Thank you for standing by, and welcome to AGL Energy's 2022 Full Year Results Briefing. All participants are in a listen-only mode. There will be a presentation followed by a question-and-answer session. If you wish to ask a question, you will need to press the Star key followed by the number one on your telephone keypad.
I would now like to hand the conference over to CEO and MD, Mr. Graeme Hunt.
Good morning, everyone. Graeme Hunt speaking. Thank you for joining us for the webcast of AGL's full year results for financial year 2022. Well, I'd like to begin by acknowledging the traditional custodians of this land where I'm presenting from today and pay my respects to their elders past, present, and emerging. I would also like to acknowledge the traditional owners of the various lands from which you are all joining from and any people of Aboriginal and Torres Strait Islander origin on the webcast. Today, I'm joined by Damien Nicks, our CFO, Jo Egan, Chief Customer Officer, and Markus Brokhof, Chief Operating Officer. I'll get us started before handing over to the team, and we will have time for questions at the end.
The FY 2022 results reflect the resilience of the business against the backdrop of a very challenging energy industry and market conditions that intensified in the second half. This included both geopolitical instability and international supply constraints that drove global commodity pricing significantly higher, as well as the unprecedented market volatility culminating in suspension of the market in mid-June. Our FY 2022 underlying profit after tax was AUD 225 million, down 58% on FY 2021. As anticipated, this lower result reflected the step-down in trading and origination electricity earnings due to lower realized contracted and wholesale customer prices, increased capacity costs to cover periods of peak electricity demand, as well as the nonrecurrence of the Loy Yang A Unit 2 insurance proceeds received in FY 2021.
Other factors negatively impacting the result included planned and unplanned outages, unprecedented market volatility and suspension, milder weather, and margin compression via customer switching. While the second half has been one of the most challenging and complex periods in AGL's operating history, the underlying strength of our business remains. Our low-cost base load generation position, supported by long-term owned and contracted fuel supply, our large and diversified customer base, and strength of our risk management framework, have all enabled us to navigate what has been an extremely difficult period for all market participants. They will be the foundation on which we move forward into FY 2023 and beyond. Pleasingly, against this backdrop, cash conversion has remained strong, driven by solid working capital outcome.
Today, we are confirming a final dividend of AUD 0.10 per share unfranked, bringing the total dividend for the 2022 financial year to AUD 0.26 per share. Turning now to some business updates. Total services to customers remain stable at 4.2 million, a good result amidst the period of unprecedented market volatility. Encouragingly, our net promoter score, which is a measure of customer loyalty, remains at historical year-end highs at +6. More customers are interacting with us on digital channels than ever before, with more than 1 million customers using the AGL mobile app and My Account services. Our large, diverse and loyal customer base, coupled with prudent margin management, has positioned us well despite increased volatility and churn in the market. This year, we also made solid progress in advancing our high-quality development pipeline.
This included the Torrens Island grid-scale battery, which is expected to be operational in the first half of 2023, the Broken Hill battery, which recently reached final investment decision, and the grid-scale batteries at the Liddell and Loy Yang sites, which have both received planning approvals from respective state governments. In addition, our ongoing focus on cost discipline has enabled us to achieve AUD 150 million of targeted operating cost reductions in FY 2022. We're also on track to achieve a reduction of AUD 100 million in sustaining CapEx by the end of FY 2023. You'll also see that this year we have completed the sale of some of our non-core assets. The Newcastle Gas Storage Facility is no longer for sale, which Damian will cover shortly.
In May, the AGL board made the decision to withdraw the demerger proposal that would have seen AGL separated into two separate listed entities. At the same time, we announced a review of the organization's strategic direction and a board and management renewal process, both of which are well underway. In relation to the review, this is being overseen by a board subcommittee and is actively considering multiple options for how an integrated AGL can deliver long-term value for shareholders. This is progressing well, and we look forward to updating shareholders in more detail in late September, along with an expected update on FY 2023 guidance. Given the status of the review, and in order for AGL to manage its ongoing continuous disclosure obligations during this period, the board has determined that the dividend reinvestment plan will not operate for the final financial year 2022 dividend.
It is our intention to reinstate the DRP when circumstances allow. The selection process for a new chair is well advanced, and we expect to announce an appointment before the AGM. A global search for a new managing director and CEO has also commenced. Looking forward, we've seen a strong uptick in spot and forward electricity prices. AGL remains largely hedged for FY 2023. Beyond this, we are well-positioned from FY 2024 to benefit from sustained higher wholesale electricity prices as historical hedge positions progressively roll off. Importantly, the strength of AGL's long-term owned and contracted coal position and gas supply contracts ensures that we are well-positioned to manage the impact of the rise in global commodity prices on our cost base and continue to provide affordable and reliable electricity to our customers.
As I touched on earlier, the second half of the year was dominated by a series of significant industry events and regulatory interventions, some unprecedented, which impacted all energy market participants. I'd like to take a moment to discuss these in more detail. From early March, we saw a sharp rise in global coal and gas pricing, driven primarily by constrained supply on the back of the Russia-Ukraine conflict, as well as ongoing supply chain delays caused by the resurgence of COVID-19 subvariants. In the fourth quarter, the confluence of this higher global commodity pricing environment, as well as a series of planned and unplanned thermal generator outages, led to an elevated wholesale electricity pricing environment within the NEM. The outcome was a series of major industry events that are detailed on the left-hand side of this slide.
In an unprecedented move, AEMO responded to this elevated pricing environment by initially triggering administrative pricing and then market suspension due to the challenges in market operation. At this same time, we saw a series of electricity and gas retailer of last resort or RoLR events, as well as selected retailers immediately withdrawing their discounted market offers and defaulting to regulated pricing. Despite these very significant events, I'm pleased to say the underlying fundamentals of our business remain strong and resilient. Firstly, we have a large and diversified customer base, with over 4.2 million customer services provided nationally, and importantly, we have ensured continuity of energy supply to customers impacted by RoLR events.
Secondly, our two major thermal generators, Bayswater and Loy Yang A, are the lowest cost thermal generation assets in their respective states and are underpinned by strong long-term fuel supply arrangements with minimal exposure to global commodity pricing. Bayswater is supported by the long-dated production cost linked Wilpinjong coal supply agreement coupled with an available coal stockpile. Loy Yang A, the NEM's lowest cost thermal generation asset, is well supported by the security of supply from its wholly owned adjoining coal mine. The critical role that this consistent coal supply has played in positioning AGL well in a very difficult market certainly should not be underestimated. Thirdly, AGL's high-quality growth pipeline of wind, battery, pumped hydro, and low-carbon firming projects continue to be progressed. These are being progressed as part of the redevelopment of our three major thermal generation sites into industrial energy hubs.
Complementary to these developments is our access to the 3.5 GW Tilt Renewables development pipeline. Finally, of significant importance is the strength of our risk management practices with prudent margin management in place, ensuring retail strength and stability in highly volatile markets. We certainly have seen the real impact of insufficient risk management through RoLR events here in Australia and similar examples in international markets. Against a very challenging backdrop, our integrated energy team has managed AGL's risk position and mitigated downside by ensuring we were largely hedged across FY 2022 and FY 2023. As mentioned from FY 2024, we are well-positioned to benefit from sustained higher wholesale electricity prices as historical hedge positions progressively roll off.
Continuing the discussion on market conditions, the left-hand side of this slide shows the very sharp rise in forward pricing seen in the last quarter, especially in New South Wales, where forward pricing rose to AUD 200 per megawatt hour for FY 2023. Pleasingly, the dotted line indicates strength in wholesale pricing for both New South Wales and Victoria into FY 2024. On the right-hand side, you can see the materially elevated volatility since mid-2021, driven primarily by multiple forced thermal generation outages through this period, as well as the rising penetration of new renewable generation, introducing variability on the supply side for electricity. Of particular importance here will be the development of our grid-scale battery portfolio.
Once operational, the 250 MW Torrens Island battery will be key in firming and providing ancillary services in South Australia, which has one of the highest penetrations of renewable generation in the world. Moving now to three core operational areas, safety, customer experience, and employee engagement. Encouragingly, our total injury frequency rate per million man-hours worked decreased to 2.1 for employees and contractors combined for the year. There's been a material improvement in safety performance over the last two years compared to FY 2019 and 2020, reflecting our acute focus on safety culture. That said, we continue to strive for further improvement in this area. As mentioned, our strategic net promoter score remains strong at +6, reflecting our unwavering focus on our customers, especially in these challenging times, together with the rewards of our significant investment in the digitalization coming to fruition.
Our employee engagement measure has fallen 5 percentage points from FY 2021. While disappointing, this result is not unexpected given the amount of change and disruption within the business over the last 12 months, primarily associated with the demerger proposal and the uncertainty this created for many. Our people have shown great resilience over a very challenging 12 months, and as we continue to move forward, we are actively working with leaders to strengthen employee engagement and ensure our valued employee base is well supported. This slide shows a further summary of our financial results, which Damien will cover in more detail shortly. Before I hand over to Damien, I'd like to delve a bit further into the four focus areas shaping the review of strategic direction.
The aim of this review will be to answer some of the most substantial strategic questions facing an integrated AGL, delivering long-term shareholder value while continuing its responsibility and leading role in helping Australia meet its future energy requirements in the energy transition. The first focus area considers which existing strategies should be continued in an integrated business, including those which may be accelerated and expanded. For the second, we are reviewing the best decarbonization pathways available to an integrated AGL and how these can be optimized to benefit both shareholders and the communities in which we operate. The third area is about determining the optimal asset portfolio in a decarbonized and decentralized market that best aligns to our decarbonization objectives.
Finally, the fourth considers how our capital structure as an integrated company can be optimized to sufficiently fund existing operations and, importantly, our significant growth ambitions. The review aims to outline a clear way forward for an integrated AGL embracing the energy transition, delivering for our customers, and creating long-term shareholder value, and we look forward to sharing the initial outcomes of the review in late September.
I'll now hand over to Damien to take you through the financial results in more detail.
Thanks, Graeme, and good morning, everyone. I'll begin by taking you through group underlying profit in more detail. As expected, the second half earnings were lower than the first, primarily due to increased capacity costs to cover peak electricity demand at higher wholesale electricity prices. However, plant outages in the fourth quarter, combined with market volatility, resulted in underlying net profit finishing towards the bottom end of expectations, with AGL's hedging and trading performance offsetting some of this impact. The AUD 312 million reduction in underlying NPAT was largely driven by forecasted lower realized wholesale electricity prices, generation performance, and the non-recurrence of the Loy Yang A Unit 2 insurance proceeds received in FY 2021.
Looking at the chart from left to right, within customer markets, consumer electricity was down due to lower average demand from milder weather, higher cost of energy associated with increased solar volumes, and margin compression with customers switching to lower priced products. Consumer gas margin was also lower, primarily due to the milder weather. The reduction in customer markets OpEx was attributable to a decrease in net bad debt expense, as well as lower campaign and advertising spend achieved via digital and marketing campaign efficiencies. The largest driver of the year-on-year profit reduction was in trading and origination electricity, with a step-down of AUD 350 million due to lower realized wholesale and customer prices as anticipated. This was partly offset by lower unit fuel costs at AGL Macquarie, with a higher proportion of coal deliveries from legacy contracts compared to the prior year.
The net impact of other key items in trading and origination electricity operating performance was AUD 91 million lower. This included favorable trading performance in the first three quarters of the year, which was more than offset by the impact of the Loy Yang A Unit 2 and other unplanned outages and June trading, where we were a buyer of electricity at elevated spot pricing. Please note that a net AUD 10 million has been recognized this year in relation to the cost of market suspension, less what we anticipate recovering from our customers. It is probable that further claims will be approved by AEMO and these will be recovered from market customers, including AGL in a future period. Pleasingly, a strong reduction in integrated energy OpEx was largely driven by lower contracts and material costs, as well as targeted efficiencies across the portfolio.
Moving across to the group-wide section of the chart, around half the reduction in centrally managed expenses were benefits from lower employee provisions and labor costs, not all of which will be retained into FY 2023, as some are non-recurring. The balance of the reduction reflects the benefit of targeted cost initiatives as well as lower IT and consulting expenses. As expected, depreciation was higher due to the accelerated closure dates for Bayswater and Loy Yang announced in February. Finally, the reduction in tax expense reflected the fall in profit together with a lower effective tax rate due to prior year adjustments, including research and development benefits. Now, let's take a look at the reconciliation between underlying profit and statutory profit, which will be included due to the sheer size of movements.
The items on the left were largely driven by external and market factors, whereas those on the right represent structural or operational decisions made by AGL. Starting on the left, the movement in the rehabilitation provision was largely driven by change in the discount rate used to assess the present value of our future obligations. The owner's contracts gain was due to higher forward electricity and LGC prices in relation to AGL's long-term renewable power purchase agreements, as well as updated discount rate used to value the liability. The financial instruments gain represent the positive fair value movements in oil and gas derivatives due to higher forward pricing for these commodities. AGL's electricity buy and sell contracts largely offset, resulting in a relatively flat position.
Moving to the right, during the year, we fully impaired the Newcastle Gas Storage Facility. This was previously held for sale and is now fully impaired due to an unsuccessful sale process, combined with a challenging market conditions for this type of gas storage facility. In addition, we recognized an impairment for surplus office capacity, as well as a small impairment reversal relating to AGL's investment in Tilt. Separation costs of AUD 89 million post-tax, or AUD 125 million pre-tax, were incurred in relation to AGL's proposed demerger. The reintegration of the business will be completed during the early FY 2023 and incur additional costs to finalize, and we are working to unwind a number of duplicated costs. In total, we expect demerger costs to be approximately AUD 145 million, lower than the AUD 160 million advised in late May, and these will be treated as a significant item.
Finally, restructuring costs were incurred in relation to organizational changes during the year, which resulted in the reduction of approximately 300 roles. Costs were also incurred in relation to the integration of recent acquisitions. Pleasingly, we delivered on AUD 150 million of targeted operating cost reductions in FY 2022, excluding the benefit of improved COVID-19-related net bad debt expense recoveries, as well as a benefit arising from labor vacancy and employee provision movements, both of which are not expected to reoccur in FY 2023. Cost out largely involved a decrease in labor, operational savings, and discretionary spend across all business units. This was partially offset by inflation, as well as incremental costs associated with the Solgen, Epho, and Energy360 acquisitions, and operating costs associated with the growth of AGL Telecommunications and the Retail Next program.
Looking forward, we expect a small step-up in operating costs for FY 2023, albeit this is planned to be lower than CPI after adjusting for the non-recurring benefits in FY 2022. Encouragingly, we will also deliver on our AUD 100 million sustaining CapEx reduction objective as forecast for FY 2023. Noting that this is against the FY 2021 baseline, with savings predominantly related to the planned closure of the Liddell Power Station and ongoing major outage management improvements. Importantly, our investment in maintenance CapEx across our generation sites remains stable, affirming our strong commitment to safe operations. Growth CapEx this year is focused on flexible storage, including the Torrens Island and Broken Hill batteries, as well as smaller flexible generation investments at AGL Macquarie.
Now turning to cash and debt. Net cash from operating activities was 2% lower in FY 2022 due to lower underlying EBITDA, albeit this was offset by strong working capital outcome driven by favorable creditor balances on the high June energy prices, effective management of coal and green inventories, and higher inflows of variation margin due to an increase in the forward curve. Lower cash tax paid was consistent with the reduction in earnings and the utilization of prior year tax losses. Investing cash flow reflected growth in sustaining CapEx and the investment in Tilt Renewables, partly offset by the sale of investments in the EIP fund, Activate Capital Partners, and ecobee, contributing AUD 155 million. Financing cash flows reflected the net repayment of debt, noting dividend payments were underwritten in the financial year, conserving cash. Pleasingly, cash conversion increased due to the strong working capital outcome.
Looking ahead to FY 2023, on cash conversion, we note that the potential for the reversal of favorable market-related creditor balances and margin positions in FY 2023, which may impact the cash conversion rate. This will be partly offset by a smaller contribution from the accounting for onerous contracts due to higher forward price expectations for electricity and green products. Turning to debt and funding, despite the challenging energy industry and market challenges of recent months, AGL still retains sufficient liquidity and headroom under its Baa2 credit rating. Since the end of the financial year, AGL has rolled over AUD 200 million of revolving bank facilities and maintains strong banking group support. AGL will assess its capital structure as part of the review of strategic direction with an intention to lengthen debt tenure.
I'll now hand over to Jo and Markus, who'll provide a full year overview on customers, operations, and portfolio generation.
Thank you, Damien, and good morning, everyone. As Graeme and Damien have discussed, market conditions during FY 2022 have been challenging, particularly in the second half. Despite these challenges, customer focus has remained our top priority, and as a result, we have continued to deliver positive customer advocacy and maintain stable customer services amid significant volatility. We have also improved the fundamentals of our business, further lowering operating costs through digitization and automation, enhancing customer experience, and extending our product offering through growth in integrated energy solutions. AGL has a proven track record of navigating market volatility with a resilient business model and stable customer base. Our performance in FY 2022 has been underscored by the successful progression of our integrated multi-service retailing strategy and improved customer experience.
Total services to customers remain stable at 4.2 million, with a marginal reduction in energy services more than offset by a 50,000 increase in telecommunication services. At the same time, disciplined margin management delivered an improvement of AUD 22 million to consumer gross margin in the second half. This solid result demonstrates AGL's ability to both support customers and carefully manage value amidst a period of heightened market volatility. Going forward, we will continue to responsibly grow our customer base while prudently managing customer lifetime value. Encouragingly, despite intense competition, our churn spread to rest of market improved to 4 percentage points. Our multi-service offering has contributed to this favorable result, with over 20% lower churn rates for customers holding both energy and telecommunication services.
We also experienced a 39% reduction in total complaints year-on-year, and a 57% reduction in ombudsman complaints over the last three years. AGL is proud to have the lowest number of residential electricity complaints of any tier one retailer in the most recent reporting cycle. Additionally, we recorded our fourth consecutive end-of-year improvement in strategic NPS with a score of +6. Another highlight is our sustained focus on cost discipline that has resulted in a 24% decline in net operating costs per service since FY 2019. This has been driven by a continued focus on marketing optimization, digitization, and a reduction in net bad debt expense due to strong collection performance. Digital improvements have seen adoption grow, resulting in over 1 million active mobile app and my account users.
When compared to its peers, AGL has Australia's number one mobile app with a 4.7/ 5 star rating on the App Store. AGL has continued its retail transformation program over the past year to strengthen its core customer business and support future energy needs. We are driving efficiency across the business by simplifying products, business architecture, and technology to lower cost to serve, improve speed to market, and enhance the customer experience. We will deliver a step change in customer experience through improved ways of working, including how our agents serve our customers. This program is already delivering benefits and our simplification activity is well underway. Process enhancements and product rationalization have delivered improvements in handling times and improved speed to market of over 30%.
Additionally, we have commenced the uplift of our middle layer of technology through implementation of our new CRM product catalog and intelligent business process management capability. This flexible and modular technology architecture will enable adaptability for future market innovations. Looking further forward, connectivity to remotely manage distributed energy resources such as batteries and electric vehicles will be critical, particularly in peak demand periods. AGL's NEO platform enables management of such assets and is already delivering value through orchestration of these assets connected via our virtual power plant. We are also partnering with Kaluza to remotely optimize energy usage for electric vehicle owners through a smart charging trial. Kaluza localization continues and is on track under the OVO Energy Australia brand. We are retaining optionality in this new energy technology to complement our existing architecture and further accelerate growth in new value pools.
Our customers are increasingly seeking advisory and support on low carbon solutions as they navigate the trends of decentralization, decarbonization, and digitization. AGL is responding to these needs by rapidly expanding our decarbonization and energy management solutions. This allows us to capture value through increased demand from electrification and create new value for both AGL and our customers as we support them through the energy transition. Our virtual power plant has grown 65% to 215 MW of decentralized assets under orchestration, underpinned by our NEO platform. This includes our Peak Energy Rewards program, our solar and battery bundles, and continued growth in our commercial and industrial demand response and orchestration products. This portfolio provides us with flexibility to reduce peak demand on the energy system, access supply during peak times, decrease emissions, and provide financial value to our customers and AGL.
AGL continues to be the market leader in commercial solar, with strategic investments supporting a 236% year-on-year revenue growth. We have grown our monitoring and management portfolio of customer energy assets to more than 140 MW. This establishes long-term relationships with customers and creates a platform for growth as customers expand current capacity, replace older systems, and add storage and charging solutions. We have continued to expand our decarbonization offerings with an increase in carbon neutral and green products across all customer segments. In addition, more recent acquisition of Energy360 has further expanded our offering in biogas to support customers in harder to abate sectors. We believe there is a compelling business case for biogas in the current East Coast market and see an opportunity to deliver value directly with customers.
In summary, AGL is well-positioned to weather any prolonged periods of market volatility. Our scale, enduring commitment to customer, and deep energy expertise, alongside our compelling suite of decarbonization products, ensures we are well-positioned for future growth.
Now over to Markus.
Thank you, Jo, and good morning, everyone. I will provide an overview of our integrated energy performance. The integrated energy business unit covers AGL's trading, origination, major projects, and operation business areas. As you can see, some of our key operational metrics have not had the results we were targeting. Despite the good start to the year, our generation volume and our thermal fleet's commercial availability are both slightly down year-on-year. These metrics reflect the challenging and unprecedented time in the market, particularly in the last quarter. I will talk more about the drivers of the market environment and how it impacted AGL shortly. Before that, I wanted to acknowledge that safety remains a critical priority for AGL. I'm proud of the fact that we have delivered a high volume of work on our complex plant and unplanned outages without a significant incident impacting safety.
It is a testament to our people staying focused in a period of challenge for our company, our assets, and the market. This positive performance led also to a reduction in our injury frequency rate over the year and trending down over the last couple of years. We will look to continue this good trajectory in AGL's safety performance. The other highlight for integrated energy in the challenging second half of this year has been the performance of the trading team to risk manage AGL's portfolio position and mitigate further downside and capturing the upside as market liquidity allowed. The very real impact on insufficient risk management can be seen elsewhere in the Australian and international markets. While some floating position is important to enable value capture, excess exposure to wholesale market prices can pose a risk in an environment such as that seen in the last quarter.
This approach to dynamically hedge the portfolio position has enabled AGL to protect against some of the downside risk we have seen in energy markets, while capturing potential value through trading at the appropriate time, as is represented by the favorability of the energy-related unrealized fair value for oil, coal, and electricity derivatives. A further consequence of movements in future electricity and environmental price expectation has been a substantial reduction in the provision for onerous contracts across future periods. I will now cover this year energy market environment in more detail. Prices have trended upwards throughout financial year 2022, with an expected uplift during the summer months. In the final quarter of this year, we saw unusual volatility and price increases, somewhat similar to the final quarter of the prior year.
Q4 is normally a shoulder season where plant operators often have plant maintenance and major outages in preparation to ensure availability during peak periods of summer and winter. However, in both financial year 2021 and financial year 2022, we have seen this shoulder period became a critical period in the market and a time of price spikes. This year, that becomes so extreme as to see the market operator issue an unprecedented multi-state market suspension. In FY 2022, this spike was driven by a confluence of international and local factors occurring at once. Starting with the international drivers, we saw elevated global commodity pricing, such as coal and gas, due to change in trade flows on the back of the Ukrainian war, as well as COVID-19. Coal plants in the market that are reliant on supply from uncontracted coal or export-linked pricing suffered a significant spike in fuel costs.
Gas-fired generation became expensive in the tight market, with the marginal gas fuel input costs equating to around AUD 400 per megawatt hour. Fuel supply in the market was further challenged as wet weather, particularly in New South Wales, further interrupted coal supplies, labor access to plants, as well as COVID-19 absenteeism. On top of these fuel supply challenges, increasing the cost of electricity generation, multiple players in the market had planned and unplanned outages of an aging thermal fleet in the NEM. This further tightened supply and destabilized the demand and supply balance. While AGL has a well-contracted and proximate coal supply, we suffered from the confluence of planned and unplanned outages impacting our availability and putting us short to a tight market. The total availability of our fleet was positive in the first three quarters of the year.
In the critical summer months of January, every category's availability was over 80%. In a normal year, this is what we would be aiming for as summer presents peak demand, so it is critical for us to be available for the market. It would be common practice to have a reduced availability in the shoulder seasons of Q2 and Q4 as plant outages for regular asset maintenance occur. However, unfortunately in Q4, we have seen a confluence of prolonged plant outages, such as Bayswater Unit 3, with long and short duration unplanned outages, including but not limited to Liddell. This is reflected in the reduced coal fleet availability.
There were two key causes of the forced outages, the generator earth fault in Loy Yang A Unit 2, which resulted from a design error in 2019, and the rise in boiler tube leaks across Liddell, Bayswater and Loy Yang. The unplanned outage at Loy Yang A Unit 2 has resulted in a revised earnings guidance, which was released to the market in May. In line with our update to the market in June, we expect Loy Yang A Unit 2 to return to service in the second half of September. The boiler tube leaks are a critical area for AGL to contain and manage into the future, particularly in Bayswater, which underperformed relatively to expectations in FY 2022. To support in monitoring and improving operating conditions, AGL has introduced digital twins for both its Loy Yang A and Bayswater plants.
These were established during FY 2022, and the digital twins will enable AGL to reduce physical testing and instead optimize the operating conditions and capital works. The digital control systems and monitoring systems are being upgraded so we can better understand the health of the system in real time and take action quickly. Film-forming substances have been introduced into our boilers to reduce the rates of future corrosion. We've introduced acoustic monitoring in the boiler so that we can detect early signs of tube failure and make the right decision. Milling routine work has been improved to ameliorate common defects. For example, optimized programs of work on oil filters and feeder belts. As we look to improve availability, AGL will be well-positioned to capture opportunities in the market if the market liquidity allows.
As we look at our overall generation and customer book, AGL is naturally overall long in the market, which means we are able to see longer-term value from the rise in wholesale electricity prices. However, there are a few nuances to explain on this. AGL's customer book demand covers the majority of our generation volumes through a combination of large wholesale, commercial, industrial, and residential customers. This means that AGL has a natural hedge and is not fully exposed to highs and lows of the market. As it is naturally long, AGL also has a floating position for further value creation in the wholesale market. While it provides a partial hedge, the customer book does not immediately reflect the wholesale price environment.
The nature of price regulation and contract lengths means that prices take a minimum of 18 months to flow through to customers, resulting in a lagging effect to price upside or downside to be reflected in AGL's book. It is important to note that our trading team does actively manage both the fixed and floating position against market dynamics, whereby we use, in addition, other trading instruments, such as caps to secure capacity position, demand response, weather derivatives, and our settlement residue auction units to balance the portfolio. Their price is reduced against our plans, long-run marginal cost based on spot coal, or there appears to be an opportunity not being priced into the market. AGL has bought back position in the rising market to manage and create additional extrinsic value.
For example, due to the high long run marginal costs of spot-based black coal generation, we were optimizing our portfolio by buying the electricity directly on the market. I've spoken about the volatility of the market already, but I'm pleased to report that AGL was able to weather the rises in global fuel prices well due to our prudent risk management and hedging strategy. While it has been a challenging second half, we can see from the number of Retailer of Last Resort events that there was much larger potential downsides in absence of a sophisticated risk management approach or poor speculation. Our long-term fuel supply strategy protected AGL from further impacts of price volatility right away. We have been positioned well in a difficult market, thanks to our competitive long-term coal off-takes.
For Bayswater and Liddell, our reprofiled supply contract has provided consistent production cost link coal supply, which combined with AGL stockpile, has meant we were unaffected by rail logistics and price rises that other thermal plant was exposed to. Our owned and operated brown coal mine adjacent to Loy Yang A power station has provided an advantaged cost position and security of supply. It is not only coal that has been a challenging commodity for the energy sector. Gas has been tight in FY 2022 and will continue to do so as international prices increased significantly. AGL has been well-positioned during this time through an actively contracted gas supply book and storage capacity with the majority of its committed gas demand, such as mass market and gas to power demand, met by long-term gas supply agreements.
Further, the trading team's activity to hedge the oil link contracts to manage exposure during the low prices of the pandemic has led to further value in the book. While it has been a challenging year on the generation side, some of the core underlying strengths of AGL in our commercial and risk management have delivered positive outcomes that reflect the sustained long-term value in AGL. A key achievement in FY 2022 has been the continued progress on our project pipeline of 2.9 GW and energy hub strategy. Our focus has been on adding more renewable and low carbon flexible capacity into our portfolio and gaining partners to join us in our plan to transition our thermal sites into low carbon industrial energy hubs.
The development of our energy hubs in the Latrobe Valley, Hunter Valley and Torrens Island is crucial to enabling our growth while continuing to provide for the low carbon energy demand. Our energy hubs are progressing well, with key MOUs signed and construction on the Torrens Island and Broken Hill grid scale batteries expected to be complete in the second half of FY 2023. One of our priority focus area has been developing partnerships with organizations that share our interest in driving the energy future, and these partnerships are critical to our development pipeline. Some of these sizable partners include Fortescue Future Industries, Osaka Gas, SK ecoplant, Vattenfall, NuRock, Idemitsu Kosan, APA Group, and Spark Renewables.
FY 2023 will see a number of new projects and developments for AGL as we look to continue to add flexible capacity and renewables to our portfolio. Hydrogen is an important industrial cluster as well targeted in domestic and international markets. I look forward to advancing these projects and seeing the energy hubs come to life over FY 2023.
I will now hand back to Graeme to provide a view of our outlook.
Thanks, Markus. In closing, I'd like to reiterate the underlying resilience of our business amidst these challenging times. In particular, the strength of our low cost generation position, supported by long-term contracted and owned fuel supply, which has helped AGL to weather the sharp rise in global commodity input prices, as well as our robust risk management framework, with prudent margin management in place, ensuring retail strength and stability in a highly volatile market. Looking forward to FY 2023, we expect earnings to remain resilient on the back of AGL's largely hedged position.
Other key impacts for FY 2023 performance to consider include the return to service of Loy Yang A Unit 2, anticipated in the second half of September, the persistence of market volatility and forced outages impacting operational performance in July 2022, and the closure of the remaining three units of Liddell Power Station in April 2023. Underlying earnings in FY 2023 will also be impacted by the onerous contract provision adjustments in the current year, as well as a small step up in operating costs. Albeit these are expected to be lower than CPI after adjusting for the non-recurring benefits in FY 2022. Importantly, we've seen a strong uptick in forward wholesale electricity pricing for FY 2023 and FY 2024, and encouragingly, AGL is well-positioned from FY 2024 to benefit from sustained higher wholesale pricing as historical hedge positions progressively roll off.
As previously disclosed, we expect to provide FY 2023 guidance in late September in conjunction with the initial outcomes of the review of strategic direction, which we look forward to presenting to our valued shareholders. Thank you for your time today, and we're now open to any questions.
Thank you. If you wish to ask a question, please press star one on your telephone and wait for your name to be announced. If you wish to cancel your request, please press star two. If you're on a speakerphone, please pick up the handset to ask your question. Our first question comes from Tom Allen at UBS.
Thanks, James. Good morning, Graeme, Damien, and the broader team. My first question relates to how AGL is protecting itself from exposure to unplanned generation outages. Clearly, market dynamics are requiring baseload coal generation be operated in ways that it probably wasn't designed. Now, Markus mentioned some engineering initiatives on the call to better identify tube leaks. But are there other measures, perhaps through trading strategies, perhaps, that can further mitigate financial exposure to these outages?
Yeah. Thanks, Tom. I'll start, and then I'll hand over to Markus. I think, you know, one of the things that we did during this year was the upgrade to the digital control system on Bayswater 3. One of the underlying elements of the business case for that was the ability for us to actually ramp up and ramp down that unit. That has some opportunities there, obviously, to seek to additionally balance our portfolio when we're running and to also take the load off when it's clear that we're not actually getting paid, if you like, for the electricity generated during the day in those units. That's one of the things that we're doing.
Clearly, beyond that, how we manage the flexible portfolio that we've got helps and how we make sure that we focus our maintenance programs, sustaining capital going forward. Markus touched on some of those things in his speech, but perhaps he can add to that now.
Yeah. Thanks a lot, Graeme. Yeah, it's true that I have proposed some or we are now implementing some technical measures, which I have described in my speech. For sure, we have reviewed very thoroughly also our planned outage and major outage schedule for this financial year. Try to avoid overlaps of units which are going out. In addition, also where it was possible, we have unblinded some hedging positions in order to make sure that if volatility comes we are able to capture this, and we are not aggressively hedged. This were measures on the trading side, which we have taken. I would still outline, you know, there was an extreme situation in Q4.
Normally we can with our interconnector capacity, particularly between SA and Victoria and so on, and also New South Wales, we can still with our flexible portfolio, for sure, make up some shortfalls. That's something which we are doing constantly. You know, as in an extreme case, as we had various forced outages, particularly in June and July this year, we were not able to to replace particularly the energy which we lost. That was an extreme situation. I don't expect that this will happen this year.
Okay. Thanks, Markus and Graeme . Just one more follow-up question. Just one on your gas portfolio. I just was seeking some clarification of slide 23 in your presentation. If FY 2022 gas portfolio demand was about 153 petajoules, is that slide suggesting that your portfolio demand will drop by about 20% or, say, 30 petajoules into FY 2023, but you don't need any additional supply over the next 12 months? From 2024 and 2025, AGL is flagging that it may require a further 30-45 petajoules per annum each year over those two years.
I think it's a bit reflected. If you look thoroughly on the slide 23, and if you look what we have signed in addition over the past years, if you look just the GSAs signed in financial year FY 2022, I think it's clear that we are not over-hedging our portfolio and just buying energy. Because most of the C&I customer and wholesale customers are contracting one or two, three years, and we are not now buying all the gas expecting that everything will be renewed. For sure, our ambition, and that is, I think, what you are asking, the uncontracted volumes going forward in FY 2024 and FY 2025, if we would renew all the contracts which we have currently, yes, we are short.
You know, we will successively fill up our portfolio as we have done also in the past. There is no change in procurement and so on. We have always said some of the legacy contracts have rolled off in the past. Yes, we have to replace some volume, but it's depending how much our customer portfolio will stay with us or will grow.
Okay. Thanks for clarifying that, Markus.
Thanks, Tom. Next up we have Ian Myles from Macquarie.
Yeah. Thank you, guys. Just a couple things. Can you maybe just give a bit more color in July? How short did you end up in the month of July in energy that you had to buy in the market? Because can we take from the commentary about hedging that you've actually managed to cover a lot of those positions prior to the outages?
I think when you look, I think I will not now, even it's this financial year, I will not disclose the secret. You can look it up in AEMO. I think we were briefly, I think for 10 days, we were short. We were units with energy were out 1,800 MW. But to be honest with you, we are normally not hedging the full Liddell units. So, you know, maybe there was a shortage of 1,200 MW briefly for 10 days. For sure, certain position was exposed, and capacity could be covered, but not the full energy content.
I think, Ian. Damien here. I mean, that's one of the reasons we called that off. Some of the operational challenges we saw in June rolled into July, and that's why we're calling it out in that outlook position.
Okay. From a go-forward position, can we assume that you've really played taking, like, an N-1 position in all markets? You've effectively got one turbine sort of sitting in spot markets.
You know, I will not comment on this because normally we not disclose our hedging strategy. Somehow you are going in the right direction. It's a bit different, you know. It's also seasonal, and also a bit different state by state. Yeah.
I think, Ian, we also think about Liddell differently as well as an aged unit as well.
Okay. One other bit left field is the Hunter gas pipeline which is being proposed. Does that start a change of thought process about what you might use Liddell for, and whether a gas plant could be put there or other opportunities?
No. I don't believe so. I think we had a project there, or a Newcastle gas peaker, which was also adding flexibility to the grid. We could never make it work. Let's see how other players in the market can make it viable. We don't believe at the moment a gas peaker can be justified at the moment in the current market environment.
Okay. Thanks a lot. That's all to ask.
Thanks, Ian. Next up, we have Peter Wilson from Credit Suisse.
Next morning. My-- a question on the gas book, a double one. Firstly, just in the June quarter in particular, was there any short-term trading gains or losses that are material? Then secondly, if you look into FY 2023, I mean, clearly, you know, customer prices have stepped up, and you do have a substantial amount of fixed price gas and price reviewed gas. Is there not potential to see gross margin growth in 2023 and into 2024?
Maybe. Yes, you are right. Our portfolio is mainly fixed in 2023, particularly the supply portfolio. That's what we are doing and what we wanted also to show, that we have hedged, particularly the underlying oil and in most of the gas offtake contracts. Yes, you can assume with the high prices that there is an upside in this year.
Okay. Just the question of, you know, whether there are any short-term gains or losses in that gas book in the June quarter?
No.
And the, and the-- I guess in July as well.
No. It was more a gain than no losses.
Okay. One for you, Damien. I was a little bit surprised to see a margin release. I would have expected, you know, even an increase in AEMO collateral and margin along with the futures exchange. Maybe if you could just explain where my thinking is wrong there. Also, if you could give us an idea of where the margins currently are lodged, where they sit versus what you think is a steady state level.
Yeah. You need to think of that on a net level you're looking at right there. I mean, that's a net level you're looking at right there. There's both variation margin and initial margins that sit within those numbers. They were sort of broadly flat, if you like, by the time we got to 30 June. We did have additional collateral called through throughout the year as well. That's what's driving some of that. In terms of the question of where I would see it sitting, I think I'd love to be able to answer that perfectly, because if we knew where that was heading, I think we'd, you know, from a market perspective, you know, depending where the volatility is in the market over the coming six months will really drive that position.
What we're flagging is we did see through the cash flows, you know, higher working capital coming through. Some of that will roll back out of our cash flow into next year, as to how much would really just depend on volatility. We did have higher creditor payments, but we also had higher AEMO on the receivable side as well. You know, I couldn't tell you exactly where it's gonna end. It will just depend on where volatility is in the market.
Yeah. Maybe I got that directionally wrong. I thought you [audio distortion] were flagging moving in FY 2023.
Yes, we are.
Maybe you could just-- Give us a kind of scenario, like assuming volatility falls, you know, assuming prices fall, as they have in recent weeks, you know, what might we expect?
Some of that will roll back. There, there's a whole combination to sift through those numbers, as I said, between both AEMO creditor payments, receipts coming through, but also that net variation piece. We will see some of it roll back out, but it will just depend on where the market, you know, settles over the course of the 6 months and 12 months for the year.
Okay. Can you give any kind of magnitude? You know, is it like AUD 0.5 billion to go out? AUD 1 billion?
I'm not gonna give any magnitude, but those numbers sound very high.
Okay, good. I'll leave it there. Thank you.
Thanks, Pete. Next up, we have Rob Koh from Morgan Stanley.
Good afternoon. Thank you very much. May I direct a question to Ms. Egan, seeing as I believe this is your first result call with AGL, and congrats on getting here. I just wanted to ask a question about any trends you might be seeing in gas residential customers in Victoria and the ACT, I guess, in relation to usage and/or connection numbers.
Thank you, Rob, and thanks for the question. Look, in recent times, we've seen retail performing quite strongly, particularly over the past couple of months as we've seen some retailers need to withdraw from the market with market offers. We're seeing good performance across both gas and electricity. In Victoria, there's nothing really unusual there. Our performance continues to be good. There was some mild weather, as mentioned in results, but otherwise nothing unusual.
I think, Rob , the question you're also getting to there is, you know, with some of the Victorian announcements and the ACT announcements on stopping putting new gas connections in, I mean, for the ACT, that will sort of start to kick in for 2023, and that will sort of flow through in our ActewAGL business, but again, it's far too soon to see that. That's just for new connections.
In Victoria, the gas substitution won't kick in till 2030.
Yep. Does that help, Rob?
Okay, cool. Thank you very much. Yeah, that's really good. Nothing gets past you, Mr. Nicks. We know that. May I direct a second question to you, Damien, then, I guess 'cause a lot of the good questions have been asked, so I'm left with this question. You've got a derecognition of onerous contracts of about AUD 1 billion, and I guess when you made those provisions in February 2021, you called out kind of AUD 50 million-AUD 80 million of positive underlying earnings impacts across COGS, depreciation, and interest. Should we be thinking that, like, roughly half those amounts are now gonna come out of underlying earnings in the coming years?
Yeah, well, nothing gets past you either, Rob , that was one deliberately while we had that sort of in the outlook slide. You know, you're right. What will happen is as it unwinds, we'll have less unwinding through the underlying earnings. Roughly those sort of numbers that you talked about is probably about the right sense of it. What it will do is obviously improve our the quality of our underlying cash flow earnings, and you'll see that also come through the cash flow as well.
Yeah, that's clear. Thank you very much. That's it from me.
Thanks, Rob. Next up, we've got Mark Samter from MST Marquee.
Yeah, morning, everyone. Or afternoon, sorry. Two questions if I can. First one, I think probably for you, Graeme, and I fully understand and appreciate why you're not willing to give guidance today, but obviously there has to be a nod towards some consensus. Consensus has FY 2023 90% higher than FY 2022. I guess that doesn't really resonate with the definition of resilient to me, and particularly when we think about the start you made in July with those issues. Is there anything you can point us towards? I mean, resilient doesn't even necessarily suggest growth, let alone 90% that I would say is astronomical.
No, I think, Mark, your dictionary definition is probably pretty correct. What we pointed to on the outlook slide and consistent with what we said back in June, that we would give, we would aim to give guidance at the end of September when we present on the strategic review, so we're being completely consistent with that. There are a number of factors we've put in the qualitative guidance that differentiate 2023 from 2022. The fact that Liddell comes out in April, the fact that Loy Yang 2 was out for the majority of the first quarter, and clearly we had a challenging July that's already been commented on, and then the issue that was dealt with in the last question as well.
Yeah, we're not looking at this point in time at, you know, a major step up in earnings year-on-year, but we'll give more quantitative assessment of that in September.
Brilliant. Thank you. Second question for Markus. It's on the gas book again. I'm just gonna throw it out of the equation. The chart looks slightly different to the one you gave six months ago, but if you go back to the one six months ago, if you assume the, I think it's orange. My eyesight's bad. Bottom of the bar chart, which tends to suggest uncontracted demand up to that minimum level. For FY 2023, that was up close to 150 petajoules rather than the, looks like about 120 petajoules in the presentation today. Can we just talk through why that's dropped 25 petajoules, if it was sort of minimum demand?
Have you lost volumes you didn't expect to lose, or is there potentially just a bit more risk that you have to be out in the market? Buying expensive gas to sell less expensively?
Exactly. I would say in this current market environment, I think we are a bit more cautious when we look at forecasts, particularly when it comes to contracting new customers and so on. I think we don't believe that we can keep at the moment the 153 PJ going forward overall. There is some still some there's also gas to power demand which we cannot properly forecast on a year-by-year basis because we don't know how the markets develop because we are very cautious when it comes to demand forecast. That's maybe the main reason. We wanted to give a clear picture because we were always asked what is our demand and supply gap.
We still believe that we are covered until 2024, but then most probably larger volumes need to be procured and later on.
Thanks. Can I have a question really quickly then to follow up with Pete's question about the obvious benefit of the fixed cost supply, but which should we think wins the battle of relative significance for you? Lost volume negative versus fixed price leverage benefit in that gas clip this year.
Can you repeat? Sorry, I didn't catch. Mark, can you repeat the question?
Sorry. I'll say it more simply. Sorry. What's more important, the benefit you get from the fixed cost supply of advising wholesale prices, or is that more than offset by the volumes you're implicitly losing through the year for this, for the gas margin?
I think in general, I think we have still a comfortable margin, I would say, when it comes to the data between what we have contracted, long and mid-term. I would say we have still a competitive gas portfolio, particular also with our huge storage gas position. I think everything what we have contracted is very competitive. Yeah.
Okay. Brilliant. Thank you.
Thanks, Mark. Next up, we have Max Vickerson from Morgans.
Hi, everyone. Just wanted to ask a question on the comments about being well hedged, particularly in light of the responses to Mark's question. I just wanted to tease it out a little bit more, what it means to be fully hedged. Does the hedging happen on both sides of the book? I mean, you know, hypothetically, if almost as if you're running two separate businesses with customer markets and integrated energy, for example. You know, if in an environment where tariffs are increasing to customer margins potentially increase, and given your response to Mark's question, does that mean that where you were short on generation, that possibly overwhelms whatever influence you might see in customer markets?
I would say, at first I would say hedging is de-risking the portfolio. I think it's not speculation. We are hedging. When you look at our customer portfolio, at our C&I portfolio, and then also at our wholesale market portfolio, we look very, very carefully into this. That's a natural hedge, even if it's not 100%, if you look at the shape. This would be a natural hedge. Everything, what is then in addition contracted, we will hedge on the market or, we increase the generation from our flexible asset portfolio. We try to cover this in this respect, and then certain positions are also hedged forward in order to de-risk falling prices. That's what we are doing.
Think about it as across the whole portfolio. It's not in parts. We look absolutely at the whole portfolio when we think of the hedging and the strategy and the risk management.
It's an integrated, we call it integrated business, so we are looking forward as an integrated business into this.
I might just add for the customer portfolio, the way we see retail pricing flow through does take a couple of years on the consumer portfolio. The wholesale price rolls through over around two years. For C&I, as Markus said, the contracts typically range between one and three years. There is a bit of a lag, just depending on the customer contract.
Got it. Okay. Well, just a quick follow-up then. Given that the DMOs lifted, and I believe AGL would be similar to a number of your competitors, where discounts are maybe getting looked at again, does that change that timeline at all? I'm guessing not.
Look, the DMO and the VDOs will certainly be a decision for the regulators, and it is a complex one. I mean, they will be trying to balance the impact on both customer affordability and, you know, keeping the retail market functioning well. For us, our customer pricing is split between both the regulated portfolio and our market contracts. As I said, we manage those with that two-year methodology on the consumer side. We're seeing retail competition soften at the moment with discounts to the VDO and DMO much lower than they have been historically. This is creating a little more retail margin currently.
In addition, Max, I would outline, you know, we have always said the most liquid product, which we are hedging, are quarterly contracts. We can relatively quickly adjust any regulatory changes when it comes to DMO very quickly, so that makes us not so exposed to regulatory changes.
Just an add to DMO VDO. A lot of those prices were struck before the June volatility as well. That's just another one that you see calling out through the marketplace in terms of, you know, where people are positioned as well. That volatility is not sitting in the DMO VDO prices at this point in time.
Excellent. Okay. Just one final quick one then, just on gas purchasing, which is pretty well covered, but just wanted to ask about the impacts of RoLR given Weston Energy, and potentially a bit of an increase in your customer demand there. Do you think you're positioned well enough, and hopefully we don't see any more spikes in energy market volatility, but I guess the potential is there. Do you think you're adequately covered if you do all of a sudden inherit some additional customers, and how would you yeah, how are you protecting from those kind of unexpected events?
Thank you. Look, the Weston RoLR was very unfortunate situation for both the market and for those customers. We were able to ensure continuity of supply. We've been working really closely with those customers to support them, offer them negotiated contracts, and also support them with dedicated account management services. We are as well passing through any credits that we do get through lower gas prices directly to those customers. We have seen now some of them move away to other retailers as they've negotiated contracts. I'll let Markus comment a little bit more on the future position.
Yeah. I think when Weston happened, I think, you know, we were very keen also to get the contracts, the supply contracts from Weston because that should be natural, because otherwise, you know, the customers of Weston would not. If you decouple it, the customers of Weston would be exposed to this regulatory change to the RoLR event. Unfortunately, I think we could only contract month by month now the volumes, particularly from Woodside and ExxonMobil, which was a supplier of Weston. I think there the regulator need to change a bit the rules, because otherwise everybody will cause a RoLR event that's beneficial and then selling the gas supplies then on the market. I think that's a loophole in the regulatory environment. We made this also clear toward the regulator.
Let's see what will come next. Then in addition, I think our colleagues from APLNG went yesterday out with the press release that we have contracted some gas supply from them as well. Everything what was then below, particularly the regulated price and the DMO price, we have somehow given back to our customers. This is what we have done. We have contracted additional gas because we were balanced. When this was below the DMO price, our customers have benefited from this.
Excellent. Thanks, everyone.
Thanks, Max. We have time for three more questions. Next up, we have Alistair Rankin from RBC.
Thank you very much, and good afternoon. I'd like to take a different tack with the first question and just want to understand how the Torrens Island Battery is progressing. Also following that, what you're seeing from a resource inflation perspective for your other battery projects, Broken Hill, Liddell, and Loy Yang.
I think when Torrens Island Battery went live on the 27th of June, we took over the energy and operating now the battery. That is very beneficial for us. We have implemented also an algorithm which is somehow running the battery in the market. I think Torrens and Broken Hill batteries, you know, these battery projects are all locked in. We are not exposed to any price increase because, you know, when we took financial investment decision, we locked in the EPC contract, so there is no exposure at all. You are fully right. Battery prices have then since then lifted up.
At the end of the day, we have, if we take investment decision for the Liddell battery and the Loy Yang battery, we have to cope with increased pricing. We are looking very carefully at this, but somehow that should be compensated also by the higher wholesale market prices. We are running at the moment our financial models, and then we take later in the year, most probably investment decision subject to the economics.
Okay, excellent. Thank you. That's clear. Just on the sustaining CapEx reduction. I understand that that's attributed to both the closure of Liddell and what you have mentioned is major outage management improvements. Can you just talk through what you mean by that major outage management improvements and what proportion of that AUD 100 million sustaining CapEx reduction you think that might make up?
I think at first, the sustaining CapEx reduction is mainly caused by, on the one hand, we have most of all the Torrens B1 unit that was already happening last year. You are fully right, the four Liddell units dropping out. Three, then one already dropped out, the other three in April. That will reduce substantially also sustaining CapEx. That's clear. I think everything what is related to. We have invested quite substantial amount already in Bayswater. Three units have undergone a substantial upgrade, which we have also outlined when it comes to Bayswater unit three this year, DCS upgrade, turbine upgrade, additional capacity added and so on. In this context, we don't assume particularly for Bayswater now going forward, major outages.
We have invested in these three new units around AUD 390 million, which is quite sizable. This, we now make sure that we gain this money back. I think everything else is then rolling into our major outage schedule, and we are still optimizing the major outage schedule in order to make sure that we are not over-investing, but also properly investing. I think it's not that we are running the units to ground, but we are doing an investment where it's necessary and where it's valuable.
Okay. Thank you. Yeah, you answered my follow-up question there, so that's great. I might just ask one more just around, I guess the future electricity system and I guess demand response among retail customers. That seems to be something that some retailers are investigating and rolling out at the moment. Just wondering what your thoughts are on the whole demand response aspect of your retail offerings will be. And then I guess just another question around that is around capacity like payments for demand response. Do you think that ESB will potentially offer some capacity payments for demand response from retail customers?
Well, I might just start and talk about the demand response program that we're running in the customer business. We've seen really good growth in that this year with 65% increase. We've now got 215 MW under orchestration, and that's across a range of products and services. We have our C&I customers who participate in demand response and orchestration products. More than 100,000 consumer customers now on our behavioral demand response program, which is Peak Energy Rewards. Our solar and batteries bundles. All of these different assets are managed remotely with our NEO platform to orchestrate at peak times. I think there's great value in this. I mean, with energy prices so high, AGL can access this energy at critical peak times.
It also lowers demand on the grid and provides value for our customers as well.
Yeah. On the question about, you know, capacity mechanism, I think the initial focus was really on ensuring that there was a, you know, medium to longer term smooth transition to capacity in the market. But as you say, there are other mechanisms that you can look to if you're looking at a much shorter timeframe. As Jo's spoken about already, we're doing that, and we'll be doing more of it. Where the policy position ends up is obviously still being worked on as we move forward, and I expect that it will, you know, seek to solve both of those longer term energy system transition issues, as well as what's possible in terms of managing demand response on a much shorter term, you know, minute-by-minute approach.
Great. That's very clear. Thank you very much.
Thanks, Alistair. We've got enough time for two more analysts. If we could keep it down to one question each. Next up, we've got Daniel Butcher from CLSA.
Hi, guys. I'll check which one I'm gonna ask then. I will ask you about gas prices. Just sort of curious for new gas contracts you've got to roll over or add, you know, some actual set of reports suggesting anecdotally maybe tenfold than usual for sort of couple of year contracts for 2023, for utilities, at least one of the utilities say similar sorts of things. I'm just wondering whether you'd comment whether you think that's in the ballpark of what you'd need to pay for any new gas.
Maybe if you could give a bit of an explanation of how you go about pricing your C&I gas versus your portfolio cost or marginal cost of gas.
I think for sure we are constantly in the market and looking and have a strong relationship with particular also the small producers, where we're taking off midterm gas, what you have seen also on the chart on slide 23. I think that for sure I will not mention any price. You know, we are normally not doing this. That's our intellectual property, and I will not comment on this. I think we are now see more prices in the spot market and so on around the 15th and the 18th and so on. Most probably in the winter in the European winter, that can change then again. We need to properly risk hedge risk manage our gas portfolio, what we have done in the past.
We are, you know, constantly looking if we can supply additional C&I customer and wholesale customers. It needs to make financial sense. We are not buying customers. We are very carefully looking that we are also earning money with this customer.
Okay, thanks. That's my one question.
Thanks, Dan. Time for one last question. We've got Reinhardt van der Walt from Bank of America.
Good afternoon, folks. Thanks for all your comments. I'll keep my one question to one on the thermal assets. It looks like your thermal assets, or at least the ones that were online, had a pretty busy FY 2022. I think from memory, you saw Loy Yang A had Units 1, 3, and 4 running at almost full capacity for quite some time. Should we think about FY 2023 as being maybe a slightly more maintenance intensive year? Is there any kind of catch-up maintenance you'll have to do now given the capacity factors, the average capacity factors you've had on those units?
No, I think you are right. I think particularly the first three quarters of FY 2022 were very good. We had really equivalent availability factors around 80%, particularly at Loy Yang. It's three running units. I'm strongly convinced that this will continue to be also this year, particularly when now Loy Yang A Unit 2 is coming back in a few weeks time. There's no reason to believe that there's a delay. We are doing continuous maintenance, so you should not expect, because the units were running on high availability, that this will now go down this year.
Got it. Thanks a lot.
Thanks, Reinhardt, and thank you everyone for dialing in. That's all we have time for today. If anyone who didn't get to call in, please feel free to contact the investor relations team. Thank you.