence of an agreement, neither party can refer that to independent expert, whereas subsequent price reviews do have that, I guess, more traditional mechanism where parties can't agree, it can go to independent experts.

So that explains the mechanism, but can you comment on what your position will be? Given that it can't go to arbitration, effectively is your position that there will be no change to slope or are you going to be offering a reduction in slope, given I assume these conversations have already been had?

Well no, we're in the price review at the moment and we're having discussions, but we're not going to go into our approach or our position in those discussions.

Okay, and then on the cost reductions you're seeing, to what extent is that a, CapEx in particular, to what extent is that a sustainable level of spending to maintain or grow production slightly, or to what extent is it deferring or cherry-picking of these non-operated wells?

Yeah, so I think, one, I think it's sustainable, absolutely. I mean, we're running a sustainable operation in the sense that we don't We don't turn the CAPEX on and off to try and chase price or demand. We set a level of production that we believe is the right level of production over time and we stick to that. I think what we're hearing from us is that the field and facilities are performing really strongly and therefore that gives us strong momentum going into future years. Again, we're not going to give guidance on CAPEX by SOPEX today. For next year we'll do that during the full year sessions. But, you know, there are some things which you would have seen in this half that won't occur, we won't get the benefit of in the second half. For example, we're not going to get another downstream claim, the $50 million that sits in there that we got back from construction activities. That won't happen again. So it's sort of like a one-off saving. So those sorts of things you shouldn't expect to happen again. The momentum is definitely there.

Okay, great. And then one on energy markets, if I could. This is on the electricity book. So the way you set up your book generally is to benefit from lower spot prices, so short-term benefit from lower spot prices, longer-term negatives. Can you just speak to how that's playing out for you this year? To what extent you're getting that short-term windfall of lower spot prices?

Yeah, so, Greggie, look, last half, We were exposed to, you know, the book was exposed to the variety and just we had some unplanned outages there. So we had to run a little bit more gas. But again, you know, the book going forward, you know, is the same. So there's no different. And I do see there's no, you know, it's consistent of two and best today. I do see more volatility in this marketplace. So just with more renewables coming in. So, you know, the book is the same. That makes sense.

Yep, perfect. That's all from me. Thank you.

Thank you. Your next question comes from Mark Busatil with J.P. Morgan. Please go ahead.

Morning, everybody. I just wanted to ask a couple of questions about East Coast gas markets. You know, if you have a look at the current pricing on the gas supply hub, it's clearly below what you would need to have your CSG weld as economic. Is there a consideration that you might start paring back some of your drill program because the value of the gas and ground is probably greater than what the price is today?

Yeah, we might have a crack at that. So I'll first of all disagree that the current gas prices in the spot market are below the cost of producing the gas. So I think you've just got to be a little bit careful in the sense that, you know, the cost of producing gas at the margin, which is what we're talking about. We're not talking about the first 2,000 petajoules. We're talking about the last 50 a day. And that cost is actually relatively low in the sense that, you know, fixed OPEX is a much larger portion than variable OPEX. The CapEx is a sustainable program. And the other thing to think about in terms of slowing down or paring back is you've got to be really thoughtful about slowing down wells or shutting in wells and trying to chase that because it's not as simple as I get some saving and I can just turn it back on. We have done a lot of work on machine learning. We've machine learned from all our previous turndown events And so we run those models backwards and then run them forwards to predict what are the economics of turndown if we were to slow down wells. And what we find is it's certainly not as simple as you save some simple amount of money because different wells perform differently. So there's a seriatim of responses from the wells. So I think what I'm saying is it's more complex than just looking at $4.50 or $3.50 OPEX plus CAPEX divided by production. That's not what gets saved. It would be a much lower number than that. That's the margin. But we continue to look at it, and we will continue to look at it.

But if you think about the worker through 2019, as we saw record amounts of gas production through the East Coast, and if you sort of move forward to 2020, we've got Victorian offshore productions relatively stable, in fact, growing through Seoul. Cenex is bringing on two additional projects this year. Cooper Basin, there's more money going into there in terms of production levels up further. So, I mean, if you think about the outlook through 2020, it looks even weaker than 2019 for the East Coast gas market. And, you know, you're drilling 300 to 400 wells a year. I mean, is it not a thought? And even from your perspective, you're saying that. With your LNG customers calling DQT, there's more gas moving into the domestic market, presumably. So, you know, is there any thought of maybe drilling less wells this year and just keeping some of that resource in the ground?

Yeah, so firstly, we've built a really extremely low-cost model. That's what you're seeing in terms of delivery on costs. And we've done that for exactly the reasons why of the market that we see today in terms of a lower value market. We constantly optimize that program in terms of making sure that we drill the lowest cost wells as the next well that we drill each day. And we have, I think, pretty low exposure to short-term pricing. The majority of the portfolio is oil-linked or fixed oil. And so the choices are really quite slim in terms of the volume that we need to make a choice on. And we're not seeing at this stage any inability to dispose of that volume economically. Okay.

Just one last thing just on this. I think Frank mentioned through the presentation that there are positive benefits to lower gas prices in terms of those contracts coming up for price review, but that's at an origin level, not at APL&G. I mean, is there, you know, are there considerations at APL&G's level that, you know, it's somewhat beneficial to origin in terms of a lower gas price?

No, Mark, it's Frank. So you're absolutely right. APL&G will make its, decisions best on an economically rational basis as a joint venture as to future program and what's available for us to be doing. We've got to meet our contractual commitments and then you would expect the joint venture to be looking at those variable costs and what's the most effective program reflecting Mark's comments about the platform we've built and the flexibility we have available to it. The comments I made earlier were really around in the case of Origin. The lower price and clearly lower price for APL&G is less revenue for APL&G so therefore you'd want to actually be maximising the economic returns cognizant of what our obligations are to both domestic market and also to our contractual commitments. The benefit I was talking there about is that as a buyer of gas and a supplier of gas into the market that also feeds into a gas fleet of assets as well as the customers, that's clearly the opportunity is that re-contraction becomes available and then we've got to make sure that we do that in a way that continues to make us a competitive retailer and generator for those gas-fired fleets. So it's really that and clearly the opportunity for us to both price review is really a benefit just to Greg's business, but we do look at them and you're right, if you want to collectively bring that together, clearly we're highly leveraged to to gas prices or subject to contracts in APLNG that are all linked and so forth, so we need to think about both but they're separately considered.

Okay, fabulous. Thanks James.

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

Hi guys, just a couple of questions for you. Just to come back on East Coast gas prices, just a comment you made before Greg when there was a question around vanilla pricing in Queensland. Just a little bit of a spin on it because the answer you gave seemed to imply more of a shorter term price. Just wondering if you can highlight for me the differences you're seeing between a term gas contract and the spot price. Some of your suppliers have made it very clear that they see a marked difference. How should we think about that difference?

Yeah, look, we haven't struck a lot of long-term gas contracts just yet. But we are seeing, you know, on a short-term basis, we definitely see opportunities to buy sort of JKM-linked type prices, right? So it really depends, you know, what the long-term JKM market does. But if I were to give you a range, it would be more of the, you know, $7 to $9 a day market. That's kind of where the longer term prices.

And I'm just giving you a real rough estimate here, but that's where we see it.

Thanks, Greg. And sorry, just to clarify, I know that's just a rough number that you're talking about. Queensland delivery point or Victorian delivery point for that number?

Look, there is pipeline costs associated. I'm just giving you a range. And again, the whole, you know, the market is somewhat linked to JK and pricing, and then you've got to take into account your transport of gas. So that's why I'm giving you your range there.

Okay, thanks for that. And then another question for you, Greg, just on the performance in the current quarter. How are you seeing Mortlake going? I thought I'd and maybe I read the data incorrectly, but I thought there were a few high-priced events where the output looked a little bit low. Are you happy with how that plant is performing since it's been brought back into service?

Yeah, look, I have to go into all the details of the electricity market in the last couple of months. It's been quite a hectic, just with bushfires and transmission failures and what have you. But overall, the generation portfolios work really well. Particularly pleasing to see Mort Lake back. It was actually pivotal to ensuring that we supplied a smelter in Victoria, and it's performed really well. And Araring has performed well. So, yeah, overall, the profile is working well.

Excellent. That's it for me. Thanks.

Just to clarify, I mean, it was a situation which we did see a high-price event where Mortlake was directed off, and that was because of the transmission events, because of the email. It wasn't because of the performance of Mortlake. But again, overall, I'm pretty pleased with the performance. That's great.

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

Good morning, guys. Just a couple of questions on energy markets. Firstly, on Stockout Hill, I noticed in very small text on slide six, there's a comment there about completion date, end of CY2020. And I think previously, Greg, you mentioned kind of May of 2021 was the completion date. Just wondering if there's been a change there?

No change, Rob. I may just have to check what we said before, but in my mind, nothing has changed from previous guidance.

Yes, right. No worries. I guess you've got a great partner there in Goldwing, but just wondering if their deliveries of turbines have been impacted with what's going on.

had some of my team visit the site. Towers are going up, turbines have been delivered. It looks all okay thus far.

Yeah, okay, good to hear. And I guess it's in Western Victoria, and the Victorian government made some announcements about breaking free of the national transmission system, which I've seen on LinkedIn called Vexit. Does that have any impact on the longer run transmission connection for Stockyard?

Look, the first comment is just being deeply involved in that project, we made sure that we had very good connection into the grid. So more like it came at a little bit more expense that we connected into the 500kV network, right, which means that that asset really gets to market and I don't see any issues there at this point in time. As far as the Victorian policy, it only came out a change yesterday, so I might just look at Tony Lucas here to comment.

Rob, on the initial look at that, it looks like it automatically repeals after one year. So we're still reviewing it, but it looks like it's only a temporary measure at the moment.

Okay, cool. Thank you, Tony. So just a more general question about the generation fleet. If you could comment on if you're thinking or requiring a change in your levels of self-insurance and your premium and how that balance is changing. I guess obviously other people out there have had much worse outages than you guys so that's going to sadly impact on the insurance market.

Yeah, it's a very timely question actually. So yeah, we do consider our insurance strategy essentially on an annual basis. We've just been through that. Obviously we have to consider what's the exposures that we face and so that analysis will change to a small extent from year to year. But then we also have to consider the overall risk settings of the company. how much risk do we have appetite for and we'll adjust our insurance as we adjust other settings as well, whether it be oil hedging or whether it be the amount of liquidity that we hold and so they're all part of the same broader mechanism. Sort of a commercial issue and we're about to go to the market so I don't want to say too much other than we will reset that strategy to some extent, but not so much affecting the generation plate, so it's more focused elsewhere.

Okay, cool. Thank you, Laurie. And so I guess my last question is, if I can draw your attention to slide 47, and this is probably not a question for Mr Jarvis, and you've got your charts of the kind of average level of the baseload And if I look at Victoria, I can see that that forward for FY21 seems to be falling quite rapidly and much more rapidly versus New South Wales. I wonder, Greg, if we could get your expert and informed view on what's driving that.

Yeah, look, the first comment is just with the forward curve in Victoria, you've got to look at liquidity levels as well. It's pretty liquid out that longer term. But, you know, right now, what we're seeing just through this summer is, you know, you're seeing quite low pull prices, right, today. And that's just informing that market, but on very low liquidity. Also, what we are seeing, though, is the, you know, probably the mix between swap and cap prices. If anything, swaps come down more and cap prices have gone up. And I think that just... says that the market is, you know, sort of looks at, you know, the renewable things playing out. You see low energy prices but more volatility in the marketplace. So that's what I'm seeing in the Victorian market. But again, it's fairly illiquid. I think you'll see just in previous years that forward curve moving around a bit.

Yeah, OK. Thanks very much, guys. That's all for me.

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

Thanks, Laurie. Frank, just a quick question. Correct me if I'm wrong. I thought the payout ratio that you were talking to at the investor day last year for the dividend was sort of the upper end of the 30% to 50% range. I think today it's come in around the midpoint. Is that just an annualising issue or is there something you're just being more cautious on in the payout ratio?

Yeah, I think obviously we always qualify those sort of statements with the board. We've got to make a decision from time to time. As we looked at this leading into this results, you have to make an assessment about the world, the environment that we're faced with and our assessment is probably the world we face is probably a little bit riskier than what it was towards the end of last year. So we just have to make those judgments. But as I said earlier, we've got another opportunity at this with the final dividend. And I don't want to foreshadow a particular outcome because the board certainly wouldn't want me to do that. But we do have another go at it.

Thanks. Thank you. Your next question comes from Mark Samter with MSC. Please go ahead.

Morning, guys. Sorry about that. A couple of questions on the gas market in particular, if I can. I guess this first one's probably for you, Frank. There's an awful lot of hysteria around the gas market at the moment. I listened to some of the questions on this call. And I guess, yeah, just to ask you, we've seen the impact gas prices have had on electricity prices recently. this year, but let's roll forward a couple of years and everyone seems to forget Victorian production is going to fall a couple of hundred pages a year. You won't be DQT because you'll probably hit DQT maximum and potentially, albeit for a short period, spot on G markets recovered whilst you've got to catch up for the next wave of supply to come. I mean, we could be back in two years' time looking at materially double-digit gas prices. I mean, how much do you worry? You spent too much time in Canberra talking to politicians. How much do you worry about the opposite of the risk that everyone seems so panicked about at the moment?

I think we know that you've highlighted some of the drivers of markets into the future, and Canberra is still focused about bringing more supply into the market, and I think a good example of that is that You can see the recent federal government, New South Wales government arrangement attached to that is the 70 petajoule requirement they want to come out of New South Wales. So I do think they're still focused on supply into the medium term. And also, I think you can see there are increasing comments recently, and I think this needs to be drawn out, is that whilst it's more of a capacity for gas fire generation rather than necessarily volume, but But what's going to happen is if we want to continue to increase the growth in renewables, it needs to be matched by firming capacity and a significant portion of that firming capacity is going to need to be maybe different technology, but it's going to need to come from gas-fired capacity as well. So, yes, I think there's still a focus on that. I think there's a more measure about it because what they've seen is that as supplies come into the market, as we've said before, prices will come down. Those trends, no doubt, I think will move over time just for some of the reasons you've said. But I do think that we've got – there's time that the governments are now working towards making sure they're putting settings in that enable that supply to come in. So, yes, I still – you said the words worried. I think that we'll continue to have different – we'll still continue to have that, I think, challenge or opportunity over the coming years. Yeah, I do think that. and I do think it'll move it around. And it'll come by the way, you know, ultimately, what's that confidence around the cost of supply of gas, you know, and that will become the, that will be the enduring thing over time.

Perfect. Thanks. Maybe just a quick one first. Greg, in this, what I think is an interim period where you maybe do have that dislocation between contract prices and spot prices or short-term volumes, can you talk about, and I guess particularly as we thank the counterparty to your price-free negotiation, mentioned the word arbitration a lot on their conference call the other day. If you get outcome in these things that you don't necessarily particularly like and there is cheap gas around, can you talk about the flexibility you have in nominations and how much harder you could turn nominations down in the scenario where there's a lot more gas available cheaper short term?

Yeah, that's right. Look, under all our contracts, we've got various take or pay arrangements. So we've got some flexibility on all our contracts. So we can, right through our portfolio, we can... lower or increase those volumes. So if we have unfavourable terms, we could clearly take less and contract elsewhere. So we certainly do. I can't tell you the exact percentages. I just can't give you that detail but there is a lot of flexibility in our portfolio and not only just through contracts but physically as well. So I still come back down to just I think the gas market increasingly needs more storage, more flexibility. The LNG industry has brought a lot of that flexibility to it because we can just ramp a lot of gas down in the winter months, which is where there's less demand. Again, a fair bit of flexibility in the gas portfolio overall. Thank you.

Thank you. Your next question comes from Ben Wilson with RBC. Please go ahead.

G'day, Frank and team. Just one more question, if I could, about the Sinopec renegotiations. I take and read through your section in the OFR and that's very helpful. I just want to pick on one point. The reference to in-market contracting, I've seen this differ across various reopeners. Are you able to tell whether that references contracts that were signed for projects developed at a similar time to AP LNG or should we interpret that as looking at current long-term LNG contracts in the market?

I'm not going to talk specifically about what the Sinopec contract explicitly says. What I would say is generally LNG contracts and the price re-opener clauses effectively talk about a period of time – you go back to a period of time when contracts have It generally doesn't go back all the way to the period when the sign effect contract was originally struck. It's a more recent one. So the philosophy being it tries to bring the contract forward into the current market and reset it around the current market. But again, I can't comment exactly on the sign effect contract any further.

Gotcha. What I'm trying to assess essentially is does the provisions or, as you said, the spirit of the renegotiation reference... what's effectively a historical capital cost base of the project versus, say, comping it to what we might see in contracts from more recent US projects that are coming into the market?

Yes, again, you know, there's quite specific wording in the sign effect contract that we can't just simply can't. I'm not going to disclose this this morning.

Okay, no worries. And can I just ask a question on your continuing exploration appraisal activity within the APLNG resource base? The East Bowen stuff looks exciting if you're saying it's spring gully type coals down there. Is this likely to be your potential extension to that current 3P reserves base? I see there's not much less than 3P reserves relative to the rest of the reserve base. Could this be a resource transfer into reserves?

Yeah, so what we're saying is we're exploring a series of material plays that is successful, would flow from the exploration program into the development program. When they go into the development program, that's when we have intent to develop, and that then leads to us booking reserves around that. That would generally be each year in the middle of the year when we do the reserves report. We have a series of different plays that we're looking at. I guess what you're seeing us do is really look at resources that are material, but also resources that are close to existing infrastructure. And the Bowen deeps, or what we call Condubri deeps internally, is a classic example of that, drilled from the same lease paths as the existing wells. Evidence of that is the pilots will be actually tied into the Condubri facilities directly. That's like five metres away. And then away we go. and again, that update will come during the end of year results update.

Okay, that's great. Thanks again.

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

Okay, I'm sure many of you are probably wanting to head off to the next company announcement, but thank you very much for your questions. We'll look forward to meeting with a lot of our investors over the coming days. So thanks very much everyone.