Earnings Transcript for AGL.AX - Q2 Fiscal Year 2021

Chantal Travers: Thank you for standing by and welcome to the AGL Energy Half Year Results 2021 Investor Briefing Conference Call. All participants are in a listen-only mode. There will be a presentation followed by a question-and-answer session. I would now like to hand the conference over to CEO, Mr. Brett Redmond.

Brett Redman: Good morning everyone. This is Brett Redman speaking. Thanks for joining us for the webcast of AGL’s half year results for financial year 2021. I’m joined today by our CFO, Damien Nicks; Chief Customer Officer, Christine Corbett; and Chief Operating Officer, Markus Brokhof. We will have time for all your questions at the end of the presentation. The results we’re announcing today reflect the sharp decline in wholesale prices for electricity and renewable energy certificates, lower gross margins in Wholesale Gas, and costs to support our operational and customer response to the COVID-19 pandemic. Underlying EBITDA of $926 million was down 13%, while underlying NPAT of $317 million was down 27%, reflecting the additional impact of higher depreciation expense. Our statutory result has been impacted by the charges associated with onerous wind offtake contracts, rehab provision increase, and other impairments we announced last week. Dividends reflect the special dividend program to temporarily lift the payout ratio to 100% of underlying NPAT unfranked, comprising an ordinary dividend of $0.31 and a special dividend of $0.10. The outlook remains challenging. We expect underlying NPAT for FY21 of between $500 million and $580 million, consistent with the update that we provided in December. That includes $80 million to $100 million dollars of insurance proceeds from the Loy Yang 2 outage of FY20, which won’t repeat in future years. This range reflects preexisting headwinds, as well as the continued deterioration in Wholesale Electricity market conditions and the financial impact of the current outage of Liddell Unit 2. We are also providing today a guidance range for underlying EBITDA of $1.585 to $1.845 billion. As we noted in December, the outlook into FY22 and beyond is impacted by continued market and operating headwinds, with a further material step-down in Wholesale Electricity margin expected. Amid these challenging conditions, over the half we continued to deliver on our strategy. We grew our total number of services to customers by 246,000 to 4.2 million, making us Australia’s largest energy retailer, thanks both to the Click Energy acquisition and organic growth. Take-up of our broadband offering and carbon neutral products has exceeded our expectations, while the launch of AGL mobile has just gone live. We are on track to deliver our plans for at least 850 megawatts of grid scale batteries, while our orchestration and demand response activities are expanding strongly. And now, we are taking further definitive action to stay ahead of the challenging conditions. We are benchmarking cash running costs to FY15, the last time Wholesale Electricity prices were around today’s levels. To that end, we have already identified $150 million of operational expenditure savings to deliver in FY22. We are also targeting a $100 million reduction in sustaining capital expenditure across the group by FY23. Finally, we are assessing our business model and capital structure to maximize shareholder value. We will have more to say on all these initiatives at an Investor Day we expect to hold around the end of March. Let me now turn to our three core operational metrics

Christine Corbett: Thank you, Brett and good morning everyone. Today, I will provide an update on the financial performance of customer markets and the progress we have made on our multi-product retailer strategy. In a challenging operating environment, I am pleased to say that as a result of our focus on customers, our positive customer advocacy story has continued and we have reported significant growth in our customer base. At the same time, we have continued to focus on lowering costs, improving the customer experience and building the foundations to become Australia’s leading multi-product retailer of essential services. Our half year performance was driven by strong customer growth, execution on our multi-product strategy and underlying cost efficiencies against a challenging backdrop. Our underlying EBITDA of $177 million was down 12%, reflective of COVID-19 impacts and the integration of our new acquisitions, Southern Phone, Perth Energy and Click Energy. This was partially offset by lower operating costs due to a decrease in call centre volumes and marketing efficiencies, together with an increase in the number of digital interactions with our customers. Regulatory intervention, customer behavior and high levels of competition have resulted in electricity margin compression in recent years, most prominently in Victoria due to the extent of regulatory changes. While this will impact in-year results, we expect to see retail energy margins settle to more sustainable levels in the near medium term. Meanwhile, our continued focus on growth in customer numbers will continue to result in volume driven margin growth and our multi-product retail strategy will drive an increased share of wallet. Our overall CapEx has increased 5% aligned to growth initiatives. The growth in customer numbers includes the acquisitions of Click and Perth Energy, both of which are tracking ahead of business case. In the second half, we will continue to focus on energy growth and scaling our AGL internet and mobile service offerings. We will make further improvements to our customer experience, while at the same time continue to improve our cost base as we further digitalize our business. As we continue to build the size and strength of our retail customer base, net promoter score is now at a record level. We are seeing the impact of this both in the growth in customer numbers and reduction in customer churn. Churn is at 13.9%, the lowest since 2014 and we have maintained a healthy spread to the rest of market. Our strong growth in customer numbers is reflected in our gross margin result, which has remained resilient despite customers switching to lower priced products over time. Offsetting this, we’ve seen gross margin growth from acquired businesses, as well as organic customer volume growth and consumer gas. We feel confident about growing our customer base further, consistent with the target of 4.5 million services by FY24. Our underlying net operating costs per customer service continue to fall, driven by our recent investment in systems and our ongoing focus on simplification and digitization. We are delivering these cost benefits at the same time as we pursue a growth strategy, enabling us to reach more households and businesses with increased efficiency. Our focus on customers provides the foundation for our ambition for AGL to be the leading multi-product retailer for the connected customer. New products and services will help deliver customers better value and an effortless experience with the launch of AGL internet and mobile in the last few months. By 30 June, every product we sell will have a carbon neutral option. By delivering value and catering for the demand for sustainable products for our customers, we in turn deliver greater long-term value for AGL shareholders. We will increase customer lifetime value through improved average tenure and overall services and margin per customer. At the same time, our cost base will be further improved through the economies of scale we deliver across both fixed and operating costs. We have bold ambitions to make a significant impact in the lives of our customers with positive progress already realized, centered on customer growth, digitization and building trust and simplicity. I’ll now hand to Markus to talk about Integrated Energy.

Markus Brokhof: Thanks, Christine and good morning everyone. To start, this page includes an update on AGL’s operational performance and impact on financials. Underlying EBITDA for the half year was down 11% to $911 million. This includes some of the effects of COVID-19 on demand for gas and the large business and Wholesale Customer segments of electricity, but also the longer term impact of the electricity transition on prices. You will see on the right of this slide a reduction in our capital expenditure year-to-date by 36%. This reduction is split equally between sustaining CapEx and growth CapEx. In the case of sustaining CapEx, the reduction is driven by major planned outage deferrals and rescoping due to COVID-19 restrictions that have changed how we are able to safely deliver work and access interstate and international expertise. For growth CapEx, the reduction is due to the completion of Barker Inlet Power Station in financial year 2020 compared with this year. Smaller growth investments have been made in the orchestration platform of our decentralized energy business and the uplift of our trading systems. In the remainder of the financial year, we will be focusing on bringing our announced battery investments to fruition and advancing our Crib Point LNG import terminal to the final investment stage. In addition, we are focusing on operating costs. Integrated Energy will deliver a substantive portion of the total company target of $150 million in financial year 2022. The primary savings have been identified from asset maintenance optimization, reduction of contractors, decrease in professional services and consulting services and reduction in overtime. Finally, we will look to complete a review of sustaining capital expenditure that we have been undertaking with international expert advisors. We can’t assume that the way we have operated our assets in the past will be the way we will operate in the future, and we are working to understand how we can operate more flexibly and efficiently in response to market conditions. Let’s now turn to how our assets performed in the period. Given the challenging conditions I just outlined, I have been happy with the ability of AGL to react and rebalance our resilient asset portfolio. On the right, you can see that AGL’s overall generation is down less than 5%, despite some material unplanned outages mainly at our coal power station at Liddell, including the severe Liddell Unit 3 incident on 17 December. After an in-depth analysis, return to service is scheduled for 26 March. Loy Yang is running more reliably than in the same period last year. Renewables generation has increased more than 10% compared with the first half of last year, reflecting the increasing role in the AGL portfolio played by Coopers Gap and Silverton Wind Farm. Barker Inlet Power Station is performing ahead of business case to meet market demand for flexibility and firming up renewable generation. On this page, as we did at the August results, we are showing the AGL gas supply portfolio by the year in which contracts were signed. The gas book historically has been underpinned by a substantial volume from supply agreements signed when gas prices were much lower. The margin pressure we are seeing this year has a lot to do with increased procurement costs as these contracts roll off. Looking ahead, as domestic gas supply availability in the South diminishes and pipelines to key consumption areas look increasingly likely to face capacity constraints, we are planning to shift our sourcing strategy to include gas imports notably via Crib Point. We believe Crib Point provides the best mechanism to meet Victorian customer requirements and provides the flexibility to ramp up and down to match demand. The panel assessing Crib Point is expected to provide their report to the planning minister by the end of February. In the meantime, we are contracting on a short to midterm basis additional supplies to meet our demand forecast, the most recent of which is shown in black on this chart. Recent portfolio contracts could be secured in the range of AUS $6 to AUS $7 per gigajoule which has an positive effect on our overall portfolio price and can compensate partially the roll-off of some legacy contracts. Let me now turn to electricity. AGL has a rolling two-to-three-year hedging strategy that is influenced by the liquidity of the market and our customer portfolio. Having this hedging strategy in place has mitigated the downside in financial year 2020 and financial year 2021 as prices have fallen. In this chart you can see for each of the past three financial years, the hedged generation portfolio and the vintage of the hedged volume including market pricing. It is this active risk management that has mitigated the downside of declining prices. However, as you can observe in the price labels, the earlier vintages were hedged at a higher price. So, as financial year 2017 and financial year 2018 roll-off, there will be a continued margin impact going into financial year 2022 and financial year 2023. We will continue to focus on actively managing our hedge position to manage price and risk exposure, combining this with the evolving nature of our portfolio into the future. I will close by talking about our strong coal supply position in New South Wales and how this translates to our competitive position. The chart on the left shows our contracted position at AGL Macquarie, which will continue to provide us access to lower priced coal than the market average into the mid 20s. The chart on the right shows the evolving dark spread in New South Wales from July 2019 to January of this year. A dark spread is the difference between the price received by a generator for electricity produced and the cost of coal needed to produce that electricity. All of the plant's other expenses must come out of this spread. Hence, it is the main benchmark used to gauge the financial health of coal powered electricity plants. With a declining dark spread moving below $20 per megawatt hour, as show in black on the chart, the profitability of much of New South Wales’ coal generation will come under pressure. You can see this trend in the NSW dark spread line converging with the average fixed operating costs in the chart on the right-hand side. While AGL has a big advantage because of the dark spread premium we enjoy, as shown in blue, we are not immune to this trend. Hence, our focus needs to be on costs and efficiency to keep the plants running economically. I will now hand to Damien.

Damien Nicks: Thanks, Markus and good morning everyone. I will start by taking you through group underlying profit in more detail. The $115 million reduction in underlying NPAT in the half was consistent with the material headwinds we flagged last August. Looking at the chart from left to right, as you have heard from Christine, customer markets margin was down slightly as a result of COVID-19 costs and lower pricing, partially offset by a solid performance from Click Energy, Perth Energy and our new telco business, which combined contributed $32 million to margin. In Integrated Energy, margins were impacted heavily as forecast, offset by the receipt of the majority of the Loy Yang Unit 2 insurance proceeds. Keep in mind that the $105 million shown is pretax. Post-tax, it’s $73 million in the half. For the full year, we remain confident in the $80 million to $100 million post-tax range we forecast for the full year. Depreciation was up $15 million before tax in the half, again consistent with our guidance for an increase in this expense. The reduction in tax expense largely reflected the fall in profit while net finance costs remain tightly managed. Now let me remind you of the four principles that underpin our approach to capital allocation. Consistent with the first, running the existing business for optimal performance and value, we have announced plans to reduce both OpEx and sustaining CapEx today. Since 2015, AGL has grown both our customer book and fleet materially, not to mention the inflation between now and then, so bringing our costs back to this level will be a significant achievement. Our second principle is to maintain a strong balance sheet and dividend policy. Underlying cash conversion remains strong, and we remain well within the bounds of our BAA2 credit rating. We are augmenting our dividend policy with a special dividend program as announced in August. Our third principle is to invest in growth, which we continue to do with a hurdle rate 300 basis points above our weighted average cost of capital. The fourth principle is to return excess liquidity to shareholders. The buyback was completed in August. I'll now look at our cost reduction program in more detail. We have identified $150 million in sustainable operating cost reductions for delivery in FY22, in addition to continuing to offset annual inflation. That follows our objective to keep FY21 OpEx flat, excluding COVID-19 impacts and acquisitions, against which we are tracking slightly ahead at the half. The remainder of those COVID-19 costs include increased allowance for expected customer credit loss, costs to ensure employees and contractors were able to continue to work safely and securely at AGL generation sites during lockdown, and increased leave balances. The decrease in other costs is being driven by ongoing savings from recent digital transformation initiatives and other efficiency programs, partially offset by a small amount of restructuring and redundancy costs in response to more challenging operating conditions. You’ll note on the slide that the waterfall starts on the left FY15, which we are using as a benchmark year. The FY22 cost program is well underway. We’re anticipating savings year-on-year from lower net bad debt expense as well as savings across labor, asset optimization, digitization and reductions in corporate functions, in addition to a material reduction in professional and consulting services. We have identified these savings across our business units, they have been budgeted and leaders understand their KPIs. I want to touch on credit loss in more detail. I’m pleased to report that our experience is tracking better than we expected year-to-date. As a result, we have reduced the provision by $5 million, but of course, there is still significant uncertainty around COVID-19 itself and the impact of government support programs rolling off. Lastly, a comment on the Click Energy acquisition. We did increase credit loss provisioning as part of our business case assumptions, reflecting the different risk profile, but to date, its collections have performed better than our business case. Now, let’s turn to CapEx. Following lower CapEx in the half, we are now forecasting CapEx for FY21 of about $750 million. The biggest difference to FY20 being the investment in growing the multi-product retailer offering in customer. You can see the level of sustaining CapEx each year marked on this chart with a black line, again benchmarked to FY15. This has largely been driven by the mid-life and major outage schedules of our coal fired generators. We have detailed programs under way to deliver reductions in sustaining CapEx as part of our $100 million target for the group by FY23. This will appropriately balance our maintenance program, prioritizing commercial availability and efficient operations with our need for the cost base to reflect market conditions. I’ll finish by talking about cash and debt. In the half, there were increased cash tax payments and negative working capital movements associated with our Wholesale Electricity market positions. Most significantly, there was a small outflow from margin calls compared with a large inflow in the first half of FY20. Excluding margin calls, which move with wholesale prices, underlying cash conversion was strong at 90%. Investing cash flow was about $50 million higher as lower CapEx was offset partially by increased spending on acquisitions. Financing cash outflows were about half of last year reflecting debt retirement and the cessation of the buyback. Despite the impairment, we retain plenty of headroom under our BAA2 credit rating and all our debt covenants. We have no major refinancing due until November 2021 and approximately $600 million in cash and undrawn debt available. We did not replace an undrawn facility that matured in September given the high levels of cash in the business. I’ll hand you back to Brett.

Brett Redman: Thanks, Damien. I want to conclude by looking at the historic relationship between EBITDA and Wholesale Electricity prices, to help put more context about our outlook beyond this year. Wholesale Electricity prices are the biggest driver of AGL’s profitability. And you can see from the chart to the right, there is a strong correlation between the price trend both up and down and AGL earnings. The steady rise that occurred from FY15 to FY18 translated into record profits in FY19. And the decline we’ve seen since is now translating to much lower earnings this year and into the next couple of years. Markus has taken you through our hedge book in more detail, from which you can see that our progressive hedging approach smoothes our earnings outcomes, both downside and upside. The chart here shows that wholesale prices are at levels last seen in 2015, hence it is likely earnings will follow. I’ll finish by recapping our formal guidance statement, with our outlook continuing to reflect the challenging market and operating conditions. Today, we have provided guidance for underlying EBITDA of between $1,585 and $1,845 million and affirmed the guidance range that we provided in December for underlying NPAT of $500 million to $580 million. This includes the expected $80 million to $100 million after-tax benefit from our insurance claims over last year’s extended outage at Unit 2 of AGL Loy Yang, which won’t repeat next year. We continue to expect FY21 operating costs, excluding depreciation and amortization, to be broadly flat on FY20, excluding COVID-19 and acquisition related costs. Our FY21 guidance reflects the pressure to margin of lower cost supply contracts maturing in Wholesale Gas, lower market prices in Wholesale Electricity, higher depreciation and the costs associated with our COVID-19 response, as well as the $25 million financial impact of the Liddell incident and further market deterioration and trading performance announced in December. In FY22, the insurance benefits will not recur. In addition, we continue to expect a further material step-down in Wholesale Electricity margin in FY22, despite the benefit we will see from having impaired onerous wind farm supply contracts, as older hedging positions progressively roll-off and are recontracted at lower levels reflecting the deterioration in wholesale prices. The cost-out program that we have announced today will not be sufficient to offset this negative earnings trajectory. As always, all our guidance is subject to ongoing uncertainty in relation to the economic impacts of the COVID-19 pandemic, as well as normal variability in trading conditions. Thank you and we will now take questions.

A - Chantal Travers: We will now open for questions. [Operator Instructions] Our first question comes from the line of Tom Allen. Go ahead, Tom.

Tom Allen: Hi, good morning Brett, Damien and the team. You obviously made a number of references during the presentation to assessing the business model and capital structure to maximize shareholder value. Now, I recognize that you're going to share more detail on that at your 29 March Investor Day. But given that you've announced it this morning, can you please provide some color on the types of changes you might consider to your business model?

Brett Redman: Thanks, Tom. Look, I'm expecting that in varying forms we'll get that question a bit today. And what we're trying to do is show that we both recognize and are responsive to the market conditions around us. So, clearly, a difficult day, or difficult presentation day-to-day, where we have to acknowledge thematics of the last six and 12 months are both continuing and accelerating. And at the same time, we've had the significant impairment last week and a difficult operating profit that we are presenting today. Even in the context of -- I'm really pleased that we've been hitting our strategic goals along the way. But it's in that context that we think it's important for us to show or to acknowledge to the market that we see what's happening around us. We see what's happening ahead of us and that we are thinking about what's the appropriate response to it. And in that sense, we need to spend the time to make sure that we're thoughtful in a very complex situation, which will require a complex discussion in response. And we're going to come back with that thoughtful and complex response at the end of March when we get a hold Investor Day.

Tom Allen: Okay. Thanks Brett. I'll look forward to engaging on it more at the Investor Day. I'll jump back in the queue. Thanks.

Brett Redman: Thanks Tom.

Chantal Travers: The next question comes from the line of Rob Koh. Go ahead, Rob.

Robert Koh: Good morning. Thank you very much everyone. So, I guess, my question is about the outlook for your OpEx and you highlighted some of the initiatives that you will be doing. I'm just wondering, should we not be expecting even more reduction in OpEx going forward from things like COVID bad debts not recurring from the reclassification of COGS under the onerous contracts and things like more self-insurance? Or I guess if the cost initiatives you've identified are in addition to those, is that the right way to think about it?

Damien Nicks: Hi. Rob, Damien here. Look, the way to think about this is that $150 million, it does include the reduction in net bad debt expense. What you need to remember we had some last year, we've got some more this year that will then return back to normalize levels. Then the way to think about that then is across the business. What we've done with them working on this program over the last 12 months, when COVID first hit us, we then accelerated that program six months ago under our operational edge piece to work through the business to identify and then start delivering cost savings. And what you're seeing excluding -- bad debt excluding some of the COVID expenses underlying costs for the half were actually down $20 million. So what we're daring to do is hit those run rates by the time we hit 30 June to be delivered $150 million. And again, it's broadly across the business, Markus talked about some of you, within Christine's area, it's around further digitization. It's been some restructuring, reorganization we've done over the last six months and then further across the corporate gender as well. So, it is broadly across the organization.

Robert Koh: Okay. Good. Sounds good. All the best with that. Thank you very much.

Chantal Travers: Thanks, Rob. The next question comes from the line of Ian Myles. Go ahead, Ian.

Ian Myles: Hi, guys. If we got to go if FY22 outlook, and I'm just looking back at the numbers for FY15, you had Wholesale Electricity sort of reporting and even 676, since then depreciation virtually doubled. When you think about that sustainability, are we thinking at a gross margin was going back to sort of 2015 levels, or we think actually EBITDA going back towards those types of levels because you've actually a lot more depreciation happening there.

Brett Redman: I think, Ian, the context of that comment, I'd first read through the lens of EBITDA, because let me acknowledge that depreciation has stepped up, as we've seen the full impact of normalizing for owning a lot more plant during that period. So, I think, EBITDA is probably a better guide to start with. And the other comment I'd make is it's sort of a broad statement to say we're looking at FY15 as a reference here. I'd sort of counsel people not necessarily the pull apart every line of detail and try and match every line within it. Because I think the business has evolved quite a bit in last five or six years. So, the detail -- at a very detailed level, the analogy breaks down a little bit, but at a macro level, I think it's a fair analogy, particularly at the EBITDA level.

Ian Myles: Okay. I'll pass the question.

Chantal Travers: Thanks, Ian. The next question comes from the line of Mark Samter. Go ahead, Mark.

Mark Samter: Yeah. Good morning, guys. Just a question -- I know remuneration is a sensitive subject, but I'm just think it's a good way to backtrack. The company thinks about it. Your LTL incentives described 5% to 8% ROE for your average as a stretch target. I guess both the denominator and the numerator of the ROE calculation benefits of impairments and provisions announced last week. Should we still think the 5% ROE is a stretch target? Because I guess that just mathematically it gets you down about $275 million, if impact is defined as a stretch target, or should we rethink the ROE guidelines in light of the impairments and provisions last week?

Brett Redman: Look -- thanks Mark for asking what is an awkward question, but is an elephant in the room. So it gives me a chance to answer it. First and foremost, the Board always takes the approach that way we have something like in impairment or in recent years to share buybacks are another good example that might give a benefit if you like to management in the LTI calculations. That was unforeseen when the target was set, they're stripped out. So, while obviously the Board will decide on bonus outcomes until the end of the financial year and beyond. Let me say with confidence that my expectation on behalf of management is that will apply consistent approach and remove any benefit of the impairments from those calculations. In that sense, I would also say that in a difficult financial year, I'm not expecting -- what's the way to say it, strong outcomes in a bonus sense. So I think we're seeing the LTI metrics heavily impacted, both at an ROE sense, the TSR sense. I think in the long haul, we're heading in the right direction on the carbon metric, but that's three to four years away in terms of hitting a reward point. So, I come back to, I think the key message here is the Board will remove from calculations any benefits from things like impairments and as the shareholders are suffering significant pain -- I want to acknowledge that, suffering significant pain, that will reflect on certain through the incentives. And I'd also say at a personal level is reflected in my personal shareholding and others within the management group. So, if you like that, that pain is shed appropriately.

Mark Samter: Thanks, Brett. Thank you.

Chantal Travers: Thanks, Matt. The next question comes from the line of Peter Wilson. Go ahead, Peter.

Peter Wilson: Thank you. Just a question on operating costs and the targets you put out there. So on slide 11, it looks like there's a large second half step up to consumer operating costs. Could you just give us some color on what that is? And then on your CapEx target, explain how you affected Liddell into that.

Damien Nicks: So, look, the step up in the second half is largely the provisioning net bad debt expense half to half. So that's based on sort of our modeling of where we actually see the actual expense roll through. On the second part of the question around our CapEx, so does include Liddell, basically we were spending very little on Liddell today as it is. So, yeah, it excludes Liddell about $100 million will be across the sustaining -- not just them, across the business, but a large part will be coming from Integrated Energy.

Peter Wilson: Okay. If I could just follow that one up. The message also, it had been you spending quite a lot on Liddell and that's why Dan, it stepped up, is that something …?

Damien Nicks: Peter, that's correct. I mean, in this year, and as we now wind down to the closure of that plant, it will be only the spend that we need to, and it's rather -- I mean, Markus whether you want to comment, but it's not large dollars at all.

Markus Brokhof: No, it's around $12 million.

Brett Redman: So for clarity, it's 10-ish, is the Liddell CapEx expand this year? You say it more pushed into OpEx, which is appropriate for a plant, but it's in its last year or so of life. You're not launching significant CapEx programs. So, technically, Liddell is in there, practically its impact I am saying we're pulling 100 out is de minimis.

Peter Wilson: Okay. Perfect. Thank you.

Chantal Travers: Next question comes from the line of Max Vickerson. Go ahead, Max.

Max Vickerson: Thanks, Chantal. Cushion for Markus on the gas market. Those comments you made about the portfolio contracts being able to be secured in the $6 to $7 figure vigil range. I'm just wondering, are there meaningful volumes available at those prices or are you more talking about smaller -- quarter to quarter contracts that you might sign on the -- in the short term markets like the one on [indiscernible] us taking? And could you give us a bit more color on that, please?

Markus Brokhof: Yeah. Thanks for the question. Yeah, you're pretty right. The depths of the market is not there. So volumes are limited. So the team -- also contracts, which we entered a one to two years and that's the range in which we are, and we still try to secure additional volumes in order to optimize the overall portfolio price. And yeah, that's at the moment, the case.

Max Vickerson: Okay. Thanks.

Chantal Travers: Next question comes from the line of James Nevin. Go ahead, James.

James Nevin: Thanks, Chantal. Well, I appreciate you're going to give more detail on how you're looking at the kind of future business model at Investor Day. And which was some of the comments that you've made in the presentation this morning around the retail service becoming more independent from the valuation -- from the value of the generation portfolio. And you're going to say you get less synergy from being an integrated retailer. Like, it looks like you're kind of trying to steer us maybe into like one of the options that you're looking at, essentially splitting up the retail side of the business from the generation portfolio. They bought moving in very different directions now.

Brett Redman: Thanks James. Look, I think, and this'll be the difficult discussion with lots of people in the coming, whatever it is, six weeks or more or less, to the end of March when we hold the Investor Day. We'll get into sort of having to try and answer black and white. Yes, no type questions in an incredibly complex environment that will require complex responses. So, in the slide there, what we're trying to do is call out some of the thematics that was saying happening in our market that have evolved from -- when I reflect on the market of five years ago and 10 years ago, it is different today. And when you think about where customers are heading and what they're demanding in a product set today, it's starting to become very different to 10 years ago. When you're thinking about the role of government policy in our markets today, it's very different to what it was 10 years ago. So all of these things are taking what was a very clear cut set of assumptions and responses 10 years ago to evolving and more complex sets of conditions and responses that we're seeing in front of us today. So, rather than rush it, we wanted to signal today that we're not sitting on our hands with our eyes shut and our ears closed to conditions around us. But at the same time, we want to be thoughtful and come back with a complex answer to a complex situation at the end of March.

James Nevin: Thank you.

Chantal Travers: Next question comes from the line of Mark Busuttil. Go ahead, Mark.

Mark Busuttil: Good morning everybody. I was interested in some of the comments that were made around dark spread. So Markus was talking about the New South Wales dark spreads. In the context that you need to give three years notice to shut any capacity. What sort of production response or response from generators could you have to lower prices for assets that may be operating at negative cash margins? What can you do?

Markus Brokhof: Various, angel it's to this. One angel for sure, lowering our minimum load. That's what we are doing already passionately and we have to look at this furthermore, then also, how we run it, is the availability of all the units, the right measurements. And then also looking at the overall cost structure. I think that's a number one. Cost structure is something which we -- where we have to Coopers. I think, Damien has elaborated already on this, that we have to lower our operating costs furthermore. And, yeah -- but at the end of the day, we have also to rethink how we run all the units in particular over the day, the prices are negative and that's something which we have to look at carefully and not to anymore loose monies then during the day.

Mark Busuttil: Can I just ask just a quick follow up on this? I mean, do -- would generators be looking at changing bidding patterns? Clearly generators offering capacity at negative pricing on intending on setting the price at those negative prices, they're just purely doing it to be dispatched. And given the increasing frequency of negative pricing days, are you and other -- and your peers looking at changing the way you're bidding or offering capacity into the market.

Markus Brokhof: I did not comment on our peers. I don't know what they are intending to do. But I think for sure we will optimize our imagine, that's clear. And going forward most probably that could be a consequence.

Brett Redman : Yeah. I think, Mark, maybe just to expand a little. The point that we're trying to make, I guess, is in two parts. In one part we are seeing a market overall get to a point where the market overall, particularly in black coal generation will be struggling to cover its cash costs at today's spot prices. So, that will point to stress within the market. The second point that we would make is that AGL has been very deliberate in the generation that is bought and built over the years. And I don’t know you'll remember many presentations we might have the last number of years about sites like Macquarie and Loy Yang where we talk about them being at the bottom of the cost stack. So, a market under stress, we continue to look at the bottom of the cost stack and are in a better position. But it is a market where something will be under pressure or something will have to start to shift in the coming months and years, if it continues to operate at or beneath in an overall sense cash running costs.

Mark Busuttil: Okay. Fabulous. I've got another question, but I'll reregister. Thanks.

Brett Redman : Thanks Mark.

Chantal Travers: Next question comes from the line of Baden Moore. Go ahead, Baden.

Baden Moore: Good morning, Brett. Just a question on Crib Point. I mean, it seems to be -- continue to have some political headwinds to your progress there. Should we take it that we'd say forward negative -- further negative earnings risk, if you're unsuccessful to Crib or is there a plan B or even C, that you'd be following up with there?

Brett Redman: In a corporate sense, we're always thinking about what are the alternate places that we would go to, to source gas for our customers. The comment I've made in the past is, we're comfortable with our ability to source for our residential and small business customers. It's large C&I that will be particularly exposed if the market overall struggles to get gas into that Southern state. And again, the forecast that we see produced externally, line up with our own views that without some pressure relief mechanism, that is a market that is going into potential short in the coming years as the best straight reserves wind down. In that context, we think Crib Point is a good project. We selected it because it was where the customers -- where our customers, where the market will need the gas, down there in Victoria. And while it is clearly a long and complex approvals process that we've had to go through, what I'd like to think as it's meant that we've been given the chance to really demonstrate to the local community, that we're being thoughtful and respectful of both the local environment and the community -- the local community need, even as we're seeking to serve the bigger community need there in Victoria to supply for gas. So, I think it's a good project. As I've always done, because I believe there's a genuine market need there that will go on for a long time. And I believe that we've done the right thing in terms of how we've designed that project and how we continue to engage in the approvals process. But we are waiting respectfully for the outturn of the panel report and ultimately the local minister's conclusions at the end of that process.

Baden Moore: Thank you.

Chantal Travers: Next question comes from the line of Tom Allen. Go ahead, Tom.

Tom Allen: Thanks, Chantal. Just following the question from Mark. So, just after Markus perhaps some further comments on Bayswater power stations long-term earning sustainability because if your low cost call supply from the MacGen acquisition expires in FY25, what the step-change increase in Bayswater generation costs occur right at the same time. Obviously, the New South Wales government is underwriting gigawatts of new generation in the state. So my question is, how confident are here that cuts to sustaining CapEx, lower OpEx and reducing your minimum generation levels of Bayswater actually offset this, because it would appear that FY22 would otherwise be shaping as a key decisions on the wind. You'll need to consider the viability of continued operations at Bayswater.

Markus Brokhof: Yeah. If you look at the overall demand supply structure and with the New South Wales governmental roadmap, most probably when you look what is happening in the market, even it could happen, particularly New South Wales and some starting of investments or postponing some investments that Bayswater could even come more profitable. That's not excluded. So, we have to look the effects on this. But our overall aim is we have a long-term -- very competitive coal supplies until 2027 secured. And Bayswater may be the lowest cost generation in New South Wales. And yeah.

Brett Redman: Well, I think, Tom too, my build on that is we always talked about when we bought Macquarie that in our structural sense where it sources its coal from is structurally lower cost than where our competitors more on the coast are looking to source their coal from. So, we've always said that eventually the legacy called contracts will roll, but in the market of that day, we expect structurally they roll through prices lower than where our competitors call contracts are rolling. So it does mean a little bit like where we look at Loy Yang is sitting at the bottom of the cost stack in its spice. And we'll see Bayswater sitting at the bottom of the cost stack in its space. And so there's -- again, I come back to there's two levels to the commentary. One is saying the overall coal generation or generation market, they're starting to see some stress in cash costs versus realized price. But, AGL will continue to exist further for longer compared to our competitors because we have a structurally better cost position.

Tom Allen: Okay. Thanks, Brett and Markus. That's great. Thanks.

Chantal Travers: Next question comes from the line of Rob Koh. Go ahead, Rob.

Robert Koh: Thank you for letting me come back. I wanted to ask a question about batteries, because you continuing on the battery initiative. And I just wonder if A, you could provide us a bit more color on the use cases for those batteries? And then B, without wanting to sound negative, I'm sure Mr. Nicks is all across these. But unfortunately you just had to reclassify a whole lot of onerous contracts on wind farm deals, which were innovative at the time. I just want to ensure you've got some lessons learned in the new battery deals to ensure that in 10 years time, there's not a lot of similar kind of onerous contract, if that makes sense?

Brett Redman: Maybe Rob, let me cover the second half first and asked Markus to cover the first half. We change -- we did learn a lot from our renewables contracting over a long period of time. We were an early mover as a corporate. More than a decade ago you'll recall that we used to build sites and then put in place, very long-term contract fuel off takes and do things with development product, profits and alike. We changed our contracting strategy nearly a decade ago now, certainly more than five or six years ago now. And that's meant that the more recent contracts and the recent ways that we've been developing renewables through vehicles, like path on our power and the other arrangements we've gone into with batteries included like the Wandoan site and the Maoneng contracts that we've entered into, are all more reflective of being responsive to a market where technology costs will keep falling and we have to be ready to work our way through it. So, I think, we've learned the lessons of more than a decade ago, and you've actually seen that play out in our book in the last five or more years. But let me throw to Markus just to give a little bit of flavor about where we see the dawn of the battery age evolving.

Markus Brokhof: We were very clear that we -- with a decrease in battery costs, we would like to start a battery investment program. We wanted to build or we will build to 850 megawatts by 2024, we have chosen -- and we're very clear that we have chosen at first the location with the best grid connections at our existing terminal power sites. So it's mainly Liddell, Loy Yang and Torrens and these better sites we will develop -- we are in various stages of development. And you will see further announcement coming up when it comes to the further steps. I would also comment briefly, the battery -- it's a bit different to impact our solar and our revenues coming from arbitrage opportunities. And at the end of the day, the penetration of renewables will continue and is continuing, and we will -- from up this renewables, and we believe flexibility in the future will become a major revenue stream we get.

Brett Redman: Thanks, Markus. And look, let me just offer one last reflection too on the impairments that we took around the wind contracts. It has to test as always -- if you could go back in the time machine, would you have entered into those transactions? And the answer is yes. If you look at the whole of life, economic outcomes that we achieve through that wind development, the results and the profits that we made in the earlier parts the last few years where grain prices and black prices have been a lot higher, in some respects what we're saying is a little bit of a disconnect to the phasing of when costs and profits are booked versus the actual economic outcomes of projects. So, do I, on behalf of the company, regret those wind projects from a decade ago? No. I think they did what they set out to do. They established renewables and wind industry in Australia. They did provide good returns over the years to our shareholders. And I think for the whole of life, they're not -- absolutely knocking it out of the park returns by any means. But they are respectable on the way through. So the impairment is not good, but the whole of life economic decisions there are not bad.

Robert Koh: Yeah. Okay. Thank you very much. Appreciate it.

Chantal Travers: The next question comes from the line of Ian Myles. Go ahead, Myles.

Ian Myles: Yeah. Thanks, guys. Just one second. Can we redo more color on the [indiscernible] debt capability or given, we're seeing as you described a structural change in the earnings power of the group, how does that influence your thinking about the appropriate levels of leverage for the quarter on a sort of a go forward basis?

Brett Redman: In my mind diving to it, but in my mind, we've always talked about the -- we are now on the BAA2 Moody's credit rating is a good kind of guide to how we think about the right level of leverage. So you sort of work your way backwards from that as to what's the right level of debt, and what's the right position for your balance sheet to be. We still have plenty of balance sheet strength and solid cash flows underneath, perhaps not as strong as what they were looking like two years ago. But by no means, are we under desperate pressure to maintain -- to keep operating the business? Looking ahead, we've always dealt with comfort. The idea that there will be times when there's a surplus, if you like that we can look to return to shareholders. And if you look over the last few years, we've done two share buybacks and significantly higher dividend payout ratios and dividend paid out compared to we fold up. And there'll be times when you had really good growth opportunities and you might want to go to the market and say, look, I've got this acquisition, I've got this investment that we can make and will you support it in a capital sense. And there again, I personally led to capital raising to drive major growth and investment in the business. So, I'm not concerned in the sense that, if the question is, am I worried or are we worried that -- can we pursue our growth plan and the good quality projects that we can see that we're assessing? No, not at all. Do I think that we have a little bit less headroom than I thought we did two years ago clearly? But we're not up against the wall and I'm not worried that if we have good quality growth projects. I'd love to be here saying I've got billions of dollars that we're about to invest or buy, and that is recognized as a good place to enforce them and we may need some help. So, there's no change in that sense in the project set that we're pursuing. If they're good growth and they're good return investments, I presume that we'll either be able to fund them or our shareholders will back it in.

Ian Myles: Is that more likely than if it's -- on a previous -- a logic was you show a large transaction that you need to more likely come to market, but as focused when you had a look at that, I don't think you actually required to come to market at the time because you had enough capacity within your organization.

Brett Redman: Look, I think, the mathematical reality is two years ago when you did the headroom calcs and with the earnings and cash outlook of the business, then you came up with a high headroom numbers. And if you do the same calculations today, I mean, it's explicit in the write-off that we had to do last week. So, I'm not sitting here trying to -- again, just to make sure that no one misunderstands. I'm not sitting here trying to hint that we're about to do a full billion dollar transaction of the capital. I just want to be clear on that. But if you look at the pipeline slides of growth projects we've presented over the last couple of years, they showed the possibility of billions of dollars worth of good quality and gas spots on strategy. We've actually pulled back on some of those pipeline sites, because I said to the team I want to start to present more active decisions and actual projects that have gone through feed and getting on with it rather than the more pipeline presentations. But if we need it, I think we can get it. The headroom is not as strong as it was before. But by no means, we at death store and needing to do anything in a desperate sense, either.

Ian Myles: No, that's great. Thanks.

Brett Redman: Thanks, Ian.

Chantal Travers: The next question comes from the line of Mark Samter. Go ahead, Mark.

Mark Samter: Yeah. Hi, guys. Thanks for taking the second question. I'm not sure if this is just me thing, a simple term, it's probably the answer is yes. But the EBITDA guidance range for this year as of $250 million range, which you talked the factors $175 million closer at the NPAT level, but the NPAT guidance range is $80 million. Is there a logical reason for that -- for the difference in the ranges?

Damien Nicks: Mark, we are using -- for the first time we're putting this out, we're using a spread about 15%, so that's similar to what we're using for the NPAT range. And the reason we're doing that is what we've found over time is, big differences in NPAT versus EBITDA and EBITDA clearly is a key measure of the cash performance. And we've started -- background noise here -- and we think it's going to provide, I suppose, less noise in some of the forecasts that are out there as well, because we can provide a better overview of where this business is going.

Mark Samter: Perfect. Thanks.

Brett Redman: And Mark, my add-on is, I wouldn't overthink it. It's the first time that we put the metric out and we're probably being a slight -- little cautious as well while we're establishing a new metric out in the market.

Mark Samter: Perfect. Thanks.

Chantal Travers: The next question comes from the line of Dan butcher. Go ahead, Dan.

Daniel Butcher: Hi, everyone. Just a quick one for Brett really on the SRP CapEx cut target of $100 million. Just sort of looking at your figures, I just want to maybe you reconcile that versus reliability or a year or two ago, you sort of almost admitted that in your presence as an area to underspend on SRP CapEx and that was a fitting reliability. But now it seems like it's going the opposite direction. Can you maybe just give us some comfort about how long that's going to be going on for it and how it sort of marries up reliability going in the future?

Brett Redman: I'll hand to Markus to talk to Dan, but it is -- let me acknowledge a couple of years ago, we deliberately increased our spend because we were seeing that we had cut, I think arguably too much prior to that was impacting reliability. Now that was in a market too with very strong margins and strong prices. And so, there was a high return as well for high reliability. As we look forward, we're having to be a little bit more market responsive. And so, there's a finer edge to it. But Markus could you sort of talk to how you're thinking.

Markus Brokhof: Yeah. In general, we are also switching to different methods. Digitalization has helped us also have much more. It sends us in paychecks. So, the overall risk-based management, it's now also paying off. We have reviewed and benchmark us against international thermal power plants, because we need to be very competitive in the market. And that has led to a reduction in -- we are confident that we can lower our sustaining CapEx spend. But always, I think we said this in the beginning, safety is our upmost -- it's upmost important. So the blends, we will invest further, to run the safe operation. There's no doubt about this. But now with digitalization and a more risk based approach and better planning capabilities, we can take out further sustaining CapEx, and also reflecting on the overall wholesale market environment. Our generation will not run at full load anymore, which will have also an impact on OpEx, but also on CapEx.

Brett Redman: Look, this -- Markus has prompted a little bit. This is something Markus has built with his experience out of Europe. We are clearly -- the market conditions we're seeing now have existed for longer over there. So, he's brought with him both experienced and the connections to bring out some expert thoughts, that are helping us on the phone how can we tune a little more in response to the market conditions we're seeing.

Daniel Butcher: All right. Thanks. Probably taking out one quick one about telco growth. Can you give you an idea of in two or three years' time how many customers you'd like to see in broadband and now mobile?

Brett Redman: I think this is a chance for Christine to speak.

Daniel Butcher: Yeah. Sure.

Christine Corbett: Actually, we have said that overall in terms of customer services that we will be at 4.5 million customer services, then FY24. If you look at where we are now, we are at 4.2 million customer services. So you would say there, certainly a few hundred services will get up to reach our target.

Daniel Butcher: All right. Thank you.

Chantal Travers: The next question comes from the line of James Nevin. Go ahead, James.

James Nevin: Hi. Thank you. I was just -- I was hoping to pick up on the common [ph] event. The high levels of competition, like saw the electricity margin compressed over the last few years, and you expect that to settle at more sustainable levels in the near to medium term. And just asking if there's anything that you can kind of point to that would give you confidence in that circling up more sustainable levels. Because just side of things like there are a lot of competitors coming into the market as well with the likes of Shell recently acquiring a business and Iberdrola entering the market, potentially Tesla pushing into the electricity as well. And just point to that kind of where you confident that it will return to in a more sustainable levels.

Christine Corbett: Yes. James, it's Christine. thank you for the question. Look, I think when -- we do a deep dive into sort of gross margin in particular, in the electricity side, we see the impacts on the degradation of margin predominantly in Victoria. And that really is due to the extent of the regulatory changes that have flown through in that market. So, what has happened over the last 12 months is as those changes rolls through our book, we will expect sort of for the remainder of this financial year for that to happen, but that gives us some confidence that that is why margin compression will level out because we have been seeing the impact of the changes with both video and DMO roll through. The other thing that I would say is we have had favorable margin with respect to the customer account growth that we have had. So, we would expect, again, aligned to our ambitions with customer growth, that we will continue to see some advantages in margin with volume growth, as well as advantages in margin as we scale a multi-product strategy.

James Nevin: All right. Thank you.

Chantal Travers: We've got time for one more question. The next question comes from the line of Mark Busuttil. Go ahead, Mark.

Mark Busuttil: Hi, everyone and thanks for indulging me on just the last question. I just wanted to investigate the P&L impact of the impairments and the other charges that you announced last week when you took in the interim, particularly the write-down of the onerous contracts. So if I look at your financial statements, which you just released, you paid about $154 million in PPAs through the half, which I'm estimating costing you more than a $100 a megawatt hour. If you sort of mark-to-market to today, it would be almost half that charge. So I understand these are rolled sort of non-cash adjustments, but sort of going forward, could we make the assumption that that PPA charge would basically come down by about half? So it would save you almost $150 million pretax a year.

Damien Nicks: In our release Mark was, we expect the benefit next year, again, the net benefit. And so there's three things that play through out of all of this. There's the onerous contract that sort of unwinds if you like, you then get the impact of depreciation, which steps up as a result of the rehabilitation provision we took. And then you also get the interest and not bank interest per se, but the finance interest also rolling through. So that's why we've guided to $50 million increase in profits for next year. So there's more than just one thing rolling through those numbers.

Mark Busuttil: Okay. So, just specifically on that question then, could I make the assumption that your P&L PPA costs would half just isolating that just one, or would you rather not sort of comment to that level of granularity?

Damien Nicks: No. Look I'll not comment to that level of granularity. But at a macro level, what we're doing is effectively taking those PPA costs that where they are today to where we think the market price is.

Mark Busuttil: Okay. All right.

Brett Redman: I suspect, Mark, that there'll be -- a complex answer to a complex question with not all PPAs were written down either and there's also some sales offsets, that we've written long-term contracts. But offline, we might be able to guide it a little bit, based upon what we've published. The team can probably help out a bit.

Mark Busuttil: Excellent. Thank you very much.

Brett Redman: All right. Well, look, thanks very much everybody for taking the time. Let me sort of, again, reiterate, difficult results, which we were very cognizant of that. On behalf of shareholders, we're very focused on running the business with discipline. We're pleased that the operating things that we can control are going well. The market around us is a challenging environment and we are thinking about what to do about it. So, I think we might wrap up there. And looking forward to catching up with different people over the next coming days. And as always, Chantal and James are here to help with any questions that you might have in the meantime. Thanks very much for your time.