AGL Energy Limited (AGL) Earnings Call Transcript & Summary

Good morning, everyone. This is Brett Redman speaking. Thanks for joining us for the webcast of AGL's full year results for financial year 2020. Joining me in today's presentation will be our Chief Customer Officer, Christine Corbett; our Chief Operating Officer, Markus Brokhof; and our CFO, Damien Nicks. We look forward to taking your questions at the end of the presentation. I will begin by discussing the highlights of the result and providing a business update. The result that we're announcing today is consistent with the guidance we provided at the start of the year and our continued strong financial position. Our operating performance reflects the strength, stability and sustainability of AGL during a period of unprecedented upheaval across our markets and in the communities that we serve. Our focus on executing our strategy with our priorities of growth, transformation and social license has guided us through the COVID-19 pandemic, summer bushfires and preceding drought. We are growing our customer base at the same time as we support customers through challenging times and deliver improved service and simplified products through increased digitization. We now deliver more than 3.95 million services to customers, and we have experienced a step change in customer feedback via mechanisms such as Net Promoter Score. Our energy portfolio has delivered resilient supply, maintained strong generation despite the major unplanned outage at AGL Loy Yang in the first half and the operating uncertainty created by COVID-19. This is testament to the growing diversity and flexibility of our portfolio, including the contribution from our new wind and gas generation assets. We are delivering on our strategic priorities. Our focus on growth resulted in the acquisitions of Perth Energy, which is performing above expectations; and Southern Phone Company, which forms the foundation of AGL's future broadband and phone offerings. We have a growing portfolio of grid-scale battery projects under feasibility or development, having signed up key projects in New South Wales and Queensland during the year, and transformation of the business is ongoing. We have reinvested $135 million of recurring cost savings from system investment and other efficiency programs over the past 2 years, and we expect to reinvest a further $100 million of recurring efficiencies this year. In June, we released our refreshed climate statement comprising 5 key commitments, including for every product to be available carbon neutral by the end of the financial year 2021. We continue to reward shareholders through capital management. There has been no change to our dividend policy amid the COVID-19 uncertainty, and we have undertaken the share buyback this year in keeping with our commitment to return excess liquidity to shareholders. Today, we're announcing a special dividend program to augment ordinary dividends up to an effective payout ratio of 100% of underlying profit after tax. This reflects the strength of our cash flow outlook and subject, as always, to the liquidity being available after funding potential growth programs. So while our guidance for financial year 2021 for underlying profit after tax to be in the range of $560 million to $660 million reflects a material decline, we have entered the new financial year with confidence. Long-standing market and operating headwinds have been well flagged in the past. The impact of COVID-19 has been to bring these headwinds forward a lot faster as wholesale prices have fallen, while also bringing new cost headwinds from credit losses associated with customer hardship. However, our cash flow and financial position remain strong, and we have material headroom to invest in the business and support growth and capital management initiatives. Let me now turn to the 3 core operational metrics on which we report: safety, customer advocacy and employee engagement. The total injury frequency rate per million hours worked decreased to 3.3 for employees and contractors combined in FY '20. While there is always more that we can do, our safety culture is improving. Injury severity continues to lessen, and our near-miss reporting continues to get better. We have pleasing results to report with regard to our customers and our people. Net Promoter Score has increased more than 13 points from a year ago and has moved into positive territory for the first time. On the employee front, we have also seen a positive trend. Our latest survey shows engagement increased 5 percentage points year-on-year. Now turning to our financial result. In contrast to FY '19, statutory profit after tax was boosted by the mark-to-market of hedging instruments as wholesale prices fell. Underlying profit after tax was $816 million, down 22%. The challenges we faced this year have been well flagged: the major unplanned outage at AGL Loy Yang, lower wholesale energy prices and higher depreciation expense. So in the context of the year's unanticipated disruptions, not least $38 million of costs related to COVID-19, I'm proud of the team's efforts to deliver this result within the guidance range that we set out last August. Our underlying EBITDA result of $2.070 billion was down 9% and is a good proxy for the relative strength of our cash flow compared to our accounting profit. Indeed, net cash provided by operating activities increased 35%, growth on the prior year, including a strong working capital contribution from margin receipts. Total dividends declared during the year were $0.98 per share. Return on equity was a solid 10%. I would now like to touch on our COVID-19 response in more detail. Across our key operational focus areas of safety, customers and our people, our response has been decisive and consistent with our purpose of Progress for Life and with our values, not least taking care in all our actions. We put in place comprehensive measures early on to ensure our people could continue to serve our customers and ensure reliable supply of energy. We are well positioned to continue to cope and adapt as the health and economic crisis evolves. Underpinning all of this has been the robustness of our financial position. So now let's turn to strategy driven by our objectives of growth, transformation and social license. Market and economic conditions may have grown more challenging, but the imperative to change as the energy industry transitions from old models is not going away. Effective 1 July 2020, we formed Integrated Energy, bringing together wholesale markets and group operations as one, alongside our Customer Markets business. I'm confident this new operating model will enable delivery of our strategy, with customer needs informing the services we supply and our integrated portfolio providing competitive advantage. We are well on the way delivering on the transition. Customer Markets is moving from being a leader in electricity and gas retailing-only to becoming a leader in the provision of multiple essential services, including broadband and the delivery of other relevant services. Integrated Energy is about moving from a carbon-intensive large asset portfolio with a long exposure to energy commodity markets today towards a carbon-neutral portfolio of more diverse, flexible and decentralized assets balanced to customer demand. My next slide details some of the targets that we are now setting ourselves. We feel confident setting these targets despite the ongoing market uncertainty because of the underlying stability of the business. By the FY '24 results, we are targeting services to customers, including broadband and phone services, of $4.5 million, and we expect to be providing each customer with 1.6 services compared with 1.4 today. That translates to 400,000 of our customers today buying another service from AGL. We also expect 65% of these services to be digitally active compared with 37% today. We want our reputation to continue to grow, so we are targeting a Reptrak score above 70 compared with 68 today. In the supply portfolio, we are targeting 850 megawatts of grid-scale batteries installed, managed or under development compared with 30 megawatts today and a further 350 megawatts of distributed and demand response assets under AGL's orchestration compared with 72 megawatts today. Consistent with our climate statement, our aspiration is for 34% of AGL's electricity capacity to come from renewables and clean storage compared with 22% today, and our goal is 20% of group revenue from clean energy or carbon-neutral products compared with 11% today. In both cases, the target reflects a max vesting outcome for our new long-term plan incentive metrics. These targets and metrics were integral to the launch of our carbon statement (sic) [ Climate Statement ] in June, which was a major milestone for the year. The statement is grounded in our belief that the energy transition will be led by 3 things: customer demand, how communities act and how technologies evolve. It's a framework to guide our actions, setting us on the path to achieving net zero emissions by 2050. On this slide, you can see our 5 commitments on carbon-neutral products, supporting voluntary carbon markets, investing in electricity supply, responsible transition and transparency. I'll finish my opening remarks with capital management. Today's announcement of a final dividend of $0.51 per share takes total dividends declared in FY '20 to $0.98, 80% franked. This is consistent with our dividend policy payout ratio of 75% of underlying profit after tax. Since the introduction of that policy, there has been a step change in the quantum of capital AGL has returned to shareholders, augmented by $1.1 billion of combined share buyback activity in FY '17 and FY '20. On average, that means we have returned about 40% of EBITDA to shareholders through dividends and buybacks since FY '17. Today's announcement of a special dividend program means we intend to declare a special dividend of an additional 25% of underlying profit after tax in FY '21 and '22. This would take the effective payout ratio to 100% and help offset the impact of the removal of franking. The temporary reduction in franking will enable us to consume tax losses as efficiently as possible and return to paying franked dividends sooner. All dividends and other capital management, as always, are subject to the ongoing funding and liquidity requirements of the business. I'll now hand over to Christine Corbett, our Chief Customer Officer, to provide an update on the Customer Markets business.

Thank you, Brett, and good morning, everyone. In a year unlike any other, I'm proud to say our support for our customers has been recognized in positive customer advocacy and significant growth in our customer base. At the same time, we have delivered improved platforms for customer experience and lower costs, while establishing the foundation to become Australia's leading multiproduct retailer of essential services. In the next 3 slides, I'll highlight the significant progress we've made in the key customer metrics that we focus on for long-term value, the benefits we are deriving from the investment we've made in our digital customer platforms and the range of products and services we have launched, providing our customers with simplicity, connectivity and value as we transition to a new energy market. One of the key metrics we look at is Net Promoter Score, or NPS, which, as Brett has said, is in positive territory for the first time. We are seeing the impact of this improved performance reflected in both the growth in our customer numbers and reduction in customer churn. We now provide almost 3.8 million energy services to customers. Over the past 2 consecutive years, we've increased that by over 140,000, of which 78,000 were in the last 12 months. This is against a backdrop of both fierce competition and regulated price changes. Adding the 168,000 broadband and phone services through Southern Phone, we now provide a total of more than 3.95 million services to customers. Across Australia, we are connecting 28% of households with essential services. We feel confident about growing our customer base further, consistent with the target of 4.5 million services by FY '24. Our churn rate is at 14.3%, the lowest since 2014, and we have maintained a healthy spread to the rest of the market. We have had good performance in our large business customer portfolio. Strong contracting and the acquisition of Perth Energy have driven growth for the first time since 2012 despite the impact of COVID-19 on demand. We are rebuilding electricity sales to underpin our generation portfolio in what has been a very competitive market, expanding further into Western Australia with our acquisition of Perth Energy and focusing on business energy solutions, deepening our relationship with our customers by offering services that reduce energy usage and environmental impact. The investment we have put into our technology and digital systems has contributed to our customer growth. It has improved the way we interact with customers, enabled us to respond quickly to market changes, to offer new products and to deliver operational cost savings. We can see the benefits of this investment in many areas, 3 of which are shown on this slide. Ombudsman complaints have fallen 37%. In particular, we are seeing a reduction in bill complaints, reflecting our customers' increasing oversight of usage and understanding of their bills. The increasing take-up of digital bills, together with the digitization of the move and new connection process, improved digital payment capabilities and messaging platforms, has improved the customer experience and reduced operational costs. Call volumes are down 20% since 2017 and 39% in the last 12 months as customers increasingly utilize the options we provide online. This allows our call center team to focus on issues that need human care. Our underlying net operating costs per customer service, as shown in this slide, have declined 8% year-on-year driven by our investment in the Customer Experience Transformation program and our ongoing focus on simplification and digitization. We anticipate further cost efficiencies over the next few years as we continue to invest in automation, optimizing processes and digital adoption. It is important to note that we are pursuing a growth strategy, balancing growth as we invest to expand our multiproduct offerings to reach more households and businesses with increased efficiency as we scale. Our focus on customers is core, and our investment in digitalization is the foundation for establishing AGL as a leading multiproduct retailer for the connected customer. We're working across 3 key areas: simplicity, connected essentials and the energy market transition. It begins with simplification. We make it easy for customers to see value in our products and trust us to have the essentials covered. Over the past 12 months, 30% of our customer portfolio has moved to our essentials range, offering simple, low rate-based products. Our digital capability enables us to move beyond an energy-only offering to a multiproduct proposition, enabling connectivity of essential services with digital and smart technology. Our customers are increasingly connected, and this provides opportunity to streamline how we service, inform and interact with them. With the acquisition of Southern Phone last December, we added phone and data services. We are also expanding our product offering to our large business customers, finding unique energy solutions that are both cost-effective and energy efficient. We are responding to our customers' desire to participate in the transition of the energy market to lower carbon. We were the first to establish a retail-led virtual power plant, and we launched a Bring Your Own Battery program last year. Our demand response program, Peak Energy Rewards, will have the capacity to scale from 20,000 customers to 1 million customers over the coming year. We have launched our carbon-neutral offer for our electricity plans, and will have a carbon-neutral offer available on all products by the end of FY '21. We have bold ambitions to make a tangible impact in the lives of our customers with positive progress already realized, centered on customer growth, digitization and building trust and simplicity.

Thanks, Christine, and good morning, everyone. It's a pleasure to be here with you virtually. I'm Markus Brokhof, AGL's Chief Operating Officer, and I lead the newly created Integrated Energy division. I strongly believe this structure will allow AGL to make more value-based decisions through closer integration of trading, origination, portfolio and operations. It has been an interesting start for me as I arrived in the second half of March, shortly before the international borders closed. In the brief period where government regulation has allowed, I have visited some of our generation sites. I have been pleased to see our people adapt to the requirements of COVID-19 and to continue their essential work in a safe manner, and I look forward to visiting more sites once it is safe to do so. Today, there are 3 key messages I would like to highlight. Firstly, AGL's Integrated Energy business had a robust financial year '20 performance. It was a year of economic and social disruption, and yet we have been able to deftly manage through. Secondly, we have seen significant disruption in wholesale markets and a declining outlook for commodity pricing. Finally, AGL is being proactive in the face of continued headwinds and seeking growth by developing flexible generation assets, investing in offtakes, balancing our sustaining capital expenditure and building our origination and trading capabilities. On this page, you see AGL's monthly generation output over the year. As Brett talked about, AGL has acted quickly to protect our people and sites during COVID-19. By doing so, we ensured the lights stayed on and gas kept flowing, and as a result, our generation output was unchanged year-on-year. We believe this is quite an achievement, given the challenging conditions, not just from COVID-19, but also the bushfires and the Loy Yang Unit 2 outage. While that outage reduced AGL Loy Yang's output in the first half of the financial year, AGL achieved record generation output during this time. This is, among other things, due to our investments in coal handling efficiency at AGL Macquarie. The efficiency resulted in increased generation output at Bayswater and Liddell and offset the lost generation from Loy Yang. Other investments that supported AGL's robust financial year '20 performance include Coopers Gap coming online and Barker Inlet Power Station, which progressed to practical completion in June 2020. BIPS, as we call it, is the first new investment in dispatchable and highly flexible capacity in the NEM in recent years, 12 gas engines with 18 megawatts each. Beyond efficiency and new investments, we have also had to defer planned maintenance due to COVID-19 restrictions. We are undergoing significant planning as to how to deliver necessary maintenance to our fleet in financial year '21 given ongoing social distancing and travel restrictions. While we have had success in holding our generation output, on the pricing side, we are seeing decline across LGCs, electricity and gas spot and forward prices. It is worth noting that AGL has been active in managing exposure across these prices, with the majority of our active financial year '21 hedges in place before the COVID-19 disruption hit wholesale prices in early calendar year 2020. For LGCs, some increasing renewable generation drove a declining price at the start of the year, but prices have recovered somewhat since May. This continues to be an area of focus for AGL as we execute on our climate commitments. On the electricity side, the forward curve declined rapidly at the second half of financial year '20 as a result of increased supply due to deferred outages, new generation and low short-term gas and coal costs. Prices have started to pick up in southern states as maintenance schedules resume somewhat and as temperatures have declined. The gas spot price declined through financial year '20 as excess market supply from the northern states continued with lower domestic demand and LNG exports. We still expect gas supply constraints to hit in the early to mid-2020s. As a result, we continue to pursue both the Crib Point import project and competitive recontracting of gas supply to ensure adequate, flexible supply with trading exposure to international LNG pricing. Across both gas and electricity, we see prices being driven by short-term issues that reflect current conditions. While the short-term and mid-term price is likely to remain depressed due to macroeconomic conditions, the COVID-19 deferral of outages across the NEM will need to be caught up by either increased planned or unplanned outages in the future, putting further upward pressures on prices and volatility. We believe investment in new flexible capacity is required if we take a longer-term view. This chart looks at the predicted trajectory of our core generation output up to 2030. You can see a significant decrease in the mid-2020s as Liddell and Torrens A retire, and you would see further declines in the 2030s and 2040s if we were to extrapolate further. Following the closure of Liddell, our generation position will no longer be in excess of our customer demand. Although energy prices are lower, we still see an opportunity to invest as the composition of the portfolio shifts away from coal towards the new firmed renewable generation the market will need. AGL's strategy is to optimize dispatchable generation, support investment in firmed renewables and continue to invest in the accelerating emergence of batteries and other energy storage technologies. In the call-out box on the right, you can see some of the projects we are working on and the ambitious targets we have set ourselves for financial year '24. In fact, we are currently inviting tenders to procure integrated battery systems, which could satisfy the entire grid-scale storage target. We believe battery technology is now at a level that allows AGL to lead in Australia's transition to a smarter and more efficient energy future. As we pursue our strategy to capture new opportunities from the energy transition, we will continue to operate our existing assets as efficiently as possible while balancing investments across sustaining existing assets and in new generation capacity. Now we look at the gas side of AGL's business, which has been a core source of value for AGL for many years. Through the last decade, AGL has benefited from long-term legacy supply contracts signed when gas was at much lower prices. These contracts are now maturing and need to be replaced at market prices in a tight market with few supply options. Hence, our gas supply costs are increasing. Our oldest supply contracts signed pre-2010 are represented by the dark blue on this chart, while those signed between financial year '10 and financial year '15 are represented by the light blue. We expect the maturation of these long-term contracts to have a material impact on wholesale gas margins in financial year '21. And we continue to see gas as a core part of AGL's portfolio, particularly as a transition fuel to firm renewables in the medium term. AGL's strategy in wholesale gas is to benefit customers by mitigating supply uncertainty and providing optionality. The hatched area in the chart represents a significant investment opportunity, which AGL plans to take advantage of with our Crib Point project and competitive recontracting, while, at the same time, our gas storage positions increase our flexibility. That finishes my overview on the performance of our Integrated Energy business. And I now hand over to Damien to take you through our financials.

Thanks, Markus, and good morning all. I'll start by taking you through group underlying profit in more detail. The $224 million reduction in profit was consistent with the guidance we gave in August. In the context of the unforeseen pressures from COVID-19 during the year, this was a solid operational and financial performance. Looking at the chart from left to right, as forecast, underlying Customer Markets margin was down slightly as a result of lower market prices. The acquisitions of Perth Energy and Southern Phone Company contributed $31 million to margin. In now what is Integrated Energy, electricity margins held up extremely well when taking into account the impact of the extended unplanned outage at Loy Yang Unit 2. As we said at the half year, strong generation elsewhere in the portfolio largely made up for the loss of the unit, while our hedging strategy protected us from the full downside of falls in market prices. In wholesale gas, the major driver of reduced margin was lower volumes under long-running contracts. The fall in eco markets margin largely reflected lower market prices for large-scale generation certificates. Depreciation expense was up $128 million before tax, reflecting ongoing investment in our thermal fleet as depreciation schedules shorten, the completion of the $295 million Barker Inlet project and a full year of depreciation on almost $500 million of software platform investments in recent years. Total depreciation expense was a little higher than we forecast at the Investor Day as a result of accelerated depreciation in the thermal asset fleet. The impact on operating costs, excluding depreciation and amortization of $59 million, was driven primarily by COVID-19-related impacts, as I'll cover in more detail on the next slide. The reduction in tax expense largely reflected the fall in profit, while net finance costs continue to be managed tightly. Looking at operating expenditure in more detail. We're showing here the change over the past 2 years with a bridge from FY '18 to FY '19 and then to FY '20. In total, we've delivered $135 million of recurring savings across the business, $78 million in FY '19 and $57 million in FY '20. These savings have come from 2 major software investments, the Customer Experience Transformation and Enterprise Resource Planning upgrade programs as well as other efficiencies. In Christine's presentation, you heard about the connected customer. 1 million of the services we provide to energy customers are now on our simplified Essentials product and the increase we have seen in customers choosing digital channels for self-service and assistance. We are seeing these efficiencies translate into sustainable savings and a significant improvement in the positive customer sentiment. There have also been one-off savings of $75 million over the past 2 years, arising primarily from asset sales and business simplification. Delivery of these efficiencies has enabled us to reinvest in the business. This has included the plant availability investment we first identified back in February 2019, the growth in our customer numbers, acquired businesses, our multiproduct retailing strategy, decentralized energy and our ongoing focus on developing energy supply and storage projects. We've then seen sharp increases in insurance costs for our aging thermal assets and costs associated with the heightened regulatory environment. Had it not been for $38 million of increased costs over FY '20 from COVID-related impacts, $20 million from increased net bad debt expense and $18 million from increased on-site operating costs, we would be reporting flat costs from FY '18 to FY '20. Noting the uncertainty in relation to COVID-19, AGL expects FY '21 operating costs, excluding depreciation and amortization, to be broadly flat on FY '20. Approximately $100 million of recurring efficiencies are expected to offset investment in growth and transformation and increases in insurance, regulatory and compliance costs. This sets us up to start driving the total cost base down on a sustainable basis in future years. I want to take a moment now to look at bad debts in some more detail. As in the current environment, this represents a read-through to the broader economic conditions. The chart on this slide goes back to FY '14 and shows that total net bad expense has been trending down slightly as a percentage of revenue. The blue-colored bars average around $80 million, with a spike in FY '18 ultimately addressed by the $33 million affordability package we announced to forgive hardship debt last year. That affordability program as well as the additional $20 million of expense taken in FY '20 are called out separately on the chart for the purposes of comparison. Of course, we expect net bad debt expense to increase further in FY '21 as economic conditions continue to deteriorate and more customers face hardship. We had 38,500 energy services to customers registered for our COVID-19 customer support program, 23% of which had paid their bills in full. This is in addition to the 40,000 energy services to customers across 28,000 customers that are part of our ongoing Staying Connected hardship support program. Our current guidance assumes the additional net bad debt expense in FY '21 will be $40 million. But of course, this is highly uncertain, and the actual number could be higher or lower depending on the economic conditions and the length and the breadth of the pandemic. Let's now turn to cash flow, which remains a positive feature of AGL's performance. Lower wholesale electricity prices resulted in a positive working capital inflow from margin receipts because of the net sold position we have in futures markets. Although this price trend is not positive for AGL's longer-term profitability, it provides a short-term benefit to liquidity. Movement in other working capital items also improved year-on-year, reflecting reduced inventory growth at AGL Macquarie as a result of our efforts to deliver coal supply chain efficiencies and positive timing impacts between the periods relating to the purchase and surrender of green certificates. Net cash provided by operating activities was $2.156 billion for the year, an increase of $557 million. Cash conversion, excluding margin calls, was very close to 100% of EBITDA and consistent with previous years. This strength and consistency in cash generation, combined with a lower outlook for capital expenditure in the short term, underpins our confidence in the financial strength of the business even in a challenging earnings environment. Our credit metrics and borrowing profile also remain a strength. We have material headroom under our Baa2 credit rating and all our covenants, with no major refinancing due until November 2021 and more than $1 billion in cash and undrawn debt available. We do not intend to refinance the syndicated debt facility maturing this September as it is undrawn. We are in the process of replacing some of our more expensive debt facilities, which will have an impact on our net finance costs this financial year but deliver a positive net present value over the remaining life of that debt. The bond debt refinancing we have due in November 2021 is our Australian medium-term notes. We intend to refinance that facility and potentially some of the remaining longer-dated bank debt next calendar year to take advantage of the strong support and the longer tenor available in bond markets. I'd like to finish by reviewing our performance relative to the 4 refreshed capital allocation principles I set out at the Investor Day last year. Firstly, to run the existing business for optimal performance and value. Sustaining CapEx is expected to be $600 million in FY '21 compared with $570 million in FY '20 as programs deferred due to COVID-19 are undertaken. We are continually assessing the optimal balance between investment and return in our core assets, in particular, in the context of the more challenging energy price outlook arising from the COVID-19 crisis. The recurring cost efficiencies we are delivering and will continue to deliver provide a strong foundation for us to drive down our total cost base over time. Our second principle is to maintain a strong balance sheet and dividend policy. As I've covered today, our headroom under our Baa2 credit rating means we can focus on the ongoing optimization of our borrowing to extend tenor and to further reduce refinancing risk. We are not only maintaining our dividend policy amid uncertain times by augmenting with a special dividend program. Our third principle is to invest in growth, which we continue to do with discipline with a hurdle rate 300 basis points above our weighted average cost of capital. The shorter-term outlook is for reduced capital expenditure after several major projects have come to an end, but we continue to seek out new opportunities. The fourth principle is to return excess liquidity to shareholders. Our on-market share buyback announced in August 2019 has returned over $620 million to shareholders and is on track for completion shortly. The special dividend program we've announced today will further augment shareholder returns during this period of excess liquidity. I'll now hand back to Brett.

Thanks, Damien. I want to start my closing remarks by reflecting on AGL's strengths. It is a deeply challenging and uncertain time for many in our community, but our strategic focus and financial strength create a solid foundation to withstand the current health and economic crisis. For AGL, while earnings pressures are increasing, our cash flow remains strong, and we are executing our strategy with discipline. There remain considerable opportunities to invest in growth as the energy sector transforms. We are growing the breadth and scale of our customer base and becoming a provider of multiple essential services at the same time as we deliver a simpler, more digitized experience for customers. We expect that to translate to higher revenue and more engaged, satisfied customers over time. We are transforming our energy supply portfolio amid severe market headwinds to deliver greater decarbonization and decentralization, consistent with evolving customer, community and technology drivers. We expect that to translate to a more flexible portfolio position as the market continues to evolve. Our resilient financial position, diverse asset base and the strong values of our people are supporting our ability to deliver essential services for customers and the community at large during ongoing challenging times. And our principled approach to capital management is enabling us to continue to pay dividends, complete our current share buyback and announce our intention to augment ordinary dividends with our special dividend program over FY '21 and '22. The specifics of our FY '21 guidance reflect increasing market and operating headwinds to margin as a result of COVID-19 as well as the broader impacts of the pandemic on our costs. Our guidance range is for underlying profit after tax of $560 million to $660 million. That 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. The key operating and market headwinds we are facing, and which have accelerated as a result of COVID-19, are as follows: we expect our wholesale gas gross margin to be approximately $150 million lower as legacy supply contracts mature, driving supply costs higher, and lower year-on-year market prices impact upon revenue. We expect wholesale electricity gross margin also to be approximately $150 million lower as sharply declining prices for energy and green certificates translate to lower customer revenue. We also anticipate further increases in depreciation expense from recent investment in plant, systems and growth. The additional COVID-19-related cost challenges we are facing is a higher expected credit loss arising from an increase in customer hardship. We currently forecast this at $40 million, but this is heavily subject to the length and severity of the economic slowdown. There is also potential for ongoing cost impacts at sites to maintain safe and uninterrupted access for employees and contractors to ensure reliable supply of energy if lockdowns worsen. Noting the uncertainty related to COVID-19, we expect to hold FY '21 operating costs, excluding depreciation and amortization, broadly flat on FY '20. We expect to deliver approximately $100 million of recurring efficiencies to offset ongoing investment in growth and transformation as well as increases in insurance, regulatory and compliance costs. Cash flow and liquidity remain strong, supporting our resilient financial position, and the special dividend program is anticipated to take our effective dividend payout ratio to 100% of underlying profit after tax. All our guidance is subject to ongoing uncertainty in relation to the economic impacts of COVID-19 as well as normal variability in trading conditions. Thank you, and we'll now take questions.

Thank you, Brett. [Operator Instructions] Our first question comes from the line of Rob Koh.

Jeez, I've got so many questions, but let me ask, I guess, a question about the target for 20% revenue from carbon neutral in FY '24. I guess the experience with targets shows that circumstances can change. Just wondering, how are you taking into account in that target, I guess, the decline of revenues from generation and price moves?

Rob, I might throw this question to Damien. But just noting that, that's one of the LTIP targets and would represent top end of our range, but certainly something we think is achievable. Damien, do you want to give a little bit of detail?

Sure, Brett. And thanks, Rob. Good morning. Look, when we think about that particular target, that target is all about how we grow our carbon-neutral products. So the products we've just put out into the market, that's where that growth will come from. You're right, it is over our total revenue base as we think about out into the future. Our forecast into next year also, obviously, has that downturn in revenues, and that's how we've considered the overall target. So what you won't see from that is us getting a, if you like, a benefit from wholesale going down materially. That's been baked in as we thought about the overall forecast. So it's all about the carbon-neutral products and those that we've released to the market.

Thank you, Rob. Our next question comes from the line of James Byrne.

I just wanted to ask about Slide 20. So that's the gas book repricing. And as I eyeball the chart here, on the volume of gas in FY '20, that's through pricing in FY '21, and then look again at what goes into FY '22, it looks like a comparable volume, albeit the gas contract signs pre-FY '10 don't decline quite as much into FY '22. So I guess the question is if I then think about -- and I know that you typically won't provide guidance beyond the next financial year, but should we assume a similar order of magnitude of impact to the gas book repricing in FY '22 as what we've seen now for FY '21?

I think, James, and I'll invite Markus to comment as well, we put this version of the gas slide in to try and help people see as the book turns over in an aging sense, and you can ensure it -- from it, given the -- based on age of contracts, where those prices might have been struck. People can see the turnover and maturity of contract. And while what you referred is some of the, I guess, medium contracts are rolling off and nearer contracts rolling on, there's also a growing wedge of uncontracted as well, which if the current prices sort of sit there and are available for contract, would help average down a little bit as well. But Markus, did you want to add any comment to that?

Hello, James. Yes, the one side is on our procurement costs, which are increasing. Now we are doing the utmost efforts to recontract now also on the lower level. But in addition, we are investing also heavily in flexibility. Because as you can imagine, with the installation of renewable energy, we have -- we are providing more and more flexibility into the market with our gas-fired power station. And this increased flexibility has a cost attached to it. So it's mainly the cost of haulage and the cost of storage. And this is another driver, but also the overall -- the portfolio costs are increasing.

Thanks, James. The next question comes from the line of Tom Allen.

Just with regard to management's decision to return excess liquidity to shareholders via the special dividends over '21 and '22, while this might soften the impact of removing franking, it also confirms the growth constraints you're facing over the next few years. Your two biggest growth projects, Crib Point LNG import terminal and Newcastle peaking gas, feature fairly lightly in the result presentation. With the market now providing a price signal to support Newcastle project and ongoing environmental concerns at Crib Point, can you provide an update on your expected timing of an FID for both projects?

So Tom, on those -- and because always, when you put together an investor pack, there's 1,000 things you can put in, the space for '20. So I wouldn't read anything into it that we haven't got as much material on Crib Point and Newcastle as we might have had in past presentations. It was more noting where I think a lot of the discussion will go. We tried to make sure we are covering some of the more outlook positions and things like the gas book. Crib Point is in a delicate place as it goes through its approvals process. Nothing has changed in the sense that there is a real market need in Victoria to find more gas. And so customers in the next few years down there are going to need more gas as best rate runs down. So the fundamentals that underpin that project are unchanged. But I note that it's in the middle of its public exhibition process, which has been extended because of COVID challenges. And right now, I'd like to sit respectfully out of the conversation to allow the public to comment on our proposal. But I think we've provided some good information. And I personally believe, because of that market need, it is a project that will ultimately get over the line. But I think it's important now that the public has a chance to have their say on that project. On Newcastle, we continue to progress it to a point where we can consider FID. So we're working through a series of calls for -- I can't remember the right phrase, the calls for tender there in terms of the equipment to make sure that we've got the best cost position for it. And then we're looking for what is the right balance of supply and demand to get that project through. I think it is a project that is needed within the market as well as we think about the broad suite of transition, and that includes the closure of Liddell, the increase in renewables in the market and, therefore, a need for the market to have more firming in it. Firming will come from gas, battery and pumped hydro. The portfolio of the future for AGL will have -- will heavily feature firming capability. We've called that out a lot over the last couple of years, so we remain focused on individual projects. We'll keep jockeying for position as to how sooner or how later they come through. But again, I think over the next 12 months, we'll see Newcastle reach a point where it is a serious proposition. Again, we're steering at the market fundamentals. But over the long haul, I think it is needed within the market, so we are seriously considering it.

Okay. I think that's clear. Your answer there just referred to the closure of Liddell. Just extending the same question, can you share an update on the commercial options available to AGL regarding the size of the Liddell power station?

So Liddell remains on track to go through its public timetable of closure, so partly in '22 and finally at the beginning of cal '23. We're continuing to look at other ways of using the site, and one of the things we're looking at is battery on that site, given the transmission infrastructure there. It's a good site for battery. And so we're actively working through the development processes to prepare the way to put battery there, even as we're studying the battery economics. It's not a site that naturally suits gas, simply because there's no big gas pipelines around it. So I think what you'll find is we'll be leaning into battery storage for the site even as we continue to run Bayswater on that site for a long time to come.

Thank you, Tom. Next question comes from the line of Mark Samter.

Just a quick question on the balance sheet. And you talked about significant headroom, which is clearly there at the moment. But I'm just curious how you think about how much of that headroom you're willing to use because I guess -- and I don't want to put words in your mouth, but when we look at all the headwinds you're highlighting for FY '21, there's a reasonably strong argument the majority of those persist through FY '22, and then you've got Liddell closure, et cetera. So how much -- and obviously, therefore, those credit metrics probably worsen as we roll through time and earnings deteriorate further. How much do you think -- can you quantify what you think is significant for use at the moment?

So Mark, I wasn't quite sure at the end there, the exact question. But look, we -- and I'll let Damien jump in as well. By any measure, we see a significant headroom in the balance sheet for either growth or capital management. Now bear in mind, if we find the right growth opportunities, then they will bring their own earnings to the table as well. There is no doubt that is -- if we see a lower profit number, that will put a little bit of pressure on some of these metrics. But the look-through and one of the things we tried to call out today is to look at operating cash flow as well. And there, you see a more robust story, if you like, hiding underneath what is a harder story when it comes to profit. And at the end of the day, cash is king, and that gives us the ongoing confidence that, one, if we can find the right growth opportunities, we've got the headroom there. And I believe that we've got a track record of discipline to pursue it. And then secondly, if we don't find the good growth opportunities, I'd like to think we're also proving that we'll meet what we've said, which is return excess liquidity to shareholders as appropriate over time through both buybacks and now the special dividend. But Damien, did you want to add anything to that?

Well, I think you've largely covered it, Brett. Look, I think just to reinforce that point around EBITDA as a proxy for cash as we look out into the future years. Mark, you're dead right. I mean, look, as profitability comes, it is going to reduce. But that EBITDA and that cash measure is strong. And as part of, obviously, when we've assessed and when we've looked at the impact of COVID, and the scenarios around COVID, we've looked out in the future, and our business continues to be strong. And so exactly to Brett's point, we have the flexibility there today, and I think you will just continue to see that flexibility into the future.

Thanks, Mark. And the next question comes from the line of Ian Myles.

Yes. Just -- got a simple question. The consumer business or -- yes, the consumer side, second half 2020, the profitability of that business literally collapsed. I think in the first half, you indicated an EBIT of $138 million; second half, full year of $186 million. And when I sort of think about you've got a $20 million charge for COVID in there, what else has gone or changed drastically over the last 6 months to see that step down? And is that an issue going forward?

I might ask Christine to pick that up, maybe with Damien backing you up.

Look, why don't I take the first thing, Christine? You can jump in, if you like. Thanks, Myles. Look, I saw your note on that one. Some of it's got to do with both the affordability rolling back in H1 from this year versus last year and also, therefore, you're right, the bad debt into the second half. I think the way, though, is still to look at customer. I think we've said this before, is look at it on a full year basis and then, I think, apply across that where you see benefits of, if you like, SPC and some of Perth rolling into those numbers as well. Does that make sense?

Sort of.

Look at it on a full year basis, I think, because, as I'm saying, affordability in 1/2 of the prior year, and then you've got -- in this second half of H2 this year, you've got the impact of the net bad debt expense rolling through there as well. But look at it on a full year basis.

Yes. I think, Ian, to -- just to build on that, and we've seen this in past years as well, both the lumpy bookings that we've had to make for bad debt over the last year or 2 with COVID this year, and at the beginning of last year, we booked an extra -- I'm trying to remember the number now, $40-odd million from memory of hardship debt. The other thing that goes on every time we try and explain half year splits in retail is the timing of price change. So transfer pricing is steady for the whole year. Price changes then happen at different points of the year. And that tends to throw out the half year splits in retail each year and make the answer messier, I've found in past years as well.

But didn't you change transfer pricing in the first -- like in the first half to actually be favorable to consumer and actually added profitability back in away from the wholesale? Does that reverse in the second half?

What's always going on is the transfer price, which is reset on 1 July every year right across the board. It picks up in that moment. And bearing in mind, it's essentially struck in April-May with all the processes we run. In that moment, what we see is the wholesale component for a cost stack for a retail customer. And then inevitably, every year, what you get into the detail of it is the timing differences of what then becomes a fixed cost push between the businesses to a moving market price, depending on how you have to trade in the market. And as I say, each year, you particularly see it in Victoria because we set the transfer price, and then on 1 July -- sorry, 1 January, Vic puts its price changes through. You're often finding little disconnects half-on-half even as the full year makes more sense.

Okay. If we look at it as a whole year, if we sort of take away the sort of the one-offs, are we seeing a trend that you can actually getting profitably back into that consumer business? Or is it really the regulatory pressure on the pricing is making you way -- very hard to stay constant?

I think -- I guess from where I sit and where I can see, obviously, all the details, it's behind a lot of these things, I see the improvement in margin that's coming from the improvement in customer numbers. That is definitely coming through, even though it can get lost in the noise of transfer prices and the rest that's there. I also think with the building focus on more services per customer, and just to point out, we've tried to come up with a word that can amalgamate energy accounts and broadband services, and we've just picked services, for lack of a better word. So more services per customer as well will also drive more margin into the business. So laying aside the noise of transfer pricing, I see a more robust future for retail as it delivers on its multiproduct strategy.

The next question comes from the line of Peter Wilson.

I did actually want to ask a question on that multiproduct strategy and the margins that you do expect. So you're targeting 400,000 extra services by FY '24. If you could answer what, I guess, gross and net margin you expect for those customers or whether we should see it more as just a retention exercise. And I'm hoping you could answer relative to your current numbers, which are about gross margin of $200 per customer, net margin of $50 per customer and gross margin on telco about $50. So kind of where in that range should we expect the margins for these 400,000 customers?

So look, I'll throw to Christine just to talk about where we see the growth in absolute number of services. What I would say is for individual services or individual products, we don't particularly see margin going up or down when we think about that longer-term outlook. So that's without giving a whole bunch of detailed guidance. When I think about the next 3 or 4 years, I'm not thinking about margin necessarily contracting or expanding. Mix will play a part in it. So to the extent, as you point out, a broadband service attracts a lot less margin than, say, an electricity service, mix in the number will be there. But for individual products, I'm not expecting a huge shift, up or down, in margin per product -- or per service, sorry. But Christine, did you want to talk a little bit about where you see that growth coming from?

Yes. Thank you, Brett. Look, the other thing I would add, consistent with our customer growth this year, and you would have seen that we've had growth of 78,000 customers in the last financial year, we see continued growth in our traditional base. And the benefit for us going into multiproduct retailing is not only to keep growing that existing base but also to add more products to that base. So when we look at that, it is really selling into that very robust strong base that we have and really moving from single fuel to dual fuel to both product, in broadband and mobile. We also see then -- the other improvement for us will be a reduction in churn. We've seen that this year with sort of record low churn levels that as customers become stickier with acquiring more product, we also see a benefit in that as well.

Okay. Can I just follow up to that? I mean the cost of service to those customers, should we focus on the gross margin? I assume there's no increase to service a single customer versus a bundled customer. Or should we look at the net margin? And also just on the mix between telco and energy customers, I'm not sure if you've provided that mix of that 400,000 customers. If you could.

No, we haven't provided that mix. So when we look at what that outlook is, it is going to be a combination of both energy and telco. When we look from a cost to serve basis, it is going to be going -- will look predominantly back into that core energy base. You'll see on the chart that we put up in the presentation where we're trying to actually now give increased visibility of operating costs overall per customer, and that is because as we broaden that base, we've obviously still got detail on what our cost to serve and cost to grow is. But as we broaden out, then we're looking at some more details on what is the overall operating cost to serve those customers rather than sort of traditional notions that have applied just to energy.

Thanks, Christine. The next question comes from the line of Daniel Butcher.

A simple one from me, actually. Just wondering about the franking credits. I think on Slide 11, you said you might have to pay franking as early as FY '23. Just curious if you give us a couple of moving parts around how much you accumulate, what losses are and what sort of profitability in FY '22 you would need to use them all up to start paying franking credits again.

So Damien?

Yes, sure. I'll take that one. Look, so if you recall, when Hazelwood ran on the market, we started to recoup our losses back in 2017 through to '19. So Loy Yang has been recouping its losses during that time. As a result of the fall in profits, what we're seeing now is Loy Yang continuing to recoup those tax losses and will continue to do so. And we were forecasting by around about the '23 year, that's the point we'll start to be able to paying frank again. So what's happening, more profitability, if you like. I said, we've got 2 tax groups, more profitability sitting in the Loy Yang tax group, and therefore, it's able to utilize those losses. We have around about -- from memory, I think it's around about, I think, $1 billion of tax losses that are still in there. You can see that through our notes. They'll continue to be utilized under the tax loss rules over those next couple of years. So it is the '23 year that we're forecasting to return to the utilization of the majority of those losses, at which point we'll start to pay franking again.

Thanks, Damien. The next question comes from the line of Max Vickerson.

Sorry, had a bit of trouble getting off mute there. Can I -- just saw a little comment on the notes on Page 44 on the commentary of wholesale markets underlying EBIT. There was a reference to movements in electricity derivatives. Just want to clarify if there's any change. I'm assuming there's no change in fair value movements in terms of impacting underlying. Can you clarify whether that was just realized impacts or if there is a change in policy?

I'm going to look which of the figure...

I'm basing from the reference, Max. But Damien, have you got that?

I'm just opening it up now. One moment.

Okay. Max, we might just have to take that on notice. Nothing unusual is going on with hedge accounting, but there's a question of detail there. We might just come back to you off-line, if that's okay.

Yes. But you're dead right, Brett. In short, nothing has changed. I'll revert back on that particular point in the notes.

Thanks, Max. Next question comes from the line of James Nevin from RBC.

Yes. Just another question on that and gas supply book and as more of that higher cost kind of gas comes in over FY '22, '23. I wonder, can you say anything on like is much of that gas actually sold like at a fixed margin already? Or is that going to be exposed to kind of whatever repricing or what you can kind of -- can sell it at over the next few years?

So James, I'll let Markus comment. But I would say loosely, to the extent that we're contracted, we are loosely in balance. The devil is always in the detail. To the extent you see an uncontracted position there, that will normally be linked to what we expect to do with rolling C&I. And so we would expect to be contracting sales to match purchases at the same time. But Markus, did you want to add anything to that?

Yes, James. A certain portion is, for sure, still exposed to the market because we are using part of the portfolio, for sure, for our gas-fired power stations. And this is an estimate that this is not fully hedged. So I would say 30% is exposed.

Thanks, Markus. Next question comes from the line of Rob Koh.

Maybe can I ask a general question to Mr. Brokhof, and welcome to Australia. I guess with the benefit of your international experience, could you maybe give us any early observations you have about the wholesale risk management systems and policies that you've come to? And with your fresh eyes, do you have any ideas for improvement?

Markus?

Yes. I think that -- when I look at -- with my international experience, there is some room for improvement, in particular, but this is also due to the liquidity in the Australian market is very limited, particularly as you go further out the curve. This is different particular to Europe, where people enter into -- a lot more in long-term corporate PPAs, which you then can hedge. To a certain extent, you still have an exposure to the market for the last period of the end of the tenor of the contract. But I think we need to develop more our products around this one and -- in order to improve the risk management point of view. I think from a short-term view, hedging and managing risks, that's similar to what we are doing or what the -- what most of the companies are doing in Europe. And then for sure, in a falling market, which we have at the moment, hedging and risk management becomes of high attention because this is very important to lock in margins in order to protect our portfolio.

Thanks, Markus. The next question comes from the line of Bruce Low.

Maybe probably a question for Markus again. Just that chart on Slide 19, looking at the generation output and sales. Should we take from that, that you would look to contract renewables? Essentially, you're talking about investments in firming. For the actual energy component, would you look at your firmly contracting new renewable projects to make up the balance of the energy? And then as the second part of that, the growth in the expected customer demand, I'm assuming that's expected growth in market share. Is that a fair way to look at it?

The latter, for sure, we would like to expand. We would, as AGL, not leave the market for -- to Shell and Total entering now and Iberdrola maybe. And the second one is -- the first one is, for sure, we will contract further out. Depending also on our carbon-neutral products, we will also then further contract long-term PPAs with renewable generation. But it's also -- that's excluded, we still have a few renewable projects in our portfolio, which we can then develop further and go to commissioning. And then in addition, we are also -- as Brett outlined, we are still continuing to develop, and this is also part of the area, of the yellow area or orange area. This is then also our Newcastle gas peaker, plus our battery -- grid-scale battery project, where we will up -- sum up and all the renewables.

And to -- I'd sort of add to that, that over the last, I don't know, 5-or-so years, we've deliberately allowed our C&I book to run down, this both gas and elec, while we've seen more sales and volumes go through the wholesale market. That's been a strategy that's paid off. You've seen that in the results in the last number of years. As the market started to turn and as we started to expect it to turn, we've looked to go back more onto the C&I side. Some of the early results of that, you'll see on the earlier Slide 13, with an uptick after -- the first time after a number of years in large electricity portfolio sales. And so I think increasingly, what you'll find us doing is moving back towards electricity, seeking some more C&I volume, and that potentially will allow us to link that into broader renewables and other projects as well. So there's a market that's growing there in C&I, looking for longer-term positions in firmed renewable energy. And the -- our point of difference, if you like, is we can bring the firming, not just the renewables that many projects are looking to sell. And then separately, on the gas, as you think about ways of getting gas supply like Crib Point, Crib Point is your ultimate play in optionality and flexibility of volume. So Crib Point itself is intended to provide some of the baseload need in Victoria. But it also allows us to go looking and talking to a longer-term C&I and saying, "We will have the flexibility and supply if you need more volume." It's a project capable of ramping up or down according to customer need down there. And so that will be part of a bit of a shift that I hope to see over the next few years.

Thank you, Brett. We've got time for one more question. The next question comes from the line of Tom Allen.

On the electricity portfolio, you've mentioned that your hedges have at least partly protected you against the big fall in wholesale prices. With your electricity portfolio EBIT dropping $150 million into FY '21, can you share what proportion of your portfolio electricity demand is being repriced at the forward curve? And also, perhaps share some color on your wholesale electricity price assumption over the next 5 to 10 years.

So I'll take that, and then Markus can add to it. Look, typically, we wouldn't, in an outlook sense, talk about the proportion of hedging. So as always, when we go into the beginning of financial year, we're reasonably highly hedged, and then that runs down over a 2- or 3-year period back down to where there is a base, I guess, of long-term customer supply agreements that we've got. So this year is no different, we start the year at a reasonably high level of hedging but still allowing plenty of space, particularly when you think about with some of the aging plant and outages, we don't necessarily contract right up to the last megawatt on our older sites. In terms of pricing assumptions we've used, look, by and large, when we give forecasts, we use what's in the observable market. So certainly, in the 1-year outlook for FY '21, it will be anchored in what you can see on the screens, in the forward market for electricity price. In the years beyond that, we begin with a planning assumption of what you can see in the forward markets as well, albeit with low liquidity. You become more skeptical in the outer years about how firm that pricing is. An observation I'd make, and it's similar to what I've sort of said up and down over the last decade, when price has been very high, when it's been $90-plus, we've talked about we feel the market is somewhat overshot, and we expect the force of gravity to pull price back. When market is well down, we've talked about -- and it's been a little while since we've talked about this side of things, but it was a few years ago, we've talked about expecting to see price firm back up, built around an assumption of where is the long run marginal cost of firmed renewables. And as you think about that grand transition that's got to go on through the market, where old coal plant particularly needs to retire, and this is answering your decade question, and firm renewables need to be built, I think we're going to need to see a price stronger than what's sitting right now in spot and in the 3-year outlook in the market. But whereas in past years, I might have been a little more bullish about the timing of when change might happen. You've often seen the market shift in 6 months. The impact of COVID has clip volume, not dramatically in the last 12 months, but is putting pressure on volume. But it's also sapped confidence in the market as well, and all of that's translated to price. So we may well see, I think, COVID sit on the head of the market for some time and depress price for a longer period of time than you might have seen in a normal market cycle. So we need to be ready for -- and none of us can answer how long will COVID exist. So we need to be ready for -- as COVID is a real weight on the market, we may well see price experiencing that weight at the same time. Markus, did you want to -- I've probably taken all your thunder, but did you want to answer or add to that at all?

No. But I think it's particularly related to how the evolvement of the prices on the commodities, particular coal, gas and oil. It's evolving, and this is most probably linked to the global economic sentiments on the back of COVID. And we see -- if this takes now longer, then we see more depressed prices going forward. That's most probably the effect. And if it comes to hedging, it's a rolling hedging. So as Brett already explained, most of our capacity -- of our energy is hedged already. But it's due to the fact that it's rolling, so -- and the liquidity is limited in the Australian market, as I said before. It's most -- it's rolling 2.5 years. And yes, then -- this current market environment, this is challenging.

Sorry, I do see in the medium haul the more strength in pricing, but COVID makes it harder. And I guess I'm a little more reluctant to sound more bullish on timing of when that might start to creep through. But you see the gas debate that's rolling around. If gas stayed at current low spot prices, you will struggle to see new investment in developing fields of gas in the country. If elec prices stay at the sort of levels projected in the forward curves, again, will be challenged as a market. This isn't an AGL comment, but as a market to see the new investment that's needed coming through as well. So I think there will be some balancing there, but COVID makes it harder to predict the short term.

Thanks, Brett, and thanks, everyone, for joining us today. I know there's a few more questions, but we'll take those offline. That's the end of AGL's Full Year '20 Presentation.

Thanks very much for joining.