AGL Energy Ltd (OTCPK:AGLNF) Q4 2020 Earnings Conference Call August 12, 2020 8:45 PM ET
Christine Corbett – Chief Customer Officer
Brett Redman – MD, CEO & Director
Damien Nicks – CFO
Markus Brokhof – Chief Operating Officer
Conference Call Participants
Robert Koh – Morgan Stanley
Tom Allen – UBS
Mark Samter – MST Marquee
Ian Myles – Macquarie Research
Peter Wilson – Crédit Suisse
Daniel Butcher – CLSA Sydney
Max Vickerson – Morgans Financial Limited
James Nevin – RBC
Bruce Low – Bank of America Merrill Lynch
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, some of bushfires and proceeding drought. We’re growing our customer advice at the same time as we support customers through challenging times and deliver improved service and simplified products to increase digitization.
We now deliver more than 3.95 million services to customers and we have experienced a step change in customer feedback by mechanisms such as Net Promoter Score. Our energy portfolio has delivered resilient supply, maintain strong generation despite the major unplanned outages 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’re 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 two years, and we expect to reinvest a further $100 million of recurring efficiencies this year.
In June, we released our refreshed climate statement comprising five 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’ve 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 from the payout ratio of 100% of underlying profit after tax. This reflects the strength of our cash flow outlook and subject is always to liquidity being available after funding potential growth programs. So while our guidance for financial year 2021 underlying profit after tax to be in the range of $560 million to $660 million reflects a material decline. We’ve 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 because they bring these headwinds forward a lot faster as wholesale prices of that, while also bringing new cost headwinds from credit losses associated with customer hardship.
However, our cash flow and financial position remains strong and we have material headroom to invest in the business and support growth and cash management initiatives. Let me now turn to the three core operational metrics on which we report safety, customer advocacy and employee engagement.
The total injury frequency rate for million hours worked decreased to 3.3 for employees and contractors combined in FY 2020, 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 five percentage points year-on-year. Now turning to our financial results, in contrast with Slide 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 high depreciation expense.
So in the context of these unanticipated disruptions, at 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 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, and 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 without 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’re 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’re well on the way to delivering on the transition.
Customer markets is moving from being a leader in electricity and gas retiling only to becoming a leader in the provision of multiple essential services, including broadband and the delivery of other roads and 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 balance to customer demand.
My next slide details some of the targets that we’re now setting ourselves. We feel confident setting these targets despite the ongoing market uncertainty because of the underlying stability of the business. For the FY 2024 results, we’re 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 to-date. That translates to 400,000 of our customers today, none of us 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’re targeting a rip track score above 70 compared with 68 today. In the supply portfolio, we’re 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 and deal 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 besting outcome for our new long-term plan incentive metrics.
These targets and metrics were integral to the launch of our carbon 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 three 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 the slide, you can see our five commitments on carbon neutral products, supporting voluntary carbon markets, investing in the 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 2020 to $0.98, 80% franked, this is consistent with our dividend policy payout ratio of 75% of underlying profit aftertax.
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 2017 and FY 2020. On average, that means we spend about 40% of EBITDA to shareholders through dividends and buybacks since FY 2017. Today’s announcement of a special dividend program means we intend to declare a special dividend of an additional 25% of underlying profit aftertax in FY 2021 and 2022. 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 returned to paying frank dividends.
All dividends and other Capital Management as always is subject to the undrawn 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 three slides, I’ll highlight the significant progress we’ve made in the key customer metrics that we focus on the long-term value, the benefits we’re 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 new energy markets.
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’ve seen 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 two consecutive years, we’ve increased that by over 140,000 of which 78,000 within the last 12 months.
This is against the 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’re 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 2024. Our churn rate is at 14.3%, the lowest since 2014 and we have maintained a healthy spread to the rest of the markets.
We’ve 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’re 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, three of which are shown on the slide.
Ombudsman complaints have fallen 37%. In particular, we have seen a reduction in bill complaints, reflecting our customers increasing oversight if you seek an 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’s important to note that we’re pursuing a growth strategy, balancing growth as we invest to expand and multiproduct offerings to reach more households and businesses with increased efficiency as we scale.
Our focus on customers is core and our investment in digitization is the foundation for establishing AGL as a leading multiproduct retailer for the connected customer. With across three key areas, simplicity, connected essentials, and the energy market transition. It begins with simplification. It is easy for customers to see value in our products and trust us to have essentials covered, over the past 12 months 30% of our custom portfolio has moved to our Central’s range offering simple low rate based products. Our digital capability enables us to move beyond an energy only offering to multi-product 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’re also expanding our product offering to our large business customers funding unique energy solutions that are both cost effective and energy efficient.
We’re responding to our customers desire to participate in the transition of the energy markets 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 years. We have launched our carbon neutral offer for our electricity plans and will have carbon neutral offer available on new products.
While we have had success in holding our generation output on the pricing side, we’re seeing decline across electricity and gas port and fluid prices. It is worth noting that AGL has been active in managing exposure across these prices.
With the majority of our active financial year 2021 hedges in place before the COVID-19 disruption, it holds our prices in early calendar year 2020. We see some increasing renewable generation growth, the 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 commitment. On the electricity side, the forward curve declined rapidly at the second half of financial year 2020 as a result of increased supply due to deferred outages, new generation and low short-term gas and cocoa. Prices has started to pick-up in southern states, as maintenance schedule resumed somewhat and as temperatures have declined. The gas book price declined through financial year 2020 as excess market supplies from the Northern states continued this lower domestic demand and LNG export.
We still expect gas supply constraints to hit in the early to mid-2020. As a result, we continue to pursue both the Crib Point Import project and competitive free contracting of gas supply. To ensure adequate flexible supply this trading exposure to international LNG pricing across both gas and electricity, we see prices being driven by short-term issues that reflect current conditions, the short-term and midterm price is likely to remain depressed due to macro economic conditions, the COVID-19 deferral of outages across that, we need to be caught up by either preplanned or unplanned outages in the future, putting further upward pressures on prices and volatility.
We believe investments in new Flexible Capacity is required, if we take a longer-term view, this chart looks at the predicted trajectory of our cogeneration output up to 2030. You can see a pick in decrease in the mid-2020s as Liddell and Torrens A retire hence you would see further declines in the 2030 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.
Also energy prices are lower, we still see an opportunity to in the composition of the portfolio shift away from coal towards the new firm’s renewable generation, the market needs.
AGL strategy is to optimize dispatchable generation, support investment in firms renewable 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’re working on. Hence ambitious targets, we have set ourselves for financial year 2024.
In fact, we’re 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 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 the core source of value for AGL for many years. Through the last decade, AGL benefitted 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 increasing, our order supply contract signed pre-2010 are represented by the dark blue on this chart, while those signs between financial year 2010 and financial year 2015 are represented by the light blue. The maturation of this long-term contract to have a material impact on wholesale gas margins in financial year 2021. 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 allows gas to benefit customers by mitigating supply uncertainty and providing optionality. The H area in the chart represents the significant investment opportunity which AGL plans to take advantage of this 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, Marcus and good morning all. I’ll start by taking you through group underlying profit in more detail, $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 extended unplanned outage at Loy Yang Unit 2. As we said at the half year, strong generation elsewhere in the portfolio lodging 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 is lower volumes under long running contracts. Before in 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 schedule shorten, the completion of $295 million parking lot project and a full-year of depreciation on almost $500 million software platform investments in recent years.
Total depreciation expense was a little hard and 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 $15.9 million was driven primarily by COVID-19 related impacts as I will cover 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 two years with a bridge from FY 2018 to FY 2019 and bring to FY 2020. In total, we have delivered $135 million of recurring savings across the business, $78 million in FY 2019 and $57 million in FY 2020. These savings should cover two 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 customers are now on a Simplified Central’s product, and the increase we have seen in customers choosing digital channels for self-service systems.
We’re 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 two 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, a growth in our customer numbers, acquired businesses and multi product retailing strategy, decentralized energy and our ongoing focus on developing energy supply and storage projects.
We’ve been seeing 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 cost for FY 2020 with COVID related impacts, $20 million from increased net bad debt expense and $18 million from increased on site operating costs. We will be recording flat costs from FY 2018 to FY 2020. Noting the uncertainty in relation to COVID-19, AGL expects FY 2021 operating costs excluding depreciation and amortization, broadly flat on FY 2020.
Approximately $100 million of procuring efficiencies are expected investment in growth and transformation and increases in insurance, regulatory and compliance costs. This sets us up for 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 debt into more detail. As in the current environment, this represents the read through to the broader economic conditions. The chart on this slide goes back to FY 2014 and shows that total net debt expense has been trending down slightly as a percentage of revenue. But blue colored bars average around $80 million. Like in FY 2018, 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 that, call that separately on the chart the purposes of comparison. Of course, we expect net bad debt expense to increase further in FY 2021 as economic conditions continue to deteriorate and more customers face hardship. We have 1,500 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 an ongoing stay connected hardship support program. Our current guidance assumes the additional net bad debt expense in FY 2021 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 sole position we have in futures markets. Although this price trend is not positive, 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 AGL acquired as a result of their efforts to deliver coal supply chain efficiencies and positive time impacts for total 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 refinancings 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 and we’re in the process of replacing some of their more expensive debt facilities, which will have an impact on our net finance cost this financial year, but deliver a positive net present value over the remaining life.
The bond debt refinancing we have too in November 2021 is Australian medium term notes. We intend to refinance that facility and potentially some of the remaining longer date bank debt next calendar year to take advantage of the strong support and the longer tenure in bond markets.
I’d like to finish by reviewing our performance relative to the four refresh capital allocation principles I said 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 2021 compared with $570 million in FY 2020 as programs defer 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’re 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 borrowing to extend tenure and to further reduce refinancing risks.
We’re not only maintaining a dividend policy amid uncertain times but 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 of 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 will hand back to Brett.
Thanks, Damien. I want to start my closing remarks by reflecting on AGL 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’re executing our strategy with discipline. There remain considerable opportunities to invest in growth as the energy sector transforms. We’re 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’re transforming our energy supply portfolio amidst the market headwinds to deliver greater decarbonisation 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 to 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 position to augment ordinary dividends with our special dividend program over FY 2021 and 2022. The specifics of our FY 2021 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 ranges for underlying profit after tax of $560 million to $660 million, that includes the expected $80 million to $100 million aftertax benefits from our insurance claims over last year’s extended outage at Unit 2 of AGI 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, a sharply declining process for energy 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 $14 million. But this is heavily subject to the length and severity of the economic slowdown.
There’s also a potential for ongoing cost impacts at sites to maintain safe and uninterrupted access for employees and contractors to ensure reliable supply of energy, if lockdown worsen. Noting the uncertainty related to COVID-19, we expect to hold FY 2021 operating costs excluding depreciation and amortization, broadly flat on FY 2020. 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 remained 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. 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. Please go ahead, Rob.
Thanks and good morning, everyone. Thank you for the presentation. I got so many questions. But let me ask, I guess a question about the target for 20% revenue from carbon neutral in FY 2024. I guess, experience with targets shows that, circumstances can change. Just wondering, how are you taking into account the target the 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 delta targets and we 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 out carbon neutral products or the products we’ve just put out into the market. That’s where that growth will come from. You’re right, it is 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 want to see from that is getting feel like a benefit from wholesale going down materially. That’s been I thought about the overall forecast. So it’s all about the carbon neutral products, and those that was released to the market.
Yes, great. Okay, it makes sense. Thank you so much. I will get back into queue.
Thank you, Rob. Our next question comes from the line of James [ph] go ahead, James.
Thanks Chantel. Good morning. 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 2023 that is repricing in FY 2021 and then look again at what goes into FY 2022, looks like a comparable volume, albeit the gas contract signs, pre-FY 2010 declined quite as much into FY 2022. So I guess the question is if I didn’t 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 2022 as what we’ve seen now for FY 2021?
I think James, 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 insure it from it, given based on age of contracts where those prices might have been struck, people can see the turnover and maturity of contract and while and what’s you have heard is some of the I guess medium contracts are rolling-off and nearer contracts rolling on. There’s also a growing wedge contracted as well, which if the current prices sort of sit there and 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 our procurement costs which are increasing now, we are doing the utmost efforts to read. Now on the lower level, but in addition, we are investing also in flexibility because as you can imagine this 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 resulted to it. So it’s mainly the cost of foliage and the cost of storage. And this is another driver by also the overall portfolio costs are increasing.
Thanks, James. The next question comes from the line of Tom Allen.
Good morning, Brett, Damien, Christine and Markus. Just with regards to management’s decision to return excess liquidity shareholders by the special dividends over 2021 and 2022. Well this month soften the impact relating franking, it also confirms the growth constraints we are facing over the next few years. The two biggest growth projects Crib Point LNG Import terminal and Newcastle 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 and 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 space for 2020. 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’re 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’s a real market need in Victoria to find more gas. And so customers in the next few years down are going to need more gases best straight ones down.
So see the fundamentals that underpin that projects 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 believe because of that market need, it is a project that will ultimately get over the lot, but I think it’s important now that the public has a chance to have its eye on that project. On parcel, we continue to progress it to a point where we can consider FID, so we’re working through a series of calls for can’t remember the right phrase, the calls tend to 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 unit, firming will come from gas, battery and hydro. The portfolio of the future for AGL will have heavily feature burning capability. We call 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 soon 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. But again, we’re staring 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 startup of Liddell power station?
So Liddell remains on track to go through its public timetable of closure. So partly in 2022 and finally, at the beginning of hours, we are continuing to look at otherwise of using the site and one of the things we’re looking at is battery on, and I give them 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 that even as we continue to run water on that site for a long time to come.
Next question comes from the line of Mark Samter. Go ahead, Mark.
Yes, good morning guys. Just a quick question on the balance sheet. And you talk about significant headroom, which is clearly down 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 or losses for FY 2021 there’s a really strong argument the majority of those assist your FY 2022 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, wasn’t quite sure at the end the exact question, but look I will let Damien jump in as well. By any measure, we see significant headroom in the balance sheet for either growth or capital management but 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 if we see a lower profit number that will put a little bit of pressure on some of these metrics, but to look through and one of the things we tried to call out today is to look at operating cash flow as well.
And they say a more rebar story if you like hiding underneath what is the hardest story when it comes to profit and at the end of the day, cash is king, and that 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 be assured and then secondly, if we don’t find the good growth opportunities, I’d like to think we’re also proving that will make what we’ve said which is return excess liquidity to shareholders as appropriate over time through buybacks on the other special dividend. But Damien, did you want to add anything to that?
I think you’ve largely covered it, Brett. Look I think just to reinforce that point around EBITDA is a proxy for cash. As we look out into the future years, Mark, you did right on profitability comes in, it is going to reduce but EBITDA net cash measure is strong. And it’s part of obviously, when was assessed and when we’ve looked at the impacts of COVID and scenarios around COVID. Yes, 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 today and continue to see that flexibility into the future.
Thanks, Mark. And the next question comes from the line of Ian Myles. Go ahead, Ian.
Yes, first simple question, the consumer business in this, second half 2020, the profitability of that business literally collapsed. So think in the first half, you indicated a neighborhood of 138, second half, full-year 186. 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 six months to see that step down and is that an issue going forward?
I might ask Christine to pick it up. Maybe with Damien backing her up.
Why don’t I take it first thing Christine, you can jump in if you like. Thanks, Myles. 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 still look at customer, I think it was said before is look at on a full-year basis. And then apply across that where you see benefits of like SPC and some of Perth rolling into those numbers as well. Does that make sense?
Looking on a full-year basis, I think because affordability in one half of the prior-year, and then you’ve got in this second half of H2 this year. You’ve got the impact of bad debts has rolling through as well. But look at on a full-year basis?
Yes, I think in to just build on that. 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 two with COVID this year and the beginning of last year, we booked an extra remember that about $40 odd million from memory of hardship. The other thing that goes on every time we try and explain switching retail is the timing of price change. And so transfer cost is steady for the whole year. Price changes then happen at different points of the year. And that tends to throw at 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 half to actually be favorable to consumer. And then added profitability back in away from also that reversed 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. Yes, it picks up in that moment. And bearing in mind it’s essentially striking April, May processes we run in that moment. What we see is the wholesale component for cost tax 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 try it in the market. And as each year you particularly see it in Victoria because we set the transfer cost and then on 1 July, 1 January that puts its price changes you often finding little disconnects half on half, even as before it makes more sense.
Okay, if we’re looking 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 profitability back into that consumer business or is it really the regulatory pressure on the pricing is making you running 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 of it, our cost include 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, energy accounts and broadband services, 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 leaving aside the noise of transfer pricing, I see a more robust future for retail as it delivers on its multi-product strategy.
The next question comes from the line of Peter Wilson. Go ahead, Peter.
Thanks, I did actually want to ask the question on that multi-product strategy and the margins that you’re doing. So you’re targeting $400,000 extra services by FY 2024. If you could answer what I guess gross and net margin 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 until about $50. So kind of where in that range, we expect the margin please 400,000 customers.
So look I’ll throw it 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 and 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 next three or four years, I’m not thinking about margin necessarily contracting or expanding, mix will fly apart.
So, to the extent as you point out our broadband service attracts a lot less margin than say in the 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 server side. 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 multi-product retailing is not only to keep growing that existing base, but also to add more products to that base, so when we look at this, 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. I have a follow-up. I mean the cost of service those customers should we focus on the gross margin as seen there’s no increase to service a single customer versus a bundled customer or should we look at the net margin and also between telecom 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 in a predominantly back into that core energy base, you’ll see on the charts 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 improve and we’re looking at details on what is the overall operating costs to serve those customers, rather than sort of the traditional notions that have applied just to energy.
Thanks, Christine. The next question comes from the line of Daniel Butcher. Go ahead, Daniel.
Hi, everyone. Simple one for me. Actually just wondering about the franking credits, I think on Slide 11. You say franking as early as FY 2023, could you just give us a couple of moving parts around how much the accumulated losses are and what sort of profitability in FY 2022 you would need to use them all up to start paying franking credits again?
Yes, sure. I’ll take that one. Look so if you recall when Hazelwood went out to market, we started to recoup our losses back in 2017 through to 2019. 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 we will continue to do so. And we were forecasting by around about the 2023 of that point we’ll start to be able to paying frank again.
So what’s happening more profitability. Like I said, we’ve got two tax groups, more profitability sitting in the Loy Yang Tax Group first able to utilize those losses. We have around about from memory. I think it’s round about I think a $1 billion of tax losses are still in there. You can see that through our notes. They’ll continue to be realized under the tax loss rules.
So it is the 23 year that we’re forecasting to return to the utilization of 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. Go ahead, Max.
Thanks, everyone. Sorry for the trouble getting off mute there, can I just saw a little comment in the notes on Page 44 on the commentary of the wholesale market on EBIT, reference to movements in electricity derivatives. Just want to clarify if there’s any change in that, there’s no change in fair value movements in terms of impacting underlying, can you clarify whether that was just realized in banks or if there’s a change in policy?
On which way you’re referring.
To your reference, Max, Damien have you got that?
I’m just typing it up, one left.
Max, I 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 offline if that’s okay.
But you did right, in short nothing has changed. I’ll revert back on that particular in the side.
Thanks, Max. Next question comes from the line of James Nevin from RBC. Go ahead, James.
Thank you. Yes, just another question on that and gas supply book. And as more of that higher cost kind of gas comes in over FY 2022, 2023, I wonder can you say anything on like is gas actually sold like at a fixed margin and already are, is that going to be exposed to kind of whatever repricing and what you kind of can sell it as over next few years?
So, James, I will let Markus comment. But I would say loosely to the extent that we’re contracted, we are loosely in balance. The data 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, do you want to add anything to that?
Yes, James a certain portion is for sure. Still exposed to the market, because the impact of the portfolio for some of our gas fired power stations and this is an estimated, this is no footnote not fully hedge. So I would say 30% is exposed.
Thanks, Markus. Next question comes from line of Rob Koh. Go ahead, Rob.
Hi, thank you so much. 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 are in tune with your franchise? Do you have any ideas for improvement?
Yes, I think that when I look at with my international experience, and there is some room for improvement. In particular, but it is also due that 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 long-term corporate PPAs between them can hatch to a certain extent, you still have an exposure to the market and for the last period of the end of the contracts, but I think we need to develop more products around this one. And in order to improve the risk management point of view making from a view hedging and managing risks that are similar to what we’re doing or what most sorts of companies are doing in Europe.
And then for sure in 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 and in order to protect our portfolio.
Thanks, Markus. The next question comes from the line of Bruce Low. Go ahead, Bruce.
Hi, thanks, thanks for all that guys. 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 renewals essentially you’re talking about investment 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 part of the growth in expected customer demand, I’m assuming that’s expected growth in market share, is that a fair way to look at it?
The data for sure, we would like to extend — would not reach the market share and total entering now and be better or maybe and the second one is, as the first one is for sure, even contract further out depending also on our carbon product, also then the contract long-term PPAs this renewable generation but it’s also nice excluded, we still have few renewable projects in our portfolio which we can then develop further and go to commissioning.
And then in addition we’re also as Brett outlined we are still continuing to develop. And this is
also part of the area of the yellow area or orange areas. This is then also our new gas plus our battery, various battery grid scale battery project, there is some apps in our renewables.
To sort of add to that, over the last five or so years, we’ve deliberately allowed C&I book to run down despite gas 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 earliest 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 is doing is moving back towards electricity, seeking small C&I volume. And that potentially will allow us to leap 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 our point of difference if you like is we can bring the firm in not just the renewables that many projects are looking to sell, and then early 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 baseline need in Victoria, but also allows us to go looking and talking to longer-term C&I and saying we will have the flexibility in 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’ll come out of a bit of a shift, 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. Go ahead, Tom.
Thanks, guys for allowing me to sneak another one. On the electricity portfolio, you’ve mentioned that you did at least partly protected you against the big bowl and wholesale process, with your electricity portfolio EBIT dropping $150 million into FY 2021. Can you share what proportion of your portfolio electricity demand is being repriced to the forward curve, and also perhaps share some color on your wholesale electricity price assumption over the next five to 10 years?
So I’ll take that and then Markus can add to it. Well, typically we wouldn’t in an outlook seem to talk about the proportion 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 two or three-year period back down to where there’s a bias, I guess of law and customer supply agreements that we’ve got. So this year is no different. We start the year by reasonable, 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 with use, but by and large when we give forecasts, we use what’s in the observable markets are certainly in the one-year outlook for FY 2021. It will be anchored in what you can see on the screens and the forward market for electricity costs. 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 on the outer years about how firms 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 have 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 this a little while since we’ve talked about this side of things, but it was a few years ago, we talked about expecting the same price firm back up, built around this assumption where is the long run marginal cost of firms renewables and as you think about that, that grand transition that’s got to go on through the market where all coal plants particularly needs to retire. This is the key 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 three 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 six months, the impact of COVID is click volume, not dramatically in the last 12 months, but that is putting pressure on volume, but it’s also sapped confidence in the market as well and all that’s translated across. So we may we’ll 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 normal market cycles.
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 market, we may well see price experiencing that right at the same time. Markus, did you want to probably taken all your, 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 commodity in particular coal, gas and oil is holding and this is most closely linked to the global economic sentiment on the back of COVID and if this takes no longer than the more depressed prices going forward, that most probably affect them when it comes to hedging, it’s rolling hedging. So as Brett already explained most of our capacity or 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 two and a half years. And yes, then there’s a current market environment. This is challenging.
I do say in the medium the more strength in pricing but by 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 true. But you say the gas debate that’s rolling around, this gas stayed at current low spot prices, you will struggle to see new investment in developing fields of gas in the country. If like prices stay at the sort of levels projected in the forward curves, again, we’ll be challenged as a market. This is an ideal comment, but as a market, this is the new investment that’s needed coming through as well. So I think there will be some balancing with that. But COVID makes it harder to predict the short-term.
Thanks Brett and thanks everyone for joining us today. I know there is a few more questions. But we will take those offline. That’s the end of AGL’s full-year 2020 presentation.
Thanks very much for joining.