AGL Energy Limited (AGL) Earnings Call Transcript & Summary

Thank you for standing by, and welcome to the AGL Energy Half Year Results 2021 Investor Briefing Conference Call. [Operator Instructions] I would now like to hand the conference over to CEO, Mr. Brett Redman.

Good morning, everyone. This is Brett Redman speaking. Thanks for joining us for the webcast of AGL's half year results for financial year 2021. I'm joined today by our CFO, Damien Nicks; Chief Customer Officer, Christine Corbett; and Chief Operating Officer, Markus Brokhof. We will have time for all your questions at the end of the presentation. The results that we're announcing today reflect the sharp decline in wholesale prices for electricity and renewable energy certificates, lower gross margins in wholesale gas and costs to support our operational and customer response to the COVID-19 pandemic. Underlying EBITDA of $926 million was down 13%, while underlying NPAT of $317 million was down 27%, reflecting the additional impact of higher depreciation expense. Our statutory result has been impacted by the charges associated with onerous wind offtake contracts, rehab provision increase and other impairments that we announced last week. Dividends reflect the special dividend program to temporarily lift the payout ratio to 100% of underlying NPAT, unfranked, comprising an ordinary dividend of $0.31 and a special dividend of $0.10. The outlook remains challenging. We expect underlying NPAT for FY '21 of between $500 million and $580 million, consistent with the update that we provided in December. That includes $80 million to $100 million of insurance proceeds from the Loy Yang Unit 2 outage of FY '20, which won't repeat in future years. This range reflects pre-existing headwinds as well as the continued deterioration in wholesale electricity market conditions and the financial impact of the current outage of Liddell Unit 2. We have also provided today a guidance range for underlying EBITDA of $1.585 billion to $1.845 billion. As we noted in December, the outlook into FY '22 and beyond is impacted by continued market and operating headwinds with a further material step down in wholesale electricity margin expected. Amid these challenging conditions, over the half, we continued to deliver on our strategy. We grew our total number of services to customers by 246,000 to 4.2 million, making us Australia's largest energy retailer, thanks both to the Click Energy acquisition and organic growth. Take-up of our broadband offering and carbon-neutral products has exceeded our expectations, while the launch of AGL mobile has just gone live. We are on track to deliver our plans for at least 850 megawatts of grid-scale batteries, while our orchestration and demand response activities are expanding strongly. And now we are taking further definitive action to stay ahead of the challenging conditions. We are benchmarking cash running costs to FY '15, the last time wholesale electricity prices were around today's level. To that end, we have already identified $150 million of operational expenditure savings to deliver in FY '22. We are also targeting a $100 million reduction in sustaining capital expenditure across the group by FY '23. Finally, we are assessing our business model and capital structure to maximize shareholder value. We will have more to say on all these initiatives at an Investor Day that we expect to hold around the end of March. Let me now turn to our 3 core operational metrics: safety; customer experience; and employee engagement. The total injury frequency rate per million hours worked decreased markedly to 2.4 for employees and contractors combined in the first half. That's a 27% improvement on FY '20, reflecting a sustained focus on safety. That said, any injury to any person on an AGL site is unacceptable. We will continue to do more improving our safety culture and practices. On the customer front, in addition to growing our customer base to a #1 position, we have delivered further improvement in Net Promoter Score. We have come a long way from June 2018, improving more than 25 points. For employees, engagement figures improved to FY '20, and we are due to take our next survey in a couple of months. Given the difficult operational conditions of the last year, these are pleasing results. This slide shows a further summary of our financial result, which Damien will cover more in detail later on in the presentation. I'd now like to look in more detail at market conditions. Spot and forward electricity prices have decreased rapidly to levels unseen since 2015. On the one hand, supply has increased as a result of new grid-scale and rooftop renewable generation, combined with the deferral of major planned outages at thermal plant as a result of COVID-19. On the other hand, demand has fallen due to mild weather and COVID-19. La Niña has created an unusually cool summer, particularly in December. Business and industrial demand were down approximately 6% across the half, excluding Perth Energy, partly mitigated by an increase in residential demand. Looking ahead, we expect demand will restabilize and price -- but price will need to lift from the current very low spot conditions or risk a market supply-side response. That said, we expect a sustained impact to long-term wholesale energy prices, reflecting policy measures to underwrite new build of electricity generation and lower technology costs, leading to expectations of increased supply. This lower price environment will put pressure on existing generation in the market, while new generation build will increasingly rely on government contracts. Amid these conditions, in the near term, we expect to see further margin compression as our historic hedge positions roll off. Longer term, our low-cost generation position gives us a relative strength among existing market operators. I now want to focus on the actions we are taking to support our market-leading position and customer offerings amid this accelerating external environment. The foundations of our business are strong. We are still Australia's largest energy retailer, largest electricity generator and largest private backer of renewables development, and we intend for all of these things to remain. The external forces of customer needs, community expectations and technological change have always shaped our market. As we've said for some time, it is the speed with which these forces change our market that will dictate the velocity of our strategy. What we have seen in recent months is an acceleration of all these forces beyond what we anticipated. In customer, uptake of our multiproduct offerings is both vindicating and exciting. And demand for decentralized offerings, whether that's home batteries and electric vehicles or remote generation and storage on industrial sites, is really starting to take off. In community, there is clearly accelerating desire for action on climate change, and with this, a shift in government policy focus. For several years, major policy initiatives have focused on retail pricing. More recently, we have seen an increase in policy aimed at accelerating the energy industry transition. This includes policies that underwrite new generation to deliver faster renewables build and put downward pressure on wholesale prices. This is coinciding with what's happening in technology: rapidly falling costs for renewables and batteries; and strong support from low-cost funding sources for renewables and clean storage. What are the impacts and implications for AGL of these accelerating forces? Our Retail business has a clearer path towards a future state in which it provides customers access to essential energy, data, electric vehicle, battery and other services on a carbon-neutral basis. And we are seeing the value of that retail service become more independent from the value we derive from our large-scale centralized energy supply portfolio. So much of what a household small business or industrial customer now wants is about the value they perceive from decentralization. This requires a different approach to trading and portfolio management in the way a traditional gen-tailer like AGL would manage risk in the past. At the same time, how we promote the 2 parts of our business is evolving. In our Retail business, we must seek out greater decarbonization, lower prices and more individual control in response to customer demand. In large-scale energy supply, we will remain an essential supplier of existing reliable generation through transition even as policy settings create much lower risk/return expectations for new supply. Six months ago, we set targets for where we think the business needs to get to in the next few years in delivering growth and transformation. Today, we are communicating further focus on cost and structure. We have identified $150 million of operating cost efficiencies to deliver in FY '22 on top of offsetting inflation. In addition, we are targeting a $100 million reduction in sustaining capital expenditure by FY '23. And finally, we are actively assessing our business model and capital structure to maximize shareholder return. At the Investor Day around late March, we will provide more detail. Let me summarize then by providing a progress report against the strategic targets that we set 6 months ago. We're delivering strong growth in absolute customer numbers, and our strategy of expanding into broadband and mobile will support our objective of increasing services per customer. We've made good progress with each of the 5 commitments from last year's climate statement. We're on track to deliver our battery objectives, including at our own legacy generation sites and have chosen a preferred supply partner in Wärtsilä. We've accelerated strongly our efforts in orchestration of residential and business customer batteries and demand response to more than 100 megawatts and 50,000 customers. But AGL and the energy industry have seen a material shift in profitability and outlook in the short time since we last set these targets. The market continues to change, and the pace of that change is accelerating. It is incumbent on us, in turn, to accelerate our response. I'll now hand over to Christine.

Thank you, Brett, and good morning, everyone. Today, I will provide an update on the financial performance of Customer Markets and the progress we have made on our multiproduct retailer strategy. In a challenging operating environment, I'm pleased to say that as a result of our focus on customers, our positive customer advocacy story has continued, and we have reported significant growth in our customer base. At the same time, we have continued to focus on lowering cost, improving the customer experience and building the foundations to become Australia's leading multiproduct retailer of essential services. Our half year performance was driven by strong customer growth, execution on our multiproduct strategy and underlying cost efficiencies against a challenging backdrop. Our underlying EBITDA of $177 million was down 12%, reflective of COVID-19 impacts and the integration of our new acquisitions, Southern Phone, Perth Energy and Click Energy. This was partially offset by lower operating costs due to a decrease in call center volumes and marketing efficiencies, together with an increase in the number of digital interactions with our customers. Regulatory intervention, customer behavior and high levels of competition have resulted in electricity margin compression in recent years, most prominently in Victoria due to the extent of regulatory changes. While this will impact in-year results, we expect to see Retail energy margins settle to more sustainable levels in the near, medium term. Meanwhile, our continued focus on growth in customer numbers will continue to result in volume-driven margin growth, and our multiproduct retail strategy will drive an increased share of wallet. Our overall CapEx has increased 5%, aligned to growth initiatives. The growth in customer numbers includes the acquisition of Click and Perth Energy, both of which are tracking ahead of business case. In the second half, we will continue to focus on energy growth and scaling our AGL internet and mobile service offerings. We will make further improvements to our customer experience, while at the same time, continue to improve our cost base as we further digitalize our business. As we continue to build the size and strength of our retail customer base, Net Promoter Score is now at a record level. We are seeing the impact of this, both in the growth in customer numbers and reduction in customer churn. Churn is at 13.9%, the lowest since 2014, and we have maintained a healthy spread to the rest of market. Our strong growth in customer numbers is reflected in our gross margin result, which has remained resilient despite customers switching to lower-priced products over time. Offsetting this, we've seen gross margin growth from acquired businesses as well as organic customer volume growth and consumer gas. We feel confident about growing our customer base further, consistent with the target of 4.5 million services by FY '24. Our underlying net operating cost per customer service continue to fall driven by our recent investment in systems and our ongoing focus on simplification and digitization. We are delivering these cost benefits at the same time as we pursue a growth strategy, enabling us to reach more households and businesses with increased efficiency. Our focus on customers provides the foundation for our ambition for AGL to be the leading multiproduct retailer for the connected customer. New products and services will help deliver customers better value and an effortless experience with the launch of AGL Internet and mobile in the last few months. By 30th of June, every product we sell will have a carbon-neutral option. By delivering value and catering for the demand for sustainable products for our customers, we, in turn, deliver greater long-term value for AGL shareholders. We will increase customer lifetime value through improved average tenure and overall services and margin per customer. At the same time, our cost base will be further improved through the economies of scale we deliver across both fixed and operating costs. We have bold ambitions to make a significant impact in the lives of our customers, with positive progress already realized, centered on customer growth, digitization and building trust and simplicity. I'll now hand to Markus to talk about Integrated Energy.

Thanks, Christine, and good morning, everyone. To start, this page includes an update on AGL's operational performance and impact on financials. Underlying EBITDA for the half year was down 11% to $911 million. This includes some of the effects of COVID-19 on demand for gas and the large business and wholesale customer segments of electricity, but also the longer-term impact of the electricity transition on prices. You will see on the right of the slide, a reduction in our capital expenditure year-to-date by 36%. This reduction is split equally between sustaining CapEx and growth CapEx. In the case of sustaining CapEx, the reduction is driven by major planned outage deferrals and rescoping due to COVID-19 restrictions that has changed how we are able to safely deliver work and access interstate and international expertise. For growth CapEx, the reduction is due to the completion of Barker Inlet Power Station in financial year '20 compared with this year. Smaller growth investments have been made in the orchestration platform of our decentralized energy business and the uplift of our trading systems. In the remainder of the financial year, we will be focusing on bringing our announced battery investments to fruition and advancing our Crib Point LNG import terminal to the financial investment stage. In addition, we are focusing on operating costs. Integrated Energy will deliver a substantive portion of the total company target of $150 million in financial year '22. The primary savings have been identified from asset maintenance optimization, reduction of contractors, decrease in professional services and consulting services and reduction in overtime. Finally, we will look to complete a review of sustaining capital expenditure that we have been undertaking with international expert advisers. We can't assume that the way we have operated our assets in the past will be the way we will operate in the future. And we are working to understand how we can operate more flexibly and efficiently in response to market conditions. Let's now turn to how our assets performed in the period. Given the challenging conditions I just outlined, I have been happy with the ability of AGL to react and rebalance our resilient asset portfolio. On the right, you can see that AGL's overall generation is down less than 5%, despite some material unplanned outages, mainly at our coal power station at Liddell, including the severe Liddell Unit 3 incident on 17th of December. After an in-depth analysis, return to service is scheduled for 26th of March. Loy Yang is running more reliably than in the same period last year. Renewables generation has increased more than 10% compared with the first half of last year, reflecting the increasing role in the AGL portfolio played by Coopers Gap and Silverton Wind Farm. Barker Inlet Power Station is performing ahead of business case to meet market demand for flexibility and firming up renewable generation. On this page, as we did at the August results, we are showing the AGL gas supply portfolio by the year in which contracts were signed. The gas book historically has been underpinned by a substantial volume from supply agreements signed when gas prices were much lower. The margin pressure we are seeing this year has a lot to do with increased procurement costs as these contracts roll off. Looking ahead, as domestic gas supply availability in the South diminishes and pipelines to key consumption areas look increasingly likely to face capacity constraints, we are planning to shift our sourcing strategy to include gas imports, notably via Crib Point. We believe Crib Point provides the best mechanism to meet Victorian customer requirements and provides the flexibility to ramp up and down to match demand. The panel assessing Crib Point is expected to provide their report to the planning minister by the end of February. In the meantime, we are contracting, on a short to midterm basis, additional supplies to meet our demand forecast. The most recent of which is shown in black on this chart. Recent portfolio contracts could be secured in the range of AUD 6 to AUD 7 per gigajoule, which has a positive effect on our overall portfolio price and can compensate partially the roll-off of some legacy contracts. Let me now turn to electricity. AGL has a rolling 2- to 3-year hedging strategy that is influenced by the liquidity of the market and our customer portfolio. Having this hedging strategy in place has mitigated the downside in financial year '20 and financial year '21 as prices have fallen. In this chart, you can see for each of the past 3 financial years, the hedged generation portfolio and the vintage of the hedged volume, including market pricing. It is this active risk management that has mitigated the downside of declining prices. However, as you can observe in the price labels, the earlier vintages were hedged at a higher price. So as financial year '17 and financial year '18 roll off, there will be a continued margin impact going into financial year '22 and '23. We will continue to focus on actively managing our hedge position to manage price and risk exposures, combining this with the evolving nature of our portfolio into the future. I will close by talking about our strong coal supply position in New South Wales and how this translates to our competitive position. The chart on the left shows our contracted position at AGL Macquarie, which will continue to provide us access to lower-priced coal than the market average into the mid '20s. The chart on the right shows the evolving dark spread in New South Wales from July '19 to January of this year. The dark spread is the difference between the price received by a generator for electricity produced and the cost of coal needed to produce that electricity. All of the plant's other expenses must come out of this spread. Hence, it is a main benchmark used to gauge the financial health of coal-powered electricity plants. With a declining dark spread moving below $20 per megawatt hour, as shown in the black on the chart, the profitability of much of New South Wales' coal generation will come under pressure. You can see this trend in New South Wales' dark spread line converging with the average fixed operating cost in the chart on the right-hand side. While AGL has a big advantage because of the dark spread premium we enjoy, as shown in blue, we are not immune to this trend. Hence, our focus needs to be on cost and efficiency to keep the plants running economically. I will now hand over to Damien.

Thanks, Markus, and good morning, everyone. I'll start by taking you through group underlying profit in more detail. The $115 million reduction in underlying NPAT in the half was consistent with the material headwinds we flagged last August. Looking at the chart from left to right, as you've heard from Christine, Customer Markets' margin was down slightly as a result of COVID-19 costs and lower pricing, partially offset by solid performance in Click Energy, Perth Energy and our new telco business, which combined, contributed $32 million to margin. In Integrated Energy, margins were impacted heavily as forecast, offset by the receipt of the majority of the Loy Yang Unit 2 insurance proceeds. Keep in mind that the $105 million shown is pretax. Post-tax, it's $73 million in the half. For the full year, we remain confident in the $80 million to $100 million post-tax range we forecast for the full year. Depreciation was up $15 million before tax in the half. Again, consistent with our guidance for an increase in this expense. The reduction in tax expense largely reflected the fall in profit, while net finance costs remain tightly managed. Now let me remind you of the 4 principles that underpin our approach to capital allocation. Consistent with the first, running the existing business for optimal performance and value, we've announced plans to reduce both OpEx and sustaining CapEx today. Since 2015, AGL has grown both our customer book and fleet materially, not to mention the inflation between now and then. So bringing our costs back to this level will be a significant achievement. Our second principle is to maintain a strong balance sheet and dividend policy. Underlying cash conversion remains strong, and we remain well within the bounds of our Baa2 credit rating. We are augmenting our dividend policy with a special dividend program as announced in August. Our third principle is to invest in growth, which we continue to do with a hurdle rate 300 basis points above our weighted average cost of capital. Our fourth principle is to return excess liquidity to shareholders. The buyback was completed in August. I'll now look at our cost-reduction program in more detail. We've identified $150 million in sustainable operating cost reductions for delivery in FY '22, in addition to continuing to offset annual inflation. That follows our objective to keep FY '21 OpEx flat, excluding COVID-19 impacts and acquisitions, against which we are tracking slightly ahead at the half. The remainder of those COVID-19 costs include: increased allowance for expected customer credit loss; cost to ensure employees and contractors were able to continue to work safely and securely at AGL generation sites during lockdown; and increased leave balances. The decrease in other costs is being driven by ongoing savings from recent digital transformation initiatives and other efficiency programs, partially offset by a small amount of restructuring and redundancy costs in response to more challenging operating conditions. You'll note on the slide that the waterfall starts on the left at FY '15, which we're using as a benchmark year. The FY '22 cost program is well underway. We're anticipating savings year-on-year from lower net bad debt expense as well as savings across labor, asset optimization, digitization and reductions in corporate functions, in addition to a material reduction in professional and consulting services. We've identified these savings across our business units, they've been budgeted and leaders understand their KPIs. I want to touch on credit loss in more detail. I'm pleased to report that our experience is tracking better than we expected year-to-date. As a result, we've reduced the provision by $5 million, but of course, there's still significant uncertainty around COVID-19 itself and the impact of government support programs rolling off. Lastly, a comment on the Click Energy acquisition. We did increase credit loss provisioning as part of our business case assumptions, reflecting the different risk profile, but to date, its collections performed better than our business case. Now let's turn to CapEx. Following lower CapEx in the half, we're now forecasting CapEx for FY '21 of about $750 million. The biggest difference to FY '20 being the investment in growing the multiproduct retailer offering in Customer. You can see the level of sustaining CapEx each year marked on this chart with a black line, again benchmarked to FY '15. This has largely been driven by mid-life and major outage schedules of our coal-fired generators. We have detailed programs underway to deliver reductions in sustaining CapEx as part of our $100 million target for the group by FY '23. This will appropriately balance our maintenance program, prioritizing commercial availability and efficient operations with our need for the cost base to reflect market conditions. I'll finish by talking about cash and debt. In the half, there were increased cash tax payments and negative working capital movements associated with our wholesale electricity market positions. Most significantly, there was a small outflow for margin calls compared with a large inflow in the first half of FY '20. Excluding margin calls, which move with wholesale prices, underlying cash conversion was strong at 90%. Investing cash flow was about $50 million higher as lower CapEx was partially offset by increased spending on acquisitions. Financing cash outflows were about half of last year, reflecting debt retirement and the cessation of the buyback. Despite the impairment, we retain plenty of headroom under our Baa2 credit rating and all of our debt covenants. We have no major refinancing due until November 2021 and approximately $600 million in cash and undrawn debt available. We did not replace an undrawn facility that matured in September, given the high levels of cash in the business. I'll hand you back to Brett.

Thanks, Damien. I want to conclude by looking at the historic relationship between EBITDA and wholesale electricity prices to help put more context about our outlook beyond this year. Wholesale electricity prices are the biggest driver of AGL's profitability. And you can see from the chart to the right that there is a strong correlation between the price trend, both up and down, and AGL earnings. The steady rise that occurred from FY '15 to FY '18 translated into record profits in FY '19. And the decline that we've seen since is now translating to much lower earnings this year and into the next couple of years. Markus has taken you through our hedge book in more detail, from which you can see that our progressive hedging approach smooths our earnings outcomes, both downside and upside. The chart here shows that wholesale prices are at levels last seen in 2015. Hence, it is likely earnings will follow. I'll finish by recapping our formal guidance statement with our outlook continuing to reflect the challenging market and operating conditions. Today, we have provided guidance for underlying EBIT (sic) [ EBITDA ] to be between $1,585 million and $1,845 million, and affirmed the guidance range that we provided in December for underlying NPAT of $500 million to $580 million. This includes the expected $80 million to $100 million after-tax benefit from our insurance claims over last year's extended outage at Unit 2 of AGL Loy Yang, which won't repeat next year. We continue to expect FY '21 operating costs, excluding depreciation and amortization, to be broadly flat on FY '20, excluding COVID-19 and acquisition-related costs. Our FY '21 guidance reflects the pressure to maintain margin of lower-cost supply contracts maturing in wholesale gas, lower market prices in wholesale electricity, higher depreciation and the costs associated with our COVID-19 response as well as the $25 million financial impact of the Liddell incident and further market deterioration and trading performance announced in December. In FY '22, the insurance benefits will not recur. In addition, we continue to expect a further material step down in wholesale electricity margin in FY '22, despite the benefit we will see from having impaired onerous wind farm supply contracts as older hedging positions progressively roll off and are contracted (sic)[ recontracted ] at lower levels, reflecting the deterioration in wholesale prices. The cost-out program that we announced today will not be sufficient to offset this negative earnings trajectory. As always, all our guidance is subject to ongoing uncertainty in relation to the economic impacts of the COVID-19 pandemic as well as normal variability in trading conditions. Thank you, and we'll now take questions.

[Operator Instructions] Our first question comes from the line of Tom Allen.

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

Thanks, Tom. Look, I'm expecting that in varying forms, we'll get that question a bit today. And what we're trying to do is show that we both recognize and are responsive to the market conditions around us. So clearly, a difficult day or difficult presentation day today where we have to acknowledge the thematics of the last 6 and 12 months are both continuing and accelerating. And at the same time, we've had the significant impairment last week and a difficult operating profit that we're presenting today, even in the context of I'm really pleased that we've been hitting our strategic goals along the way. But it's in that context that we think it's important for us to show or to acknowledge to the market that we see what's happening around us. We see what's happening ahead of us and that we are thinking about what's the appropriate response to it. And in that sense, we need to spend the time to make sure that we've thoughtful in a very complex situation, which will require a complex discussion in response. And we're going to come back with that thoughtful and complex response at the end of March when we're going to hold the Investor Day.

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

Thanks, Tom.

The next question comes from the line of Rob Koh.

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

Rob, Damien here, mate. Look, the way to think about this is that $150 million, it does include the reduction in net bad debt expense. What you need to remember, we had some last year, we've got some more this year. That will then return back to normalized levels. Then the way to think about that then is across the business, what we've done we've been working on this program over the last 12 months when COVID first hit us. We then accelerated that program 6 months ago under our operational edge piece to work through the business to identify and then start delivering cost savings. And what you're seeing, excluding bad debt, excluding some of the COVID expenses, underlying costs for the half were actually down $20 million. So what we're endeavoring to do is hit those run rates by the time we hit 30 June to be able to deliver the $150 million. And again, it's broadly across the business. Markus talked about some of his. Within Christine's area, it's around further digitization. It's been about some restructuring, some reorganization we've done over the last 6 months and then further across the corporate center as well. So it is broadly across the organization.

Thanks, Rob. The next question comes from the line of Ian Myles.

If we go to your FY '22 outlook, and I'm just looking back at your numbers for FY '15, you had wholesale electricity sort of reporting an EBIT of [ 676 ]. Since then, depreciation has virtually doubled. When you think about that sustainability, are we thinking at a gross margin that's going back to sort of '15 levels? Or are we thinking actually EBIT going back towards those types of levels? Because you've actually a lot more depreciation happening there.

I think, Ian, the context of that comment, I'd first read through the lens of EBITDA because let me acknowledge that depreciation has stepped up as we've seen the full impact of normalizing for owning a lot more plant during that period. So I think EBITDA is probably a better guide to start with. And the other comment I'd make is it's sort of a broad statement to say we're looking at FY '15 as a reference year. I'd sort of counsel people not necessarily to pull apart every line of detail and try and match every line within it because I think the business has evolved quite a bit in the last 5 or 6 years. So in the detail -- at a very detailed level, the analogy breaks down a little bit. But at a macro level, I think it's a fair analogy, particularly at the EBITDA level.

Thanks, Ian. The next question comes from the line of Mark Samter.

Just a question. I know remuneration is a sensitive subject, but I'm just -- we think it's a good way to factor about how the company thinks about it. Your LTI incentives are described at 5% to 8% ROE for your average target as a stretch target. I guess both the denominator and the numerator of the ROE calculation benefited from impairments and provisions announced last week. Should we still think that 5% ROE is a stretch target because I guess that just mathematically gets you down to about $275 million of impact, as defined as a stretch target? Or should we rethink the ROE guidelines in light of the impairments and provisions last week?

Yes. Look, thanks, Mark, for asking what is an awkward question, but is an elephant in the room. So it gives me a chance to answer it. First and foremost, the Board always takes the approach that where we have something like an impairment, or in recent years, the share buybacks are another good example, that might give a benefit, if you like, to management in the LTI calculations that was unforeseen when the target was set, they're stripped out. So while obviously, the Board won't decide on bonus outcomes until the end of the financial year and beyond, let me say with confidence that my expectation on behalf of management is that they'll apply a consistent approach and remove any benefit of the impairments from those calculations. In that sense, I would also say that in a difficult financial year, I'm not expecting, what's the way to say it, strong outcomes in a bonus sense. I think we're seeing the LTI metrics heavily impacted, both at an ROE sense, the TSR sense. I think in the longer haul, we're heading in the right direction on the carbon metric, but that's 3 or 4 years away in terms of hitting a reward point. So I come back to, I think, the key message here is the Board will remove from calculations any benefit from things like impairments. And as the shareholders are suffering significant pain, I want to acknowledge that, suffering significant pain, that will reflect, I am certain, through the incentives. And I'd also say at a personal level is reflected in my personal shareholding and others within the management group. So if you like, that pain is shared appropriately.

Thanks, Mark. The next question comes from the line of Peter Wilson.

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

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

Okay. And maybe just following that one up. The message I thought had been that you're spending quite a lot on Liddell, and that's why D&A had stepped up. Is that -- is there something…

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

No, it's around $12 million.

Yes. So for clarity, it's 10-ish is the Liddell CapEx spend this year. You see it more pushed into OpEx, which is appropriate for a plant in its last year or so of life. You're not launching significant CapEx programs. So technically, Liddell is in there. Practically, its impact on saying we're pulling 100 out is de minimis.

Next question comes from the line of Max Vickerson.

Question for Markus on the gas market. There were those comments you made about the portfolio contracts being able to be secured in the $6 to $7 per gigajoule range. I'm just wondering, are there meaningful volumes available at those prices? Or are you more talking about smaller quarter-to-quarter contracts that you might find on the -- in the short-term markets like the Wallumbilla hub or the STTM. Could you give us a bit more color on that, please?

Yes. Thanks for the question. Yes, you are fully right. The depth of the market is not there. So volumes are limited. So the tenure of the contracts which we entered are 1 to 2 years and that's the range in which we are. And we still try to secure additional volumes in order to optimize the overall portfolio price. And yes, that's, at the moment, the case.

Next question comes from the line of James Nevin.

I appreciate you're going to give more detail on how you're looking at the kind of future business model at Investor Day. But just some of the comments that you made in the presentation this morning around the retail service is becoming more independent from the valuation -- from the value of the generation portfolio. And you're kind of saying you get less synergy from being an integrated retailer. Like it looks like you're kind of trying to steer us maybe into, I guess, one of the options that you're looking at, essentially splitting up that retail side of the business from the generation portfolio. Are they both moving in very different directions now?

Thanks, James. Look, look, I think -- and this will be the difficult discussion with lots of people in the coming, whatever it is, 6 weeks or more or less to the end of March when we hold the Investor Day. We'll get into sort of having to try and answer black-and-white, yes-no-type questions in an incredibly complex environment that will require complex responses. So in the slide there, what we're trying to do is call out some of the thematics that we're seeing happening in our market that have evolved from when I reflect on the market 5 years ago and 10 years ago. It is different today. And when you think about where customers are heading and what they're demanding in a product set today, it's starting to become very different to 10 years ago. When you're thinking about the role of government policy in our markets today, it's very different to what it was 10 years ago. So all of these things are taking what was a very clear-cut set of assumptions and responses 10 years ago to an evolving and more complex set of conditions and responses that we're seeing in front of us today. So rather than rush it, we wanted to signal today that we're not sitting on our hands with our eyes shut and our ears closed to conditions around us. But at the same time, we want to be thoughtful and come back with a complex answer to a complex situation at the end of March.

Your next question comes from the line of Mark Busuttil.

I was interested in some of the comments that were made around dark spreads. So Markus was talking about the New South Wales dark spreads. In the context that you need to give 3 years' notice to shut any capacity, what sort of production response or response from generators could you have to lower prices for assets that may be operating at negative cash margins? What can you do?

There are various angles to this. One angle is for sure, lowering our minimum load. That's what we are doing already partially. And we have to look at this furthermore. Then also how we run it. Is the availability of all the units the right measurements? And then also looking at the overall cost structure. I think that's number one. Cost structure is something which we -- where we have to cope with. I think Damien has elaborated already on this that we have to lower our operating costs furthermore. And yes -- but at the end of the day, we have also to rethink how we run all the units, in particular over the day the prices are negative. And that's something which we have to look at carefully and not to any more -- to lose money then during the day.

Can I just ask just a quick follow-up on this? I mean do -- would generators be looking at changing bidding patterns? Clearly, generators offering capacity at negative pricing aren't intending on setting the price at those negative prices. They're just purely doing it to be dispatched. And given the increasing frequency of negative pricing days, are you and other -- and your peers looking at changing the way you're bidding or offering capacity into the market?

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

Yes. And I think, Mark, maybe just to expand a little. The point that we're trying to make, I guess, is in 2 parts. In one part, we're seeing a market overall get to a point where the market overall, particularly in black coal generation, will be struggling to cover its cash costs at today's spot prices. So that will point to stress within the market. The second point that we would make is that AGL has been very deliberate in the generation that it has bought and built over the years. And I don't know, you'll remember many presentations we've made over the last number of years about our sites like Macquarie and Loy Yang, where we talk about them being at the bottom of the cost stack. So in a market under stress, we continue to work at the bottom of the cost stack and are in a better position. But it is a market where something will be under pressure or something will have to start to shift in the coming months and years, if it continues to operate at or beneath, in an overall sense, cash running costs.