AGL Energy Limited (AGL) Earnings Call Transcript & Summary

Good morning, everyone. This is Chris Kotsaris, talking from the AGL Investor Relations team. Welcome to AGL's half year results presentation for the 6 months ended 31st December 2019. The agenda for this morning's presentation is as follows: our CEO, Brett Redman, will shortly present an overview of our results and the business update; then be followed by our CFO, Damien Nicks, to present more detail on the results before handing back to Brett to comment on our outlook. At the end, we will open for questions. [Operator Instructions] I'll now hand over to Brett.

Thanks, Chris. And good morning, everyone. Our 2020 half year result reflects a disciplined approach to executing our strategy in operating the business amid increasing challenges. Profit is down year-on-year as per our guidance. We are nonetheless tracking ahead of our expectations. We are making our portfolio more resilient and growing our customer base while delivering disciplined cash and capital management outcomes. Underlying profit after tax was down 20% in the half primarily due to the outage of Unit 2 at AGL Loy Yang, increased depreciation following record levels of investment in recent years and the impact of market headwinds relating to the wholesale energy prices and reduced gas volumes. We have declared an interim dividend of $0.47 per share, consistent with our policy of paying out 75% of underlying profit over the full year. Throughout the period, there have been many positives, evidence of how we are building a stronger, broader business amid the ongoing uncertainty of our sector. Customers are responding positively to simpler pricing and the investments we've made to make it easier for them to do business with us. Energy customer accounts were up again in the period by 36,000 to more than 3.7 million. The acquisition of Southern Phone added another 160,000 broadband and mobile services. And our reinvestment in large business electricity customers is also delivering growth. In generation, our output was up 3% in the half despite the Loy Yang outage reflecting our efforts over the past 12 months to invest in plant availability and coal supply. We're also expanding and modernizing our energy portfolio. We announced 2 major grid-scale battery deals in the half at Wandoan in Queensland last month and with Maoneng across New South Wales in October. And we commissioned the first new gas capacity in the National Electricity market for 7 years at Barker Inlet in South Australia. We have refined our growth strategy to focus on connection, orchestration, trading and supply and generation. We've made targeted acquisitions in support of our strategy via Perth Energy and Southern Phone. Our continued strong cash position, both from an underlying performance and capital discipline point of view, has enabled us to complete 51% of the share buyback we announced in August 2019, while maintaining ample headroom to support investments in the business. We're announcing today that we expect underlying profit after tax for FY '20 to be in the upper half of the $780 million to $860 million range to which we guided last August, while noting that headwinds remain as we look ahead to FY '21. I'll now cover our key metrics for safety, customers and people. These are trending in the right direction, but there is always still more to do. In safety, the total injury frequency rate for the half is marginally improved across employees and contractors at 3.5 per million hours worked, but it is still too high and requires continued focus and investment. For customers, Net Promoter Score has substantially improved compared with recent years, although disappointingly, the score did not improve over the past 6 months. Our objective remains to continue to improve and we're encouraged that our Net Promoter Score, surveyed against specific events and transactions, is positive and trending upward over time. There is no new data on engagement for our people with the next enterprise-wide survey scheduled for the second half. Now to the financial highlights of the result. Statutory profit was up 11.4% to $323 million, reflecting a lower negative fair value movement than in the prior corresponding period due to the lower short-term forward electricity prices year-on-year. The reduction in underlying earnings was consistent with the guidance we gave at the 2019 full year result in August. There was a material impact from the Loy Yang outage, depreciation and market headwinds, as I've already discussed. And despite resilience in the period, average wholesale electricity prices were still down, customer pricing has come down on average, and gas volumes and margin are down in a tight operating environment. Consequently, underlying profit was down 19.6% to $432 million. The cash result benefited from a strong underlying performance and a reversal of net margin calls in the period. The interim dividend declared is 15% lower than the prior corresponding period. This is a smaller reduction than for underlying profit, in part because of the benefit of the share buyback, reducing shares on issue. Return on equity was down 1.9 percentage points to 11.2%, reflecting lower earnings, again, with some mitigation from the buyback. My next slide covers the Loy Yang outage in more detail. Having returned Unit 2 safely to full operation, we are now in a position to confirm the financial impact for this year and estimate the insurance proceeds that we expect in next year. To recap, after the initial generator failure in May, it became apparent following a full assessment that a full generator repair and stator rewind would be required, which would take 7 months. Although we completed the repair and rewind process largely on schedule in mid-December, following the initial return to service, we found cracking in one of the unit's 2 cold reheat heaters which meant we needed to undertake more boiler repairs before we could return the unit to full service. The final impact of the outage to our FY '20 underlying profit after tax will be within the $80 million to $100 million range we provided in August. The reason that the earnings impact was so large is that it has a low marginal cost as a result of supplying its own brown coal. So any loss of generation translates to significant loss of cash margin. We expect to receive the benefits of insurance claims in FY '21 and expect the net benefit to be broadly consistent with the quantum of the FY '20 impact. Looking ahead, the insurance market is becoming harder for aging thermal coal assets. This means AGL will pay rising premiums at the same time as retaining greater risks through higher deductibles. My next slide focuses on the resilient performance of the rest of our fleet. Total generation sold to the pool was up 3% to 21,793 gigawatt hours. Our increased availability and output enabled us to offset some of the extended costs of the Loy Yang outage. At the same time, wholesale electricity prices were stronger than we expected, albeit, they were lower on average than the prior corresponding period. The biggest improvement in output was at our black coal plants driven by our operating investment in plant availability and removing bottlenecks from the coal supply chain. The calendar year just ended was a record for coal deliveries to AGL Macquarie of more than 13 million tonnes, up by more than 1 million tonnes. This is a result of our major focus on working with trained rail operators to improve the availability at our Antiene unloader. More capacity gives us more opportunity to use lower-cost contracted coal and reduce our use of more expensive spot coal. Elsewhere in the portfolio, there was some reduction in hydro output following high generation last year and drought-related constraints. Generation from our wind assets was up as a result of output from Silverton and Coopers Gap. I'll now turn to my CEO scorecard, which covers our strategic priorities of growth, transformation and social license as well as the operational goals, which I've already discussed. We presented our growth pathways of connection, orchestration, trading and supply and generation at the Investor Day last October. We have acquired Perth Energy and Southern Phone in support of this strategy. Our core energy customer base is now up more than 100,000 accounts over the past 18 months and is bolstered by platform for multiproduct retailing, which Southern Phone provides. This is one way we are transforming the business, building a broader customer base more resilient to a transitioning market at the same time as we expand and further diversify our generation fleet and becoming a leader in both residential and grid-scale battery projects. In social license, we are a founding member of the Energy Charter, reporting publicly on our ongoing commitments to improve affordability and service delivery for our customers. We have supported our people and communities through the recent bushfire crisis. And we know that this has only heightened financial market and other stakeholder concerns in relation to climate change. So I'm pleased with the progress we are making in delivering on our commitments to enhance reporting under the Task Force for Climate-related Financial Disclosures framework. And I continue to believe that developing new energy supply is the best way that we can support lower prices for customers over the long term. And with the development of Coopers Gap, Silverton and Barker Inlet, we have delivered $1.6 billion of new plant. Now let's focus on our growth strategy. Connection is primarily about exploring opportunities in mobile broadband and the connected home as data and energy continue to converge. Our acquisition of Southern Phone has provided us a scalable platform on which to build a multiproduct offering. Orchestration is primarily about the value we can create through a network of distributed energy assets. Our Virtual Power Plant continues to expand. Trading and supply is about our DNA in trading energy in all its forms. Our proposed LNG jetty at Crib Point is a key project in which we see enormous potential to make the gas market more dynamic, while our growing grid-scale battery portfolio builds optionality into our electricity portfolio. Generation is about developing flexible dispatchable assets that can support the ongoing transition of the grid to renewables. We're proud to have commissioned Barker Inlet. We have added Kwinana Swift Power Station to the portfolio via the Perth Energy acquisition, and we are progressing approvals for the Newcastle Power Station. At the same time, we're continuing to invest in our core asset base to improve its flexibility and reliability. And in November, we will reach the halfway point in the 100-megawatt upgrade of the Bayswater Power Station. My next slide looks at the growth momentum we're seeing in our core energy customer base as we progress our journey to becoming a multiproduct retailer. The chart to the left shows that we have achieved net growth of 102,000 customer accounts in the 18 months to 31 December 2019. Overall churn and market activity has reduced with customer retentions down over the 18-month period, reflecting higher levels of customer satisfaction. We have also seen a reduction in Ombudsman complaints of 16%. The Customer Experience Transformation program is delivering better service and customers are responding positively to simpler offers. We now have 750,000 customer accounts on our simple AGL's Essentials plan. And call center volumes are down 21% and we're staying focused on providing all customers with the best rate for them. The chart to the right shows where more growth can come from. Our core energy customer base is increasing from a mature position, and there are pockets of meaningful growth opportunity as we sell more services to more households in more places. Throughout our customer base, there are considerable opportunities to provide more customers with services such as rooftop solar, batteries and demand response. Western Australia remains a growing market for us. Then of course, there is data with 160,000 services Southern Phone provides giving us a platform for multiproduct offers nationally. Now let's turn to transformation and specifically, our progress in batteries. As we said at the Investor Day, we are now at the dawn of the battery age. And we are taking a leadership position at both grid and residential scale. This market is now at a tipping point with the opportunity to leverage falling technology costs and government support for investment. The Wandoan South battery partnership announced last month with Vena Energy will be one of the largest battery projects in the country, complementing our energy position in Queensland through the Coopers Gap Wind Farm. We announced in October our innovative derivative agreement with Maoneng, giving us a call on capacity at a fixed price at 4 -- 50-megawatt batteries throughout New South Wales. We're already operating the Dalrymple battery on the Yorke Peninsula in South Australia, and we are progressing potential projects at Broken Hill and Liddell. Our Virtual Power Plant, residential and small business battery program now has more than 1,200 participants and capacity of greater than 6 megawatts. Consumer interest is accelerating, and we are responding, for example, through the very competitive Tesla Powerwall offer we launched early this year. Another way we are giving customers access to smarter energy solutions is via demand response. Today, we are announcing, we will expand our Peak Energy Rewards program to other states before next summer, following successful trials in New South Wales and Victoria. The pilot program with 8,000 customers in New South Wales and the support of ARENA, AEMO and the state government enabled customers to earn bill credits by reducing their energy usage at coordinated times of day. On average, participants save 30% on their usage during peak events. The expansion is entirely AGL funded and follows the successful expansion into Victoria in December. There is no cost to customers for participating in the program. Transformation is also about flexible generation supply. We were delighted late in January to accept full operational handover of the Barker Inlet power station adjacent to the AGL Torrens site near Adelaide. BIPS, as we call it, is a flexible 210-megawatt dual-fuel gas peaking power station with fast-start generation, suited to an increasingly dynamic market. It assists in balancing the state movements that can occur in wind and solar supply and its flexibility frees up gas for use in other parts of AGL's portfolio. The proposed mothballing and closure of the 4 Torrens A units will occur starting later this year through to September 2022. That is consistent with the deferral that we put in place last year to help offset the impact of the Loy Yang outage over summer. In social license, I want to acknowledge the efforts of our people in supporting our customers, communities and each other during the recent bushfire crisis. This response began at the start of the crisis last November. The AGL portfolio has performed strongly on extreme heat days that we experienced throughout that time. We have supported affected customers and the communities around our assets with prompt provision of targeted financial assistance. More than 173,000 of our customers have been directly affected by the fires and we have put in place targeted debt waivers, forgiven fees or paused billing for those affected. We have also given $150 credit for all volunteer firefighters. To date, the billing measures we put in place amount to about $3 million in customer relief, with about a further $1 million committed through donations and work with our community partners ongoing. Many of our own employees, families and communities were affected because the main Southern Phone operations are ran out of Moruya in New South Wales. Although I'm relieved to say none of our people were harmed and our assets have not been damaged. I will close this section of the presentation with this slide showing the executive team that's now in place at AGL. When Markus Brokhof starts as Chief Operating Officer in April, combining leadership of our Wholesale Markets and Group Operations units in the integrated energy business, the team will be fully in place. It's a team with a breadth of skills, combining deep energy experience with broad customer, technology and finance expertise. I'm excited about what Markus is going to be able to achieve leading the new combined business, and I am encouraged by the way Christine is delivering growth and operational improvements in customer. Not only is the team, my team, now stable after a period of leadership change, it is ready to deliver with edge. And I'm looking forward to what we can achieve. I'll now hand over to Damien.

Thanks, Brett, and good morning, everyone. I'll start by explaining the reconciliation of statutory profit to underlying profit in the half. Significant items in the period comprised of costs associated with the acquisition of Perth Energy in September 2019 and the partial impairment of our PARF investment, which reflects revised market pricing, marginal loss factors and generation assumptions for some of PARF's sites. The loss in the fair value of financial instruments of $92 million in the period compared with a loss of $251 million in the prior corresponding period reflects movement in wholesale prices. Now let's look at underlying profit across the group in more detail. The period-on-period $105 million reduction in profit reflects issues we flagged to the market back in August. The largest of these was the impact of the Loy Yang outage, which had a total portfolio impact consistent within the $80 million to $100 million range we provided last August. The total negative movement in wholesale electricity gross margin of $50 million shown here reflects the offsetting benefit of our strong generation performance. The other large impact we forecast in August was higher depreciation. This was $80 million pretax in the half, reflecting recent investments such as Customer Experience Transformation program and capital expenditure on major outages and life attainment activities on assets nearing their end of life. Note that the first half impact makes up much of the pretax increase of the $100 million we forecast for the year. That step-up in depreciation had already started to take effect in the second half of last year. Therefore, the period-on-period change will be less in the second half of FY '20 than the first half. Nonetheless, full year depreciation may come in above the amount we forecast as a result of accelerated depreciation associated with unplanned CapEx on outages at both Loy Yang and Bayswater. Elsewhere, the biggest movements were the decrease in gas margins due to lower volumes and lower eco market margins on lower LREC prices. The strong offsetting factors in the period were our consumer electricity gross margin, supported by stronger volumes and customer numbers despite the introduction of default pricing. Operating costs were broadly flat as savings in customer markets offset increased plant availability and digital capability spend. Net finance costs were down, following the retirement of the hybrid notes in June 2019. Tax expense was down primarily because of lower profits. I want to take a moment to talk about the second half as our strong first half implies a lower result in the second 6 months of the year. Although we expect wholesale electricity margin to be higher in the second half now Loy Yang Unit 2 is back in service, we expect generation elsewhere in the fleet to pull back a little. And we have experienced a number of small outages in recent weeks combined with the impact of ongoing market price headwinds. In addition, we expect ongoing impacts in consumer electricity from customers moving to lower rate products as well as the timing impact of the accounting treatment of bad debts which always weights to the second half. Finally, we expect ongoing pressure across the gas portfolio as well as the usual seasonality impact from lower volumes in the second half. Turning now to our electricity portfolio performance. Pleasingly, the 3% generation increase was coupled with increases in customer volume across all categories. Consumer volumes increased in line with our continued growth in average customer accounts with weather impacts negligible to consumption. Large business saw increases in customer load in New South Wales and South Australia, a result of customer account growth following a renewed business development effort. Wholesale customer consumption was up slightly on aggregate. On the right-hand side of the page, you can see the wholesale electricity margin, reflecting the Loy Yang outage and offsetting performance elsewhere. The increase in consumer margin reflected a lower transfer price because of lower wholesale prices. The group operations cost increase reflects the availability investment and depreciation trends I've previously discussed. There is enhanced disclosure in the portfolio margin reporting section of the operating and financial review on fuel and generation running costs, as we flagged at the Investor Day last October. We'll continue to evolve these disclosures for the full year as part of our approach to integrated reporting. The gas volume reduction is consistent with recent trends with a continued decline in large business and wholesale customer volumes due to the loss of customers amid continued tight supply conditions. Lower consumption led to a reduction in consumer volumes, although customer accounts were up. Consumer margin was impacted by a combination of these lower volumes and customers switching to lower-priced products during the period, including the introduction of the gas Safety Net to reward loyal gas customers with lower rates. Wholesale and large business continued to experience a loss of customers as a result of tight supply conditions. Please note, for completeness, we are now including gas production and storage earnings in our gas portfolio margin. These earnings improved due to reduction in cost and increased gas sales at the Moranbah joint venture. Looking at operating expenditure in more detail. Last year's full year results, we said we're going to have year-on-year savings and we are still on track for that, excluding the impact of newly acquired companies. At the half, we are flat, excluding the impact of Perth Energy OpEx, meaning we are offsetting inflation. The savings are largely due to customer markets. The largest benefits being the nonrecurrence of major debt forgiveness initiatives we undertook in the prior corresponding period. Lower market activity also meant lower variable costs, supported by the benefits of our investment in the Customer Experience Transformation program. Offsetting these savings, we had increased spend in Group Operations because of the Loy Yang outage and the continued deliberate investment in plant availability. We've also created the Future Business & Technology unit, which is driving the delivery of innovation, long-term business development, ongoing digital transformation and data analytics capability. This expenditure will be offset in margin growth and efficiency gains over time. Finally, we continue to see increases in insurance and regulatory costs, reflecting our aging thermal assets and the heightened regulatory environment. The net cash outcome of $1.135 billion is a record for the first half driven by strong underlying cash generation and working capital improvements. The positive inflow from margin calls reflected the recent decreases in the electricity prices, meaning we needed to keep a lower margin balance in relation to our net sale position in futures markets. The movement in other working capital also improved, reflecting reduced inventory growth at AGL Macquarie as a result of our coal supply chain efforts and positive timing impacts between the periods relating to the purchase and surrender of green certificates. The tax cash flow of $5 million was net of tax installments and a refund received for the prior year as well as the utilization of tax losses at Loy Yang. Cash conversion, excluding margin calls, is close to 100%, consistent with the historical performance as you can see on the graph to the right. My next slide gives a good visual representation of capital management and our financial and funding position. We have now undertaken just over half of our announced share buyback and we intend to complete in the second half, market conditions permitting. As a result, net borrowings have increased. We undertook our first sustainability-linked loan in September 2019, following the repayment of the hybrid in June of last year. We maintain scope to invest in the existing business and new growth opportunities while continuing to manage capital efficiently. I will close my comments by providing an update on our plans for enhanced TCFD reporting. We committed last year to provide an analysis of at least one scenario in which the objectives of the Paris Agreement are met and global warming is kept to no more than 1.5 degrees above preindustrial levels. This is one bookend of the scenarios we are modeling, the other being no change to current policy settings in Australia. Other scenarios we are modeling reflect other potential pathways to deliver meaningful emissions reduction. In all cases, we'll be extending our modeling further than before at least to 2040, and using comparable, verifiable data from the IPCC and AEMO as starting points for our modeling, with KPMG assisting us as an independent adviser. The resilience of our business to the physical risk of climate change is also being considered in our scenario analysis and reporting. I'll now hand back to Brett to wrap up.

Thanks, Damien. I will now wrap up by providing an update on our current views on the wholesale electricity and green certificate markets and on our fuel cost outlook. You'll recall, we spoke at our full year result in 2019 about how these market headwinds would affect our earnings in the short to medium term. I'll start with the wholesale electricity market. Although down on average on the prior corresponding period, spot prices, in fact, proved reasonably resilient in the half, and we were able to benefit from this because of our strong generation performance. However, there has been a sharp contraction in flat swap prices in recent weeks and as a result of lower pool prices in the first quarter of this calendar year to date. The first quarter is often a volatile month for spot prices because of the emphasis on system availability over summer. So the current flat swap pricing may be slightly depressed compared with our 3-year view. But while that may mean some risk to the upside in the short term, the long-term trajectory remains for prices to continue to trend down as more supply comes on and demand remains flat. We expect, over the next few years, prices to trade in the $60 to $90 per megawatt hour range. In the green certificate market, although the large-scale renewable energy certificate price has been resilient over recent months, the forward outlook remains for further falls. We still expect certificates to maintain some value, and we are watching the market closely in the context of demand for carbon offsets which may create a conceptual floor for LREC prices. Now I will turn to our fuel cost outlook and our revolving sourcing strategy for black coal and gas to mitigate impacts from maturing contracts and market price trends. As we have discussed, gas input costs were lower in the half because of lower volumes, meaning we sourced a greater proportion of gas from lower-cost legacy contracts. While the cost of recontracting is lower at present than it has been for some time as a result of a fall in global gas prices, it is still materially higher than at a time when we struck these older contracts. As a result, the outlook for our gas sourcing costs continues to average up in coming years. We continue to look at the most efficient ways to source gas to support the lowest possible prices for our customers and to increase competition in this market. We're progressing the proposed Crib Point LNG import terminal, working through environmental approvals and expecting to reach a final investment decision during the 2021 financial year. When we do come to that decision, we do expect the timing of delivery of first gas and the overall cost of the project will have been impacted by the increasing complexity of the project since its first inception. Nonetheless, even with potentially later gas and higher costs, the economics of the project remain potentially very compelling. Our average cost of black coal in the half just gone was greatly aided by the coal supply chain improvements I discussed earlier. And I am confident the investments that we've made in logistics management over the past 18 months will continue to benefit AGL. Nonetheless, escalation will still occur on existing contracts and there are gradual step-downs in volume from the very cost-competitive legacy contracts we acquired with Macquarie Generation in 2014. Of course, black coal only services AGL Macquarie, not AGL Loy Yang, where we provide our own brown coal at a very low marginal cost. So the market headwinds in our traditional business remain, but we are executing our strategy and operating the business in a disciplined way against these challenges. Building a broader-based, more diverse business characterized by many relatively small initiatives is all about growing our resilience in this transitioning world. If I reflect on our progress in recent months, we are now connected to more than 27% of Australian households, and I am confident we will continue to expand the breadth, number and quality of our services. We've added broadband, mobile and battery offerings to our core electricity and gas services. And this will enable us to provide more value to existing and new customers. Geographically, we are more diverse than ever with a meaningful presence in Western Australia, an increasingly physical presence in Queensland, and a stronger regional presence to build on via Southern Phone. Finally, as our traditional baseload generation fleet approaches the end of its life, we are developing a more modern, more distributed portfolio of nimbler, more dynamic energy supply using fast-start gas, batteries and other technologies. It remains an exciting time to be in the Australian energy industry, and I am confident AGL, with its broadening customer base and asset portfolio, is extremely well placed to thrive. To close, the outlook reflects our solid performance relative to the known challenges. We expect underlying profit after tax for the full year to be in the upper half of our $780 million to $860 million range. This reflects the offsetting impact of our strong portfolio performance and customer growth on the impacts of the Loy Yang outage, depreciation and market headwinds that we expected. Those headwinds remain as we look into FY '21, but our cash generation continues to be very strong, supporting our robust financial position and the anticipated completion of the share buyback. We will now take questions.

[Operator Instructions] Our first question comes from Tom Allen from UBS.

Congratulations on the solid first half result, obviously, amid fairly tough market conditions. First question, can you please provide some further detail on the debottlenecking work undertaken to get better coal supply into the Mac Gen assets? And what work you've done to optimize the physical dispatch out of those Mac Gen assets? Or I guess, I'm interested in whether these new arrangements you described with rail operators will continue. And is the higher output from those assets over the first half, the new run rate to expect going forward?

Tom, we might -- I'll get Doug Jackson, our GM of Group Operations, and we've got Richard Wrightson here, too, from Wholesale. It's a collaborative effort, but I'll get Doug maybe to kick off the answer.

Sure. Thanks, Brett. Thanks for the question. Yes, it was a lot of work done, not only with the rail companies on sort of improving the supply logistics, but there is a maintenance strategy and operating sort of strategies we could put in place within the coal yard and the coal belt handling systems to improve, not only availability and reliability, but it's removing single contingency failures and just optimizing the whole operational maintenance of that, the coal yard and coal handling systems. And then Richard can sort of comment on some of the work we did with the rail transport system.

Yes. One of the major problems we had at Bayswater and Liddell site was actually getting the coal on a number of trains getting canceled. And if we cancel trains, we actually normally end up losing the Wilpinjong, which is our lowest cost coals. So there's a real focus to making sure we could actively took or take all the trains that were coming in and get them to site. And that allowed us to really improve both output at the Macquarie site and pick up generation, but really keep our lowest priced coal coming into the portfolio and by not canceling train routes. So it's a bit of an effort from my team and Doug's team just to really work out the value of those investments and make sure the plant could take the coal when it arrived.

Okay. I think that's clear. So that sounds like that this should be a new run rate, I guess, on that physical output from those Macquarie assets going forward. So looking at your coal supply charts on Slide 36 of your presentation, you're forecasting relatively flat Mac Gen custom loads from FY '21 to '22. And I note that one of the units at Liddell will close in March '22. So are you saying that the Bayswater will be able to ramp up output and offset that impact?

Just if you go to those forecasts and you look at the level of wind penetration, the issue that we have with the Liddell units is they're not very flexible. So they actually take a lot of -- when they're on baseload generation. So we run them and just run them at flat rate. When we take a Liddell unit off, what that actually mean is a lot of Bayswater units are actually doing the offloading to actually make space for the Liddell units to run flat. So we'll reduce the amount of offloading off the Bayswater through that period. It will be driven by the level of wind penetration to that market. So it's also subjected to change depending how much renewables gets put into that market up until that date.

The next question comes from Ian Myles from Macquarie Group.

Congratulations on the results as well. Can you just talk about on the generation side, Newcastle, when you need to make an FID decision. And I think last time we spent lots of talk about hydro. I barely saw a word hydro in the presentation. Is there sort of an update where those plans are?

Look, they're good questions, Ian. I think in terms of Newcastle, trying to remember what we've said in terms of timing of FID, but I think it's towards the back end '21? Yes. Sorry, into early '21, I think it is that we'll be getting to an FID point there. We're actively out talking to our potential EPC suppliers and looking at pricing for it. So that's a big area of focus. Look, just to probably preempt what might be a couple of questions, in this presentation, we've rearranged a little bit just some of the growth pipeline things that we've been presenting for many years. So we just felt some of the slides were getting a little bit tired. And we brought a few things into focus for this presentation, like the batteries work. Pumped hydro remains a major focus for us. In the previous pipeline slides and presentations, it was always something that was going to take some years to develop. You may have seen the owners of the Kanmantoo site talk about some of the challenges that we've had there in trying to settle arrangements there. So I'm seeing that, that in the funnel of opportunities become a little more difficult. In terms of bringing forward, on the other hand, I think Muswellbrook in New South Wales remains an excellent site for us to be looking at. But that one is more phased more for the mid-2020. So pumped hydro, in my mind, very much up there with batteries. But in a speed to execution sense, batteries represent something that you can get to market much quicker than what hydro is because hydro is a much longer, more convoluted approvals process and business case preparation versus a battery site, simplistically, you can get up and running quite quickly by comparison.

And just on the battery side. Can you -- you talked in the past about firming -- cost of firming being $20 to $30. And I appreciate battery's a sort of a complicated piece, but are they -- in the signing of the PPAs which you're achieving, are you still expecting that, that is the sort of price you're getting? Or are we seeing that decline?

I think what's -- I found interesting with batteries is a year or 2 ago, I talked a lot about, I thought they'd be on balance sheet. I thought about them in relatively simplistic terms, and that's somewhat reflected in what you're asking me there. And the lived experience with the early battery projects are coming through are things like FCAS services are becoming a big part of the revenue and profit streams to make those grid-scale projects work. So in these early days of the dawn of the battery age, some of the early projects are a much more complex bundle of revenue lines and profit streams to provide different market services as they get up and running. I think once we get a few years in and the cost of batteries comes down, the reliance upon government subsidy becomes a lot less. And if you like, the first movers have picked up things, like the FCAS service benefit and the later movers, are more focused on the time shifting of energy and the benefit that comes with it. We'll see it start to be more focused on that comparison to gas peaking, if you like. In a costing sense, so I think that sort of $20 to $30 is still not an unreasonable number to be thinking about. It will narrow from there. But Damien, do you want to...

Just so we're clear, though, on the firming cost, that was a blended price. So if you can imagine, renewables is going to lot cheaper and the firming cost is going to be a lot more expensive. It's not just a $25 price per site, it's a bundled price.

Yes. Yes. So -- but it's -- the orders of magnitude are the same. The detail, though, is swirling around in a project-by-project sense as we're getting these things moving.

Our next question comes from Rob Koh from Morgan Stanley.

And let me also congratulate you on the fine result. Can I just make sure that we understand the -- how the $80 million to $100 million Loy Yang A impact is reflected in these results? I guess does that include the little extra delay in January? And also, when we turn to the insurance recovery next year, which you said you should -- you're expecting to receive all of that, does that mean that you're claiming the full $80 million to $100 million or the -- what, I guess, I'm estimating is a net impact of closer to $50 million, if that makes sense.

Thanks, Rob. So I'll just briefly talk to it. The number we've given you is for the full impact for FY '20. So it does include that small period in January, noting it wasn't big. When you think about from an insurance perspective, what we've said is the insurance will broadly offset that impact, noting that the outage went from the '19 year into the '20 year as well. And obviously, that's also going to be net of deductibles.

Okay. So does that mean that you're claiming the full $80 million to $100 million plus, the little bit, in FY '19? Or are you claiming the net impact because you've obviously reduced that net impact through the extra generation at Mac Gen?

So just to be clear, so the impact of Loy Yang will be -- the overall impact when it was out of the market, we had offsetting generation for the rest of the fleet, so that's offsetting the result for the half. When we think about the insurance claim and just noting it is subject to ongoing commercial and sensitive matters with the insurers, that will be the claim on the outage for Loy Yang over the period of '19 and '20.

Yes. Okay. All right. And another question, if I can. Thanks for the extra color on fuel procurement over the next few years, and the gas -- the coal charts are clear. Can you remind us how much gas contracting you've got left to do?

I'm looking at Richard, but I think we, as always, we'll somewhat dodge that question because of the commercial sensitivities. But Richard, do you want to give a more elegant way of avoiding it?

I'll more than happily dodge the question. We have been active in the market with buying gas to fill the gap. We've also left a little bit of spare room, given where the prices are. So we -- the portfolio just changes over time. I think the current fall in the gas prices are -- is likely to sustain for a little while, given what's going on in the international markets. We will use that opportunity to pick up some more gas. But what we're trying to focus on is, if we can source gas, where can we sell it to and how easily can we sell it? So we'll look at things like business customers and trying to push some more gas with the business customers. And if the gas is at the right price, we'll pick up some through generation. We're not buying a fixed targeted volume, and we can -- because we can flex the portfolio around what gas is available and at what prices both through our generation and through our business customer fleet. So in answering your question, we've got adequate gas in the portfolio. And we'll adjust our buying depending on market conditions.

The build I'd sort of put on that answer too, is we've been talking about it for a little while now. What we're seeing in the gas market, I think, is a market trading much more like the electricity market nowadays. So while we have still some really nice significant legacy contracts that will go on for many years, so people will have seen them from presentations in years past, the old QGC positions are still there, and they're very competitively priced to those contracts. For the rest of the portfolio, you're seeing it more move to a bit like in the electricity market, where it's more on a 3-year horizon with the decline sort of through that horizon and constantly layering in from different sources. And the way we've been positioning our portfolio with a particular emphasis on storage. So WUGS is really starting to come in, Iona is starting to really come into its own over the next year or 2. We've got the Newcastle gas storage facility, other optionality like that. We're leaning into storage and optionality that allows us to have a flexing, rolling portfolio. So it will take time for gas price market change to roll through that portfolio. But it will be rolling through, not dissimilar to what happens in the electricity world nowadays.

Okay. Great. That's not a dodgy answer at all. It's very, very helpful. Just a final question. I guess you've got a refreshed management team now all in place or coming into place. Should we be anticipating any kind of resegmentation of the accounts?

So Rob, I'll answer that one. What you will expect for the end of June will be simply a summation, if you like, of group ops and wholesale. That's how we'll look at reporting 30 June, but you will still see the details of group ops and wholesale for 30 June.

I'm not speaking too much for Damien because I know this will come up a lot. I would think of all of it as just adding a new subtotal of wholesale and operations with the same amount of detail rather than a rearrangement of detail, which I know creates issues for just keeping spreadsheets up to date.

Our next question is from Pete Wilson from Crédit Suisse.

A comment on operating costs, if I could. So they're up 5% if you strip out pcp one-offs. I mean it's fair to say, missing targets that were set a few years ago and we're still not getting any benefit from the significant capital investment in digital and IT. So I'm just wondering whether we should all start reassessing our expectations for declining total operating costs in the next few years?

Look, I'll take that one, Peter. Look, what we've said and continue to say, we will have a year-on-year cost savings as you look forward to the end of this year. We are seeing the benefit of the work we did, particularly digitization in CXT, coming through in customer markets. And combined with that, because of the lower market activity and churn, you're starting to see that flow through the books. So I think churn is down around about 15%, 16%. And we are managing hundreds of millions of transactions per annum. So that digitization is absolutely important as we continue to look forward and evolve our products and services. I would say that the money we spent on CXT and other systems upgrade is paying for itself, and will continue to pay for it as we look forward.

Okay. And where should we see that though? Because on the waterfall you've put in on Slide 22, the only negative cost is a reduction in market activity. And then all of the other ones are increases in cost including investment in digital, data and IT. Where is -- where are the savings in CXT in that waterfall?

Well, I think much of them is coming through that reduction in market activity. We haven't sort of broken that out any further, but that's where you're seeing it because things like call volumes are down, I think, 19% in the call center. That's one of the big ones and that sort of -- that piece, therefore, because it's digitized means we can start to really see that cost come out of the organization.

I mean isn't a fair chunk of that, though, just reduced market churn?

Oh, it's absolutely a combination of both, yes. And we've always said that market activity as it comes out, therefore, our costs will also reduce at the same rate.

Okay. So in FY '21, we should still be expecting a reduction in total operating costs, should we?

In the customer markets business, yes, that's right.

The entire business?

We will be -- we're not going into comment into FY '21. What I've always said is we'll have year-on-year cost savings for this year. We'll provide guidance into the market when we get round to the August results.

Our next question comes from Mark Busuttil from JPMorgan.

Just a question about the insurance claim, and this might be a relatively simple question. But do you intend to include that in underlying earnings for whatever guidance you might provide for '21, which would therefore mean you sort of unwind $80 million to $100 million in 2020 costs and add that amount into next year? So it could be an uplift in the order of about $160 million to $200 million on underlying impact, everything else being flat.