AGL Energy Limited (OTCPK:AGLNF) Q4 2022 Earnings Conference Call August 18, 2022 9:00 PM ET
Company Participants
Graeme Hunt – CEO and MD
Damien Nicks – CFO
Jo Egan – Chief Customer Officer
Markus Brokhof – Chief Operating Officer
Conference Call Participants
Tom Allen – UBS
Ian Myles – Macquarie
Peter Wilson – Credit Suisse
Rob Koh – Morgan Stanley
Mark Samter – MST Marquee
Max Vickerson – Morgans
Alistair Rankin – RBC
Dan Butcher – CLSA
Reinhardt van der Walt – Bank of America
Operator
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. [Operator Instructions]
I would now like to hand the conference over to CEO and MD, Mr. Graeme Hunt.
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. 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 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 and culminating in suspension of the market in mid-June.
Our FY 2022 underlying profit after tax was AUD225 million, down 58% on FY 2021. As anticipated, this low 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 non-recurrence of the Loy Yang 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. Whilst 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 AUD0.10 per share unfranked, bringing the total dividend for the 2022 financial year to AUD0.26 per share.
Turning now to some business updates. Total services to customers remained stable at AUD4.2 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 and highs at positive 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 MyAccount 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 a 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 $150 million of targeted operating cost reductions in FY 2022, and we are also on track to achieve a reduction of $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 Damien will cover shortly.
In May, the AGL Board made the decision to withdraw the demerger proposal that would have seen AGL separated into two separately 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 sub-committee 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 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 and 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 remains 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. And 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-gigawatt Tilt Renewables development pipeline. And 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.
And 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. And as mentioned, from FY 2024, we are well positioned to benefit from sustained higher wholesale electricity pricing, 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 AUD200 per megawatt hour for FY 2023. Pleasingly, the dotted lines indicate strength in wholesale pricing for both New South Wales and Victoria into FY 2024.
On the right-hand side, you can see the material elevation in volatility since mid-2021, driven primarily by multiple forced thermal generation outages throughout 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-megawatt 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 hours work 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 plus 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. Whilst 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 uncertainties 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, whilst 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. And 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.
Damien Nicks
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 AUD312 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 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 by our 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 AUD350 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 AUD91 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 Unit 2 and other unplanned outages and June trading where we’re a buyer of electricity at elevated spot pricing.
Please note that a net AUD10 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 a 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 nonrecurring. 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 to Bayswater and Loy Yang announced in February. And 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 a change in the discount rate used to assess the present value of our future obligations. The onerous 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.
And the financial instruments gain represents 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 the 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 AUD89 million post-tax or AUD125 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 cost to be approximately AUD145 million lower than the AUD160 million advised in late May, and these will be treated as a significant item.
And finally, restructure 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 our AUD150 million of targeted operating cost reductions in FY 2022, excluding the benefit of improved COVID-related net bad 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 AUD100 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 remain stable, affirming a 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 and 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 AUD155 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 AUD200 million of revolving bank facilities and maintained 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 will provide a full year overview on customers, operations and portfolio generation.
Jo Egan
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 multiservice retailing strategy and improved customer experience. Total services to customers remained 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 AUD22 million to consumer gross margin in the second half. This solid result demonstrates AGL’s ability to both support customers and carefully manage value amid a period of heightened market volatility.
Going forward, we will continue to responsibly grow our customer base whilst prudently managing customer lifetime value. Encouragingly, despite intense competition, our churn spread to rest of market improved to four percentage points. Our multiservice 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 1 retailer in the most recent reporting cycle. Additionally, we recorded our fourth consecutive end of year improvement in strategic NPS with a score of positive six.
Another highlight is our sustained focus on cost discipline that has resulted in a 24% decline in net operating cost 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 growth, resulting in over 1 million active mobile app and MyAccount users. When compared to its peers, AGL has Australia’s number one mobile app with a 4.7 out of 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 data 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 benefit 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 capabilities. This flexible and modular technology architecture will enable adaptability for future market innovation.
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 pool.
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 megawatts 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 megawatts. 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 offering with an increase in carbon mutual 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.
And now over to Markus.
Markus Brokhof
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 operations business areas. As you can see, some of our key operational metrics have not had the result we were targeting. Despite a 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 am proud of the fact that we have delivered a high volume of work on our complex, planned 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 the 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 of 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 dynamic 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 expectations has been a substantial reduction in the provision for onerous contracts across future periods.
I will now cover this year’s 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 planned operators often have planned 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 spike. And 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 one.
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 cost equating to around $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 is 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%, and in a normal year, this is what we would be aiming for as summer presence peak demand. So it is critical for us to be available for the market.
It would become common practice to have a reduced availability in the shoulder seasons of Q2 and Q4, as planned outages for regular asset maintenance occur. However, unfortunately, in Q4, we have seen a confluence of prolonged planned 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 Unit 2, which resulted from a design error in 2019 and a rise in boiler tube leaks across Liddell, Bayswater and Loy Yang.
The unplanned outage at Loy Yang 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 Unit 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 Loy Yang A and Bayswater plant. These were established during FY 2022 and the digital trends will enable AGL to reduce physical testing and instead optimize the operating conditions and capital reserves.
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 rate of future corrosion. We’ve introduced acoustic monitoring in the boiler so that we can detect early signs of tube failure and makes the right decision.
Milling routine work has been improved to ameliorate common defects. For example, optimize programs of work on oil filters and feeder bill. 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 markets.
While it provides a partial hedge, the customer book does not immediately reflect the wholesale price environment. The nature of price regulation and contract length 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 positions, demand response, weather derivatives and our Settlement Residue Auction Units to balance the portfolio. Where prices reduce against our plant’s 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 positions in a 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 am 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 downside in absence of a sophisticated risk management approach was poor speculation. Our long-term fuel supply strategy protected AGL from further impacts of price volatility right away. We’ve been positioned well in a difficult market thanks to our competitive long term coal offtakes.
For Bayswater and Liddell, our re-profiled supply contract has provided consistent production cost-linked coal supply, which combined with AGL’s 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 advantageous 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 we continue to do so as international pricing 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 -linked contracts to manage exposure during the low prices of the pandemic has led to further value in the book. So, while it has been a challenging year on the generation site, 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 projects pipeline of 2.9 gigawatts and Energy Hubs 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 areas 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 sizeable partners include Fortescue Future Industries, Osaka Gas, SK ecoplant, Wartsila, Nu-Rock, Idemitsu, APA and Spark Renewables.
FY23 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 in important industrial cluster as well targeting 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.
Graeme Hunt
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 have 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 the 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’ll now open to any questions.
Question-and-Answer Session
Operator
[Operator Instructions] Our first question comes from Tom Allen at UBS.
Tom Allen
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. So clearly, market dynamics are requiring baseload coal generation be operated in ways that 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 users.
Graeme Hunt
Thanks, Tom. I’ll start, and then I’ll hand over to Markus. I think one of the things that we did during this year was the upgrade to the digital control system on Bayswater 3 and one of the underlying elements of the business case. So that was the ability for us to actually ramp up and ramp down that unit.
So that has some opportunities there, obviously, 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. So that’s one of the things that we’re doing. But clearly, beyond that, how we manage the flexible portfolio that we’ve got helps and how we make sure that we focus our maintenance program, sustaining capital going forward, and Markus touched on some of those things in his speech that perhaps you can add to that now.
Markus Brokhof
Thanks a lot, Graeme. Yes, it’s true that I have proposed some – or we are now implementing some technical measures, which I have described in my speech. But for sure, we have reviewed very thoroughly also our planned outage and major outage schedule for this financial year, try to avoid overlap of units which are going out.
And then in addition, also where it was possible, we have unwinded some hedging positions in order to make sure that if volatility comes we are able to capture this and we are not aggressively hedged. So, these were measures on the trading side, which we have taken and then I would still outline there was an extreme situation in Q4. And normally, we can – with our interconnector capacity, particular between SA and Victoria and also New South Wales we can still, with our flexible portfolio, for sure, make up some shortfalls.
So, that’s something which we are doing constantly. But as in an extreme case, as we had various forced outages, particular in June and July this year, we were not able to replace particular the energy, which we lost and that was an extreme situation. I don’t expect that dispenses year.
Tom Allen
Okay. Thanks Marcus. And Graeme, just one more follow-up question. Just one on your gas portfolio, I just was seeking some clarification on slide 23 in your presentation. So, if FY 2022 gas portfolio was about 153 PJs, is that slide suggesting that your portfolio demand will drop by about 20% or, say, 30 PJs into FY 2023, but you don’t need any additional supply over the next 12 months. But from 2024 and 2025, AGL’s flagging that may require for 30 to 45 petajoules per annum each year over those two years?
Markus Brokhof
I think it’s a bit reflected if you look thoroughly on the slide 23 and if you look what we had signed in the addition over the past years, if you look just GSA signed in financial year 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 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 review – if we would renew all the contracts which we have currently, yes, we are short. But we will successively fill up our portfolio as we have done also in the past.
So, there is no change in procurement and so on and we have always said some of the legacy contracts have rolled off in the past. So, yes, we have to replace some volume, but it’s depending how much our customer portfolio will stay with us or will grow.
Operator
Next up, we have Ian Myles from Macquarie.
Ian Myles
Thank you guys. Just a couple of 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 and yet buy in the market because – and can we take some of the commentary about heading that you’ve actually managed to cover a lot of those positions prior to the outages.
Markus Brokhof
I think when you look – I think I will not now even in this financial, I will not disclose the secret. You can look it up in. I think briefly – I think for 10 days, we were short. We were units with energy were out 1,800 megawatts. But to be honest with you, we normally are not hedging the fully Liddell units. So maybe the shortage of 1,200 megawatt briefly for 10 days. And for sure, certain position was exposed and capacity could be covered, but not the full energy content.
Damien Nicks
And I think – Damien here. I mean that’s one of the reasons we called that off. Some of that the challenges we saw in June rolled into July, and that’s why we’re calling it out in that outlook position.
Ian Myles
Okay. And the recent – from a go-forward position, can we assume that you’re really taking like an N-1 position in all markets. So you’ve effectively got one turbine sort of sitting in spot market.
Markus Brokhof
You know, I do not comment on this because normally we not disclose our hedging strategy, but somehow you are going in the right direction, but it’s a bit different. It’s also seasonal and it’s a bit different state by state. But yes.
Damien Nicks
And I think Ian also just to take into account, we also think about Liddell differently as well as an age unit as well.
Ian Myles
Okay. And one other left [indiscernible] Hana gas pipeline, which has been proposed, does that start a jump thought process about what you might use Liddell for and whether a gas plant could be put there or other opportunities?
Markus Brokhof
No. I don’t believe so. I think we had a – we had a project there or a new gas peaker, which adding flexibility to the grid. We could never make it work. Let’s see how our other players in the market can make it viable, but we don’t believe at the moment, a gas peaker can be rectified at the moment in the current market environment.
Operator
Thank you. Next we have Peter Wilson from Credit Suisse.
Peter Wilson
Thanks. Good morning. A question on the gas book, double one. Firstly, just in the June quarter, in particular, was there any short-term trading gains or losses that are material? And then secondly, if you look 2023 clearly, the customer prices have stepped up, and you do have a substantial amount of fixed price gas and price of your gas. Is there not a potential to see gross margin growth in 2023 and in 2024.
Markus Brokhof
Maybe, yes, you are right, we – our portfolio is mainly 623, particularly the supply portfolio that what we do – or what we wanted also to show that we have hedged, particularly the underlying oil in most of the gas off-take contracts. Yes, you can assume with the high prices that there is an upside in this year.
Peter Wilson
Okay. And just a question of whether there are any short-term gains or losses in that gas book in the June quarter and, I guess, in July as well?
Damien Nicks
It was more again than – no losses.
Peter Wilson
Okay. And for you – Damien, I was a little bit surprised to see a margin release. I would have expected even an increase in AEMO, collateral and margin along get Futures Exchange. So maybe if you could just explain where my thinking is wrong there? And also if you could give us an idea of where the margins currently lodged – they lodged where they sit versus what you think is a steady state level?
Damien Nicks
Yes. So you need to think about that on a net – I mean, that’s a net level you’re looking at right there. There’s both variation margin and initial margins that sit in those numbers. And they were sort of broadly flat, if you like, by the time we got to 30 June. We did have additional prudentials called through throughout the year as well. So 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 would – from a market perspective, depending where the volatility is in the market over the coming 6 months will really drive that position.
What we’re flagging is, we did see through the cash flows higher working capital coming through. So some of that will roll back out of our cash flow into next year as to how much would really just depend on volatility. But we do that creditor payments, but we also had higher AEMO on the receivable side as well. So I couldn’t tell you exactly where it’s going to end. It will just depend on where volatility is in the market.
Peter Wilson
Maybe I’ll get that directionally wrong. I saw you were flagging an adverse working capital movement in FY 2023. And maybe if you could just give us a kind of scenario, like assuming volatility falls, assuming prices fall, let’s say, have in recent weeks, what might we expect?
Damien Nicks
Some of that will roll back. So there’s a whole combination to sit through those numbers, as I said, between both AEMO creditor payments, receipts coming through, but also that net variation piece. So we will see some of it roll back out, but it will just depend on where the market settles over the course of the six months and 12 months of the year.
Peter Wilson
Can you give any kind of magnitude? Is it like AUD0.5 billion to go out, or AUD1 billion?
Damien Nicks
I’m not going to give any magnitude, but those numbers and very high.
Operator
Thanks, Pete. Next up, we have Rob Koh from Morgan Stanley.
Rob Koh
Good afternoon. Thank you very much. May I direct the question to Ms. Egan, seeing as I believe this is your first results call with AGL, and congrats on getting here. I just wanted to ask a question about any trend by seeing in gas residential customers in Victoria and the ACT, I guess, in relation to usage and/or connection numbers?
Jo Egan
Thank you, Rob, and thanks for the question. Yes, so 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 with market offers. So we’re seeing good performance across both gas and electricity. In Victoria, that there’s nothing really unusual there. Our performance continues to be good. There were some mild weather, as mentioned in results, otherwise, nothing unusual.
Damien Nicks
I think, Rob, I think the question you’re also getting to there is 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 23, and that will sort of flow through in actual AGL business, but again, far too soon to see that. That’s just the new connections…
Jo Egan
And in Victoria, that the gas substitution might won’t kick in until 2030.
Rob Koh
Yes. Okay. Thank you very much.
Damien Nicks
Was that helpful?
Rob Koh
Yes. That’s really good. Nothing gets past you, Mr. Nicks we know that. May I direct the second question to you, Damien, then, I guess, because a lot of the good questions have been asked, so I’m left with this question. So you’ve got a derecognition of onerous contracts of about AUD1 billion. And I guess when you made those provisions in February 2021 you called out AUD50 million to AUD80 million of positive underlying earnings impacts across COGS, depreciation and interest. Should we be thinking that roughly half of those amounts are now going to come out of underlying earnings in the coming years?
Damien Nicks
Well, nothing gets passed you either Rob. So that was one deliberately what’s in the outlook slide. You’re right. So what will happen is as it unwinds, we’ll have less unwinding through the underlying earnings, roughly those 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.
Operator
Thanks, Rob. Next up, we’ve got Mark Samter from MST Marquee.
Mark Samter
Yes. Good morning, everyone or afternoon. Two questions, if I can. First one, I think, probably for you, Damien, I fully understand and appreciate why you’re not willing to give guidance today. But, obviously, there has to be a nod towards consensus and consensus has FY 2023, 90% higher than FY 2022. And I guess that doesn’t really resonate with the definition of Brazilian to me, and particularly when we think about start you made in July with those issues. Is there anything you can point us towards? I mean, Brazilian doesn’t need necessarily suggest growth, but alone 90%, but also is astronomical?
Damien Nicks
No. I think, Mark, your dictionary definition is probably pretty correct. What we pointed to in the outlook slide and consistent with what we said back in June we would give – we would aim to give guidance at the end of September when we present on the strategic review, so we’ve been completely consistent with that.
There are a number of factors that put in the qualitative guidance that differentiate 2023 from 2022, the fact that Liddell comes out in April, the fact that Loy Yang too 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. So we’re not looking at this point in time at a major step-up in earnings year-on-year, but we’ll give more tariff assessment of that in September.
Mark Samter
Great. Thank you. And then second question for Markus on the gas book, again, which has been amount of tension out. The chart looks slightly different to the one you gave six months ago, but – if you go back to six months ago, issue, I think it’s orange nice out spread part of the bar chart, which tends to suggest un-contracted demand up to that minimum level. For FY 2023, that was up close to 150 PJs rather than looks it like about 120 PJs in the presentation today. Can we just talk through why that’s dropped 25 PJs, if it was kind of minimum demand, have you lost volumes you didn’t expect to move? 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?
Markus Brokhof
Exactly, I would say, in this current market environment, I think we are a bit more cautious when we look at forecast, particular 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.
And there is some – still some – there’s also a regard 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 forecasts. So that maybe the main reason. And we wanted to give a clear picture, because we were always at 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 from later on.
Mark Samter
Thanks. And Graeme, I guess, just really quick, then follow up with Pete’s question about the – obviously, the benefit of the fixed cost supply, but what should we think wins the battle of relative significance for you of lost volume negative, versus fixed price leverage benefit in that gas spread this year?
Graeme Hunt
Can you repeat? Sorry, I didn’t catch your…
Mark Samter
Sorry. I’ll say it more simply. Sorry. What’s more important, the benefit you get from the fixed cost supply revising wholesale prices, or is that more than offset by the volumes you’re implicitly losing through the year for this – for the gas margin?
Graeme Hunt
I think, in general, I think we have still a comfortable margin, I would say, when it comes to the delta between what we have contracted long and mid-term. So I would say, we have still a competitive gas portfolio, particularly also with our huge storage gas position. And so, I think, everything what we have contracted is very competitive. Yes.
Operator
Thanks, Mark. Next we have Max Vickerson from Morgans.
Max Vickerson
Hi, everyone. Just wanted to ask a question on the comment about being well hedged, particularly in light of the responses to Mark’s question. So I just wanted to just tease it out a little bit more what it means to be fully hedged. Is it – does the hedging happen on both sides of the book?
I mean, hypothetically, if almost as if you’re running two separate businesses with customer markets and integrated energy, for example. So 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 sort on generation, that possibly overwhelms whatever influence you might see in customer markets?
Graeme Hunt
I would say – and first, I would say, hedging is de-risking the portfolio. I think, it’s not speculation. So 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 carefully into this. So that’s a natural hedge, even if it’s not 100%, if you look at the shape, but it would be a natural hedge.
And then everything, what is then in addition contracted, we will hedge on the market, or we increase the generation of our flexible asset portfolio. So 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.
Damien Nicks
But think about it, it’s across the whole portfolio. It’s not in part. It’s – we look absolutely at the whole portfolio when we think of the hedging and the strategy and the risk management.
Markus Brokhof
Integrated, we call it integrated business, so we are looking for sure as an integrated business into this.
Jo Egan
And 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. So the wholesale price rolls through over around two years. And for C&I, as Markus said, the contracts typically range between one and three years. So there is a bit of a lag just depending on the customer contract.
Max Vickerson
Got it, okay. Is that – 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 were discounts are maybe getting looked at again. Does that change that time line at all? I’m guessing not.
Jo Egan
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 keeping the retail market functioning well. For us, our customer pricing is split between both the regulated portfolio and our market contracts.
And as I said, we manage those with that two-year methodology on the consumer side. So, we’re seeing retail competition soften at the moment with discount to the VDO and DMO much lower than they have been historically. So, this is creating a little more retail margin currently
Markus Brokhof
And in addition, Max, I would outline, we have always said the most liquid product, which we are hedging a quarterly contract. So we can relatively quickly adjust any regulatory changes when it comes to DMO very quickly. So that makes us not so exposed to regulatory trend.
Damien Nicks
And just maybe just an add to DMO, VDO, a lot of those prices were struck before the June volatility as well. So that’s just another one that you see calling out through the marketplace in terms of where people are positioned as well. That volatility is not sitting in the DMO, VDO prices at this point in time.
Max Vickerson
Excellent. Okay. Just one final quick one then just on gas purchasing, which has been pretty well covered, but just wanted to ask about the impacts of rollup given Western Energy and potentially a bit of an increase in your customer demand there. Do you think you’re positioned well enough? I mean, 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 – how are you protecting from those kind of unexpected events.
Jo Egan
Thank you. Look, the Western RoLR was a very unfortunate situation for both the market and for those customers. And we were able to ensure continuity of supply, and 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 credit that we do get through lower gas prices directly to those customers. And we have seen now some of them move away to other retailers as they have negotiated contracts. I’ll let Markus comment a little bit more on the future position.
Markus Brokhof
Yes. I think when Western happened, I think we were very keen also to get the contracts, the supply contracts from Western because that should be natural because otherwise, the customers of Western would not – if you decouple it, the customers of Western 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 ExoMobile, which was a supplier of Western. 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 than on the market. And I think that’s loophole in the regulatory environment. We made this also clear towards the regulator. Let’s see what will come next.
And then in addition, I think – and I think our colleagues from APN LNG went yesterday out with the press release that we have contracted some gas supply from them as well. And everything was below particular the regulated price and the DMO price we have somehow given back to our customers. So this is what we have done. So we have contracted additional gas because we were balanced and then when this was below the DMO price our customers have benefited from this.
Operator
Thanks, Max. We have time for three more questions. So next up, we have Alistair Rankin from RBC.
Alistair Rankin
Thank you very much, and good afternoon. I might just take a different tact with the first question. And just want to understand how the Torrens Island battery is progressing. And then also following that, what you’re seeing from a cost inflation perspective for your other battery projects Broken Hill, Liddell and Loy Yang?
Markus Brokhof
I think one dual battery went in live on the 27th of June, we took over the energy and operating now the battery that is very beneficial for us, and we have implemented also an algorithm, which is somehow running the battery in the market. And then I think Torrent and Broken Hill batteries, this battery projects are all locked in. We are not exposed to any price increase because when we took financial investment decisions, we locked in the EPC contract. So there is no exposure at all.
You are fully right. battery prices have been since then lifted up. And at the end of the day, we have if you take investment decision for the Liddell battery and the Loy Yang battery we have to cope with increased pricing. We are looking very carefully to this. But somehow that should be compensated also by the higher wholesale prices. So we are running a moment our financial models and then we take then later in the year, most probably in the decision factor the economy.
Alistair Rankin
Okay. Excellent. Thank you. That’s clear. Just on the sustaining CapEx reduction. So I understand that that’s attributed to both the closure of Liddell and what you have mentioned as major outage management improvements. Could you just talk through what you mean by that major outage management improvements on what proportion of that AUD100 million CapEx sustaining CapEx reduction, we think that might make up. Thank you.
Markus Brokhof
I think at first the sustaining CapEx reduction is mainly caused by – on the one hand, we have most, more deterrent Loy Yang Unit that was already happening last year. Then you are fully right probably Liddell Unit dropping out three then one dropped already out. The other three in April that will reduce substantially also sustaining CapEx that clear.
And then I think everything what is related to – we have invested quite substantial amount already in the Bayswater three Unit, have undergone a substantial upgrade which we have also outlined when it comes to Bayswater Unit 3 this year, DCS upgrade, turbine upgrade, additional capacity added and so on.
In this context, we don’t assume particular for Bayswater. Now going forward, the major outages, so we have invested in these three new units, around €390 million is quite sizable. So this we will now make sure that we gain this money back. And then, I think everything else is then rolling into the – in 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.
Alistair Rankin
Thank you again. You ask about my follow-up questions, so that’s great. I might just talk more just around, I guess, the future electricity system and I guess, demand response amongst retail customers. That seems to be something that 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 you will potentially offer some capacity payments or demand response from retail customers?
Jo Egan
Well, I might just talk about the demand response program that we have in the customer business. And we’ve seen really good growth in that this year with a 65% increase. We’ve now got 215 watts 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 product more than 100,000 consumer customers now on our behavioral demand response program, which is peak Energy Rewards and they’re now solar and batteries bundles.
And 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 that also lowers demand on the grid and provides value for our customers as well.
Graeme Hunt
Yes. And on the question about capacity mechanism, I think the initial focus was really on ensuring that there was a medium- to longer-term smooth transition to keep capacity in the market. But as you say, there are other mechanisms that you can look to, if you look in a much shorter timeframe.
And as Joe has 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 seek to solve both of those longer-term energy system transition issues as well as what’s possible in terms of managing this demand response on a much shorter term minute-by-minute approach.
Operator
Thanks, Alister. We’ve got enough time for one more. If we keep it down to one question each. Next up, we’ve got Dan Butcher from CLSA.
Dan Butcher
Yes. Hi, guys. Last one. I will ask you about gas prices. I’m just sort of curious for new gas contracts, you’ve got to roll over or add some accuracy report suggesting anecdotally, maybe you could use your for sort of a couple of year contracts from 2023 for utilities, at least monthly similar sorts of things. Just wondering whether you’d comment you think that’s in the ballpark of what you need to pay for any new gas? And 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?
Markus Brokhof
I think what we – 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 guards what you have seen also on the part on Slide 23. I think that for sure, I will not mention any price. We are normally not doing this that’s our internal property, and I will not comment on it. I think we are now more price – in the spot market, and so on around the 15 and the 18 and so on most probably in the winter that could change, the European winter that can change them again.
So we need to properly risk manage our gas portfolio and what we have done in the past. And yes. And then we are constantly looking if we can supply additional C&I customer and wholesale customers, but needs to make financial decent. So we are not buying customers. We are very carefully looking on money with this customer.
Operator
Thanks, Dan. Time for one last question. We’ve got Reinhardt van der Walt from Bank of America.
Reinhardt van der Walt
Good afternoon, folks. Thanks for all your comments. I’ll keep my one question to one on the thermal assets. So 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 one, three and four 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?
Markus Brokhof
No, I think you are right. I think particularly the first three quarters of FY 2022 were very good. We had really availability – equivalent availability factor of around 80%, particular at Loy Yang. It’s a three running unit. We believe we – or I’m strongly convinced that this will continue to be also this year, particular when now Loy Yang Unit 2 is coming back in a few weeks’ time. There’s no reason to believe that there’s a delay. And so – and 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.
Graeme Hunt
Thanks Ryan 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.
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