Good morning, everyone. Thank you for joining us for AGL's 2026 half-year results webcast.

I'd like to begin by acknowledging the traditional owners of the land I'm on today, the Gadigal people of the Eora Nation, and pay my respects to their elders past, present, and emerging. I'd also like to acknowledge the traditional owners of the various lands on which you are all joining.

Today, I'm joined by some of my executive team: Gary Brown, Jo Egan, David Moratto, Matthew Curry, and Ryan Warburton. I'll get us started, and we'll have time for questions at the end.

Our first half results reflected strong operational and financial momentum across the business, on the back of improved reliability and flexibility of our generation portfolio, growth in customer services and higher margins, as well as the continued delivery of the transition of our asset base. We're pleased to see our customer satisfaction metrics continue to improve, and are working hard to support our customers who are facing cost of living pressures.

Although the market experienced unusually less volatility in the half compared to historical averages, the longer-term forecasts for energy demand, as well as our expectations for volatility, remain strong. Importantly, our stronger fleet availability and flexibility, coupled with excellent battery performance, helped mitigate the impacts of lower market volatility driven by milder weather and lower transmission constraints.

Overall, EBITDA was flat, and as indicated, underlying net profit was impacted by increased depreciation and amortization due to continued investment in the availability and the flexibility of our assets, and higher finance costs in line with increase in borrowings and facility interest rates, as we continue to invest in growth and press forward with our multi-decade transition of our business. A fully franked interim ordinary dividend of 24 cents per share has been declared, in line with our policy to target a 50% to 75% payout ratio of underlying NPAT for the total FY26 dividend.

Today, we have narrowed our FY26 financial guidance ranges in line with a strong first half performance, that I will discuss at the end of this presentation. I'll also talk to how the NEM has progressively shifted to more elevated winter demand peaks compared to the summer peaks, partially explaining the increasing earnings skew towards the first half we've seen in recent years.

We're also implementing a cost and productivity improvement program that is targeting sustainable net operating cost reductions of $50 million per annum, with the full benefit from FY27 onwards. Whilst financial outcomes were broadly stable, the fundamentals of our business continue to strengthen, with a significant improvement in operational performance in the half.

Starting on the left-hand side, where we saw another period of elevated market activity, we've materially grown our customer base, increased our already strong customer satisfaction, and improved consumer margin. Our Customer Markets business recorded excellent growth in overall customer services, primarily led by growth in energy services, including the acquisition of Ampol customers, with telecommunications and Netflix customer services also higher.

Our customer satisfaction score increased to 83.8, strategic NPS remains positive at +4, and spread to market churn remains strong at 5.3 percentage points, all strong indicators of our customers being satisfied with AGL's service offering. At the same time, we delivered a 10% improvement from the prior half in consumer margin, reflecting a return to more sustainable levels.

Turning to the right-hand side, where we've delivered a stronger fleet availability result for the first half, and remain on track for improved fleet availability for the full year. Importantly, higher commercial availability and improved plant flexibility allowed AGL to generate when market conditions were most favorable.

Amidst lower volatility, our growing flexible asset fleet delivered an excellent premium of 20% to the time-weighted average price for the half, 7 percentage points above FY25. Importantly, our continued investment in flexible assets is expected to grow this premium over time.

Finally, our operated battery portfolio continues to deliver excellent performance, with an EBITDA contribution of $35 million, $10 million higher on the prior half. Again, a strong result despite a period of unusually lower volatility.

Turning now to some observations from the half, as well as some longer-term trends and the opportunities they present for AGL. Firstly, we've observed new peak demand records, and as I mentioned, the NEM shifting to more elevated winter demand peaks relative to summer peaks.

As I'll discuss on slide 15, AEMO's forecast for long-term operational demand remain highly favorable, underscored by growth in electrification, EV penetration, and data centers providing AGL with considerable opportunities into the future. Crucially, our energy portfolio, and particularly our flexible asset fleet, is well-positioned to leverage the upside of rising operational and peakier customer demand.

I've already mentioned the unusually lower volatility in the half driven by milder weather and lower transmission constraints. However, over the longer term, as the NEM transitions, we do expect higher volatility through the cycle, for reasons I'll speak to later in the presentation.

Again, our growing flexible asset fleet is well-placed to leverage the upside of a higher long-term volatility, delivering strong supply-side realized pricing and portfolio outcomes. Finally, the market is delivering on the 41 gigawatts of grid-scale and residential batteries required in the NEM by 2035.

Approximately 10 gigawatts of this target have been built, albeit a significant amount of new storage and generation capacity still needs to be in place over the next 10 years. We continue to progress the build-out of our high-returning operational grid-scale battery projects, and I'll speak to the new products and initiatives which are delivering value for our residential battery customers.

Overall, AGL is very well-positioned in an evolving and transitioning energy market. We've had an excellent half across the business as we press forward with the delivery of our strategy to deliver long-term value.

Headlined by the transition of our energy portfolio, we've continued to make great progress. Our development pipeline has grown to 11.3 gigawatts, up from 9.6 gigawatts at the FY25 full year results in August.

We continue to be very well-positioned with the size, maturity, and quality of our development pipeline, with an ongoing focus on the timely and the disciplined execution of our projects of the highest portfolio value. During the half, we signed two long-term power purchase agreements with Tilt Renewables to offtake electricity generation from the Palmer wind farm in South Australia and the Waddi wind farm in Western Australia.

These PPAs further diversify our electricity supply portfolio and support our target to add 6 gigawatts of renewable and firming capacity by 2030. AGL was awarded a CIS contract for the proposed 600-megawatt Hexham wind farm in Victoria, as well as the allocation of 176 megawatts of peak capacity credits by AEMO to the proposed Kwinana Swift gas-to project in Western Australia.

Construction has commenced on the 500-megawatt Tomago battery in New South Wales, and the 500-megawatt Liddell battery is expected to commence full operations of the 500 megawatts in the fourth quarter of FY26, with progressive operation of the first 250 megawatts in this quarter. Kaluza has also generated some great momentum in the past few months.

As shared in September, the signing of a third major customer in ENGIE marked another major milestone in Kaluza's journey, boding well for the potential growth in other regions. More specifically, this multi-year, multi-market agreement marks Kaluza's largest deployment to date.

This deal more than doubles Kaluza's contracted meters, and importantly, adds to Kaluza's significant pipeline growth demonstrated over the past two years, with multiple platform deployments in retail and flex across six active markets. The retail transformation program continues to progress well.

Key capabilities have been deployed as planned over the last six months, with committed benefits tracking to plan. We've also signed a gas supply agreement with Esso Australia, commencing in 2028 for 40 petajoules, with gas to be supplied from the Gippsland Basin over a five-year period, strengthening our medium-term gas supply book.

Today, we're also announcing a long-term strategic partnership with Aussie Broadband, and the divestment of our telecommunications business, and I'll speak to this on the next slide. In early November, we announced an agreement to divest 19.9% of our 20% interest in Tilt Renewables for $750 million, with the agreement expected to complete in the third quarter.

We expect that the proceeds will be deployed towards our investment in flexible, dispatchable capacity, and provide additional balance sheet flexibility. As I mentioned, today we're announcing the divestment of our telecommunications business and a long-term strategic partnership with Aussie Broadband, with our approximately 400,000 customer services to be acquired by Aussie Broadband in June 2026.

This transaction delivers strong value, with AGL expecting approximately $150 million in proceeds in Aussie Broadband shares. Importantly, this move also establishes a long-term partnership where Aussie Broadband will deliver telco services under the AGL brand, ensuring continuity for our customers and creating a platform for shared growth.

We'll also have the opportunity to increase our equity interest in Aussie Broadband through incentives that reward telco growth under the AGL brand. Both organizations are committed to delivering a seamless migration for our customers over FY27.

Under this strategic partnership, AGL will act as a sales and marketing channel for Aussie Broadband's telco offers under the AGL brand, with clear incentive to support strong customer growth. Customer operations will be managed by Aussie Broadband, giving customers access to their award-winning service and high-quality products.

Customers will continue to benefit in the convenience and the value provided by bundling AGL energy services and telco services provided by Aussie Broadband. As such, AGL will continue to deliver the retention benefits evidenced by this bundled offering today.

Through this approach, AGL simplifies operations, supports growth in bundled offerings, and strengthens long-term alignment through an equity-based partnership that positions both companies to succeed together. Turning now to our operational performance for the half, starting with our safety, customer, and employee metrics.

Total injury frequency rate saw a marginal increase. However, this metrics remains significantly lower than FY23 and FY24.

This is a good result, particularly across two major coal-fired outages, where our contractor workforce increases significantly, and we continue to strive further to improve this metric. I've already spoken to customer satisfaction, which has increased to 83.8, and we acknowledge the lower employee engagement score of 69% from the pulse survey taken in November.

We are working closely with our employees to improve engagement across the organization, particularly in light of our recent organization restructure, which has seen a reduction in roles across the business. As I mentioned at the start, our Customer Markets performance was headlined by excellent growth in customer services, continued strong customer satisfaction, as well as margin improvement in a competitive market.

Total services to customers increased by 108,000. Growth in energy services was largely driven by the acquisition and the successful integration of Ampol Energy's customer base, approximately 45,000 services, and we also recorded solid growth in telecommunications and Netflix services.

Crucially, we've maintained strong customer metrics, including a leading energy brand, digital offering, and loyal customer base, with a favorable churn spread to the rest of market of 5.3 percentage points, again, a strong result in a highly competitive market. On the right-hand side, as we indicated at the full year results, you can see the improvement in consumer gross margin on the prior half, reflecting a return to more sustainable levels.

We've delivered a strong asset performance for the half, driven by continued strategic investment in our generation fleet, with commercial availability and flexibility remaining critical and highly valuable in a transitioning energy market. On the left-hand side, we've already spoken to our improved fleet performance for the half, largely driven by higher wind and hydro availability.

The two major planned coal-fired unit outages were both successfully completed with complex scopes of work designed to improve future reliability and availability. This strategic investment included a low-pressure heater replacement at Bayswater, low-pressure turbine replacement at Loy Yang, and an updated critical spares program to de-risk availability.

Crucially, availability is targeted to strengthen in the second half, and realign with the positive five-year trend in FY26. Our operated grid-scale battery fleet delivered an EAF of 99%, underscored by advanced analytics and continual control system enhancements to optimize charge and discharge performance.

During the period, the Torrens Island battery was also transitioned to AGL site management of operations and maintenance, with this operating model also to be adopted across the fleet of AGL batteries following commissioning, providing AGL strengthened control over asset performance. Turning now to a more detailed discussion of the first half fleet performance, where higher commercial availability and plant flexibility enabled AGL to generate value when market conditions were most favorable, despite a period of low volatility.

On the left-hand side, you can see we recorded a good increase in coal-fired commercial availability, primarily driven by stronger reliability and a lower unplanned outage factor. As mentioned earlier, the lower volatility captured was mainly attributable to the unusually lower spot price volatility that occurred in the NEM in this half, a function of milder weather and lower transmission constraints.

However, I'd like to emphasize that over the longer term, as the NEM transitions and coal-fired generation is gradually withdrawn, new variable renewable generation comes online, and the grid navigates new transmission build-out, we expect volatility to normalize at higher levels than observed in the first half. The NEM recorded 4.7 equivalent hours of market price cap just in January.

This is higher than the 4.4 hours recorded for the entire first half. Generation volumes overall were 2.8% lower, with lower thermal generation utilization partially offset by higher renewable output, particularly wind generation, which was supported by the commencement of the Rye Park wind farm.

Again, despite lower thermal generation volumes, higher thermal fleet availability, combined with almost 3.3 gigawatts of thermal fleet flexibility, enabled AGL to generate when market conditions were most favorable, delivering the strong realized supply-side pricing outcomes you'll see on the next slide. Encouragingly, our growing flexible asset fleet continues to deliver strong realized supply-side pricing outcomes for AGL.

I'll first point out that the unusually low volatility was observed in the NEM this half compared to the very high, strong prior half, which you can see within the orange dotted box. We expect this to lift in the second half, in line with the historical trend you can see on the right-hand side of that graph.

As I mentioned, over the longer term, we expect volatility to normalize at levels higher than observed in the first half, as the NEM undergoes a significant transition in the coming decade. Our flexible asset fleet continues to realize a premium above average market prices, a premium which has steadily increased since FY22, with a slight moderation in FY25, albeit with a good uptick in the first half of FY26.

Coal-fired flexibility investments and the inherent flexibility of hydro, gas, and batteries continue to underpin this premium. AGL is at the forefront of residential battery adoption, outpacing the market in capturing flexible load and associated value pools as customer demand accelerates.

The graph on the left-hand side shows the significant amount of storage required by 2035 as the NEM transitions away from coal-fired generation: 40 gigawatts by 2035 per AEMO's latest forecast, with only 10 gigawatts in the system currently. The right-hand side illustrates how we are capturing value and innovating across emerging residential battery-enabled value pools as the market evolves.

We've delivered excellent market share growth with our residential battery customer base, doubling over the past 12 months, outpacing broader market growth. We've also strengthened our flexibility proposition by launching AGL's first battery flexibility offering, Battery Rewards, alongside a partnership with leading battery brand, Sigenergy.

Our orchestration capabilities continue to expand, with the launch of AGL Community Power following the acquisition of South Australia's Virtual Power Plant from Tesla. In addition, we have significantly expanded OEM capability, driving growth in VPP sign-ups.

We're also innovating in emerging flexibility value pools through vehicle-to-grid trials and a network flexibility services pilot, Flex Together, in collaboration with Endeavour Energy. Encouragingly, there were positive indicators for the demand in the NEM, which represents a potential tailwind for electricity pricing.

We've seen peak demand records achieved in the NEM in 2025, as well as the continued strong long-term outlook for energy demand supported by electrification, data centers, and the expected continuity of smelter operations in New South Wales. The first graph shows a significant uptick in NEM winter demand recorded during the super-peak periods in 2025 relative to the last five years.

More specifically, in 2025, Queensland reached an all-time demand record in January, and New South Wales and Victoria reached winter demand records. As you can see, the NEM has progressively shifted to more elevated winter demand peaks compared to the summer peaks, partially explaining the earnings skew towards the first half that we've seen in recent years.

In the middle, you can see that AEMO forecasts significant growth in electricity demand over the next 30 years under all ESOO scenarios, with the major drivers of this expected growth being the electrification of the home, data centers, transportation, and the broader industry. Delving further into this, the right-hand side shows the forecast material uptick in data center-driven demand growth expected in the coming decade, driven by rapid growth in domestic data center development pipelines, particularly in New South Wales, Victoria, and the ACT, with significant supply required to meet this demand.

Overall, our transitioning energy portfolio, and particularly our growing flexible asset fleet, is very well-positioned to manage and leverage the upside of rising and reshaping customer demand. Concluding with market conditions before I hand over to Gary.

This slide shows the observable curves for both swap pricing as well as the cap curves. Forward curves remain flat in Victoria and have eased in New South Wales over the last 10 weeks, and I've already spoken to the drivers of the unusually low volatility observed in the first half.

Overall, AGL is largely hedged for FY27, and importantly, the current forward curves are not reflective of the favorable longer-term electricity demand tailwinds that I spoke to earlier, especially given a lot of recency bias is factored into the near-term forward pricing. Now over to Gary.

Thank you, Damien, and good morning, everyone. It is a pleasure to be here today to tell you about our very strong set of operational and financial results, positioning us to continue to pursue our strategy of reinvesting cash flows back into strong generating asset returns.

This slide shows an overall summary of our financial results, which I'll cover in more detail on the following slides. As Damien mentioned, our strong first half financial result reflected an improvement in operational performance, with an underlying NPAT of $353 million, and EBITDA at $1.09 billion.

As we communicated earlier, we had higher Customer Markets earnings as well as stronger fleet availability and flexibility and increased battery earnings, which helped mitigate the impact of unusually lower market volatility in the NEM. As we expected, EBITDA remained flat and underlying profit was lower due to higher depreciation and amortization and finance costs.

Today, we've announced a fully franked interim ordinary dividend of 24 cents per share, consistent with our targeted 50% to 75% payout ratio of underlying NPAT for the FY26 dividend. AGL also currently expects to pay a fully franked dividend for the full year.

I'll speak to our improved cash performance shortly, and one of the key drivers of the higher net debt was investing cash outflows as we press forward with the transition of our business. This included expenditure on the Liddell battery, K2 turbines, as well as the acquisition of South Australia's Virtual Power Plant for approximately $80 million.

Importantly, our significant investment growth, particularly our near-term focus on firming assets, aims to continue and is currently delivering high-quality earnings for AGL, with strong cash flow conversion as the business transitions. Additionally, our agreement to divest our equity interest in Tilt is a prime example of our ability to recycle capital when timely and prudent.

Settlement is expected in the third quarter, with proceeds expected to be redeployed towards our firming projects and provide additional balance sheet flexibility. We're also exploring future funding vehicle options for the deployment of a 2-gigawatt-plus wind farm portfolio.

Before I move on, I'd like to note that we have reviewed and restated our accounting in relation to the classification of a number of renewable PPAs. The net impact on the balance sheet is immaterial.

Furthermore, there is no impact on cash flow, and immaterial impacts on underlying profit and our credit metrics. Let me first take you through underlying profit in more detail.

Starting on the left, the stronger Customer Markets performance was primarily driven by margin growth across the consumer electricity and gas portfolios. Consumer electricity gross margin expansion was driven by customer growth and disciplined customer value management.

Consumer gas gross margin growth was attributable to margin initiatives and higher volumes driven by colder weather. The growth bar reflects the initial earnings contribution from South Australia's Virtual Power Plant, which we acquired from Tesla last July, as well as earnings from the sale of battery hardware, which has been supported by government initiatives.

As we continue our focus on disciplined cost management, Customer Markets opex was lower due to ongoing initiatives to deliver operating model benefits, partially offset by higher net bad debt expense due to revenue increases. Moving further to the right, despite stronger fleet availability, Integrated Energy's earnings were impacted by lower coal-fired generation volumes, as well as a reduction in volatility captured compared to the prior half, with the prior half being a period of very high volatility.

The positive $10 million bar for batteries reflects the full six months of operation of the Broken Hill battery, which was being commissioned in the prior half, as well as stronger performance from the Torrens battery. As I'll touch on in a few moments, we're very pleased with the continued strong performance of our 300-megawatt operational battery fleet, which delivered a $35 million EBITDA contribution for the half, a very strong financial result.

Continuing with our cost discipline, Integrated Energy's opex improvement was driven by a reduction in unplanned coal-fired outage days compared to the prior half, divestment of the Surat gas project, as well as savings through productivity and optimization initiatives. The slight increase in centrally managed expenses was mainly driven by IT hardware and software costs, as we continue to invest in our technology offerings and capabilities.

At the full year results, we indicated an uplift in depreciation and amortization in FY26 of approximately $100 million. This increase is largely attributable to the continued investment in our thermal assets with a shortening useful life, growth, including the expected commencement of the Liddell battery, as well as higher rehabilitation asset base.

Please note that we are now revising down our expectation of the uplift in depreciation by $40 million to approximately $860 million, of which some of this is driven by an ongoing decrease in environmental rehabilitation assets, primarily at AGL Loy Yang, with the confirmation of bulk water entitlements costs. The increase in finance costs was largely driven by the higher net debt position as we press ahead with the transition of our business.

Finally, lower income tax paid reflected the decrease in underlying profit before tax. We initially indicated a 3% increase in FY26 operating costs back in August.

However, with a disciplined cost focus, we are tracking better than initially expected, now forecasting just under a 2% increase. The impacts of inflation in FY26 are expected to be more than offset by the significant and accelerated productivity initiatives that have been implemented across the organization.

Today, we are also giving further detail on our cost out program in FY27 that is targeting an overall sustainable cost benefit of $50 million per annum after CPI, with CPI again expected to be fully absorbed by productivity benefits in FY27. Briefly touching on capex.

In line with our strategy, approximately $760 million is expected to be spent on growth this year, with the majority of capital deployed to advance our high-returning firming projects, being approximately $650 million. This growth outlay is expected to comprise roughly $190 million for the remaining project costs for the Liddell battery, with first operations and revenues expected in the third quarter.

In addition, it includes approximately $360 million of the estimated $800 million total project cost for the Tomago battery, with the bulk of the remaining spend expected in FY27. For the K2 turbines, about $85 million is expected to be spent in FY26, with the remaining spend in FY27 approximately $100 million.

Additionally, Customer Markets growth spend will focus on broadening our energy-as-a-service offering for commercial and industrial customers and electrification solutions. This significant investment in growth is the key to unlocking future value for the business.

Please note, the FY26 sustaining capex forecast is unchanged from August. As I mentioned before, our 300-megawatt operational battery fleet continues to deliver excellent performance, with $35 million of EBITDA contribution for the half.

This is despite a period of unusually low volatility that we observed in the NEM during the half. Based on 30 months of performance from FY24 to half year 26, the Torrens battery is generating an excellent annualized yield of 24%.

Just to be clear, this is calculated as annualized EBITDA divided by the total project capex costs of $189 million. Given the strong operating performance of both the Torrens Island and Broken Hill batteries, we remain confident in targeting the upper end of our 7% to 11% IRR range for our grid-scale battery projects, noting that these are ungeared post-tax asset-level returns.

Just a reminder that we have 1,000 megawatts of projects which are under construction and expected to be online in the coming years. The Liddell battery is expected to commence full operations in the fourth quarter of FY26.

This is the entire 500 megawatts, with the commissioning of the first 250 megawatts targeted for the third quarter. The Tomago battery is expected to commence operations in late 2027.

The graph shows actual and expected earnings for existing and committed projects only, noting that we have a few more late-stage battery projects which we are focusing on, which I'll highlight on the next slide, with each project expected to take roughly two to three years to build once it's reached FID. This significant investment in firming assets aims to deliver high-quality earnings for AGL, with strong free cash flow conversion as the business transitions.

Importantly, we continue to advance our development projects and pipeline, which now stands at 11.3 gigawatts. We have excellent optionality within the pipeline, and seek to deliver projects of the best strategic fit and expected returns that exceed our hurdle rates.

On the left-hand side, you can see the priority late-stage battery and wind projects which we are focusing on, which includes the 500-megawatt Tuckanoot battery in Queensland, and the development of wind farm and battery projects for the Pottinger Energy Park together with our joint venture partner, Someva Renewables. I'm also pleased to share that we're also exploring future funding vehicle options for the development of a 2-gigawatt-plus wind farm portfolio.

We have extensive experience in capital partnering with Tilt since 2016 to accelerate the deployment of wind and solar generation in Australia, and look forward to updating the market in due course. Please note that AGL is no longer pursuing the Gippsland Skies offshore wind project.

Turning now to cash performance, which was headlined by an improvement in underlying cash flow and cash conversion. I'll run through some of the key movements.

Underlying operating free cash flow was $24 million higher, driven by the unwind of government bill relief to customers in the prior corresponding period, partially offset by an increase in margin calls in the current period. The majority of the significant items relate to the continued implementation of the retail transformation program, and other investing cash flows include the acquisition of SA VPP for approximately $80 million.

As you can see at the bottom of the screen, operating free cash flow excluding the impact of bill relief timing was $9 million higher, largely driven by lower income tax payments, partially offset by higher sustaining capital spend on our thermal assets to maintain availability and reliability in a transitioning market, as evidenced this half. Encouragingly, our cash conversion rate, excluding margin calls, rehabilitation, and the timing of bill relief, increased by 3 percentage points to 93%.

I will conclude with a discussion on net debt, credit metrics, and our strong funding position before I hand back to Damien. Starting with net debt, where one of the key drivers for the increase was the roughly $320 million spend on growth and strategic acquisitions.

This included expenditure on the Liddell battery, K2 turbines, and the SA VPP acquisition. The other drivers were the $168 million worth of fully franked dividends paid to shareholders, and prudent spend on the flexibility and availability of our assets.

Importantly, we also maintain our Baa2 investment-grade credit rating, with headroom to covenants. Turning to the right-hand side, where our funding remains strong following the successful issuance of a $500 million AMTN in September across seven and 10-year tenors.

Impressively, this issuance was more than 10 times oversubscribed, an excellent outcome heralding AGL's return to the public bond market after 10 years, and continued evidence of broad lender support as we continue to deliver on our business strategy and decarbonization plans. Our liquidity position remains healthy at almost $1.2 billion in cash and undrawn committed debt facilities.

Average debt tenor has increased marginally, and we don't have any major debt maturing until FY27. The Tilt divestment proceeds are also expected to settle by the third quarter, providing balance sheet flexibility and a source of funding for our firming projects.

Thank you, and handing back to Damien.

Thanks, Gary. I'll now conclude by talking to FY26 guidance.

As I mentioned at the beginning, we have narrowed our FY26 financial guidance ranges in line with strong first half performance, driven by consumer margin improvement. Full year operating costs are expected to be lower than previously indicated, driven by disciplined cost management, and depreciation is expected to be lower than indicated last August due to greater water price certainty on a future rehabilitation of the Loy Yang mine.

As expected, earnings are skewed to the first half, in line with typical seasonality of customer gas and electricity demand, as well as the gradual roll-off of lower price legacy gas supply contracts. Importantly, we're also targeting $50 million of sustainable net operating cost reductions in FY27.

Overall, it's been a great first half. Thank you for your time, and I'll now open to any questions.

Thanks, James. Good morning, Damien, Gary, and the broader team.

For my question, I might start with pointing out that a lot of investors have been inquiring in recent months about the impact of the lower wholesale pricing outlook being priced into the futures market. AGL's result today indicates that your electricity portfolio remains in the money, with stronger realized price premiums compared to average prices, and the batteries are performing well despite lower than average volatility.

My question is, can investors be confident that, provided AGL maintain good generation availability, there's upside risk to current market estimates into the medium term for underlying EBITDA, which are currently forecast to be near flat over FY26 to '28?

Thanks, Tom. Good morning, all.

Look, let me sort of break that question down a little bit. What I would say is what we've seen is a decline in the New South Wales market in the last 10 weeks.

I would not call that a structural trend whatsoever. We saw really mild both weather and good generation over that period of time.

I would classify this as winter is the new summer. It really is.

The type of volatility we saw was really unusual in that first half. We called out we saw 4.4 hours, which is incredibly low in that first half.

We saw 4.7 hours alone in January in one month. We see it returning to cyclical norms, if you like.

The other big driver behind all this is demand. Demand is going to have a big role to play.

We saw a number of records broken over the first half in three states. That peakiness and demand is going to be there.

That's where our confidence lies. In terms of your question on the asset itself, we're really pleased.

Exactly what we said to the market back in August, we're expecting improved availability. What to think about those assets and the way they play, it's that commercial availability that's also incredibly important, and the flex we can get out of all of our portfolio, not just those coal assets.

You can see through our results that flexibility really enabled us to deliver a strong result on the generation side.

Thanks, Damien.

Morning, team. Thanks for the update.

Just initially, hoping you could step through what's driving these PPA restatements to leases. With the $45 million EBITDA benefit we saw last year, be fairly consistent with '26?

Just trying to split out of the guidance increase, how much of that would be from the accounting change and how much would be underlying?

Thanks, Henry. Firstly, we've obviously made the decision to restate the accounting of those legacy PPAs.

What's most important is there is no impact on cash at all, and there is very immaterial impacts on the P&L, the balance sheet, and just as importantly, the credit metrics. You can see in the prior period comparisons the adjustments there, and you've quoted some numbers.

What I can say in the current period is those number adjustments are very immaterial, and certainly much lower than the prior period. In our consideration, they're very immaterial and we should take that into consideration.

There is some moving geography of these adjustments, in the balance sheet, effectively, what we've done is we've reversed some of the onerous provision, and we've created a corresponding lease liability and right-of-use asset. Again, you can also see a very immaterial impact on the balance sheet.

Okay. Thanks, Gary.

Good morning, all. I just wanted to follow on from Tom's question, because it sounded like interconnector issues is going to be solved, or we'll have a better interconnector at some point with South Australia.

Demand is increasing, which we all know. Volatility is still going to be there, or your expectation of high volatility comes from, is it coal generation coming out?

That seems more longer term. Just trying to understand the confidence that you have in that high volatility in the more immediate term before that coal generation ultimately comes out, please.

Sure. What we did, we included a couple of slides in the deck.

Slide 13 is probably the one I'd point you to. One, you can just see how H1 25 was a very high volatility period.

H1 26 was unusually low. We saw less transmission constraints in that half as well.

If you look then into H2, if you look where the trend is, those trends are often higher in H2 as well. Our confidence is not so much that there won't be different periods with some higher volatility, some lower volatility, it's over the cycle, we see volatility in the system.

That's how the system was designed, and as both new assets come in and new assets come out, we will see that volatility continuing to play through the marketplace, and we see H1 26 is unusually low.

To follow up on that, you're not seeing a reduction in volatility as more households take up battery, solar, and that interconnector comes back in line? Oh,

look, I think the way to think about it, if you look at what is required in this marketplace, it's almost 45 gigawatts of new battery capacity. It is enormous what's required, and there's roughly 10 in the market today.

A huge amount needs to be built over the next 10 years, and therefore, also as you're seeing assets come out of the market, you're going to see that volatility continue to move through the cycle. I think battery volatility will continue to play a role.

That's why we're continuing to invest in large-scale batteries, because we think there is still enormous value in those batteries, and we're making some good progress then on bringing more online.

Thank you.

Good segue. Congrats on the result.

Can you just talk a bit more on the batteries? You've talked about firm batteries coming online for now 12 months, and you haven't made an FID.

I'm sort of intrigued on what gets you to that FID. I'm sort of interested in the government batteries coming out at the retail level.

Are we seeing any sort of implications at the retail level for demand growth, because they would probably replace some of the need for grid-scale electricity?

Thanks, Ian. Breaking down the question, first part was on firm power.

We continue to make great progress there on that particular portfolio. We haven't brought any to market just yet.

I think the way to think about this, we are using absolute capital discipline to bring the right batteries to the market at the right time. That doesn't mean we won't bring anything from firm power.

We've got a number at the moment in the pipeline. The ones we're obviously bringing to market first have been Tomago and Liddell, they were the ones to progress.

We'll continue. I think the answer is, you'll see in time some of those batteries come into the portfolio.

We've got a huge amount to build over the next, what is it, three to four years, and so you'll see us progressively rolling those through based on where we think we get the greatest returns in the greatest part of the market. Then if I turn to your second part of the question, which was around the consumer, interestingly, and what has it been, 250-odd thousand batteries now, what we've seen in some cases, which I think is also interesting, is some of those customers are ending up using more energy as a result through this.

I think what we need in the system, though, we need to be able to orchestrate those batteries to ultimately share value between the customer and the system, but also then so we can help manage some of that demand. I think both the residential battery and grid-scale batteries will play a role, and that's why, if I think about Joe's customer business, we're outperforming at the moment in terms of a number of batteries.

We are both contracting, but also joining the VPP. We made a big change back in, I think it was December, to enable us to connect significantly more batteries into our systems.

In the past, it was quite limited, so that's seen a lot more people connect in now. It is now about making sure we make this as simple as possible for our customers.

The transition is complex, we want to make sure it's simple for them, and that they also get that value from the battery on the way through.

thank you very much, and congratulations to Damien and the executive team on a good result. My question relates around your lowering costs and exposure to the low negative prices.

To what degree has Bayswater's two-shifting strategy helped reduce costs and lower exposure to periods of low and negative prices, and how is asset fleet availability going to improve through the second half of FY26?

Thanks, Gordon. If I just start on the cost piece first, we've obviously announced today targeting a $50 million net, and I make it clear, net cost reduction into FY27.

What I mean by that is that is after absorbing inflation as well, it is a significant number. It's across both labor and non-labor through the whole organization.

Never an easy thing to do, but we're making good progress on it. We're seeing the benefits even in the half starting to roll through, and you'll see the full-year benefit into FY27.

In terms of your question on Bayswater itself, we are still continuing to do the two-shifting trials, and we will continue to do that. We're seeing some great success, the team is doing a great job.

We've run a number of trials, I actually don't know how many now, because it's been quite numerous. For us, it's about really now getting our hands on all of the data, all the information, both from a trading perspective and an operational perspective, we can optimize when those assets both come out and into the system.

The last one we did, I think we brought in and out within 30 seconds of our targeted time, so that's pretty impressive on big kit like that. Again, we're still in that pilot phase.

I think the way to think about assets like this, both Bayswater and Loy Yang, is there'll be optionality around two-shifting, there'll be optionality about mothballing, there'll be optionality around sweet spot running. They're all the sort of things we're working our way through.

As you get into the next five, 10 years, you're actually making decisions on how you run the assets very differently, but you've got the data behind it, because to your point, what's critical, and as we said at the full year, is getting asset availability to where we wanted it to be. You saw that come up in the half, and which was great to see.

We see further improvement into the second half. That's all around the investment we're making in the assets, both on availability and flexibility.

We'll continue to see improved performances in the fleet.

Good morning. Allow me to join the queue of people congratulating you on the result.

I don't know if you've got your full management team there, I thought we might try and ask a question and give some of the other team members a chance to speak. Mr.

Brown flagged a new 2-gigawatt wind vehicle potentially coming to market. Can you maybe give us some color on that in terms of what kind of PPA prices are you seeing?

Does AGL need to provide capital to that vehicle? What kinds of things are you needing to see to reach FID on new wind farms at this point?

Rob, are you suggesting you're sick of hearing my voice? I'll hand straight to Gary.

Oh, dear. I wasn't suggesting that in any way.

Hi, Rob. Look, it's very early, preliminary stages around the option of a funding vehicle.

We are exploring that at the moment, and if you think about it, we've got a number of wind projects that are very exciting opportunities, of which one of them has already got a CIS awarded to it, which we're terming coming hopefully to FID in the next, let's call it 12 to 24 months. We have flagged in the past that we would be looking at funding capital opportunities for those.

As I said, it's early days, but we would be looking at introducing a strong, high-quality funding partner into a potential vehicle. We would likely take a small equity stake in that, but we'd be really looking to partner up with someone with a low cost of capital ultimately.

Difficult to talk about what PPA prices are, it's way too early, but, as you'd expect, they would be typically market-driven type prices.

Great. Thank you.

If I can sneak in a second question in the same kind of ballpark, with your K2 expenditure, you've given us the turbine costs. I presume you haven't yet reached FID, but could you maybe give us a sense of what kind of balance-of-plant costs we should be thinking?

Rob, look, I won't give you that at this point in time. We're continuing to work our way through that.

Look, we're really positive around the WA and the growth in that market. I think let me just say, watch this space as we continue to work through that.

You're right, we've given you the engines, we haven't given it to you all yet, but we'll continue to watch that space because I think the growth in WA with both the peaker and Waddi wind farm and that business, we're really excited about what we can do over there. I'll come back to you at another time.

Okay. No problem.

Thank you so much.

Morning, team. Just firstly on the $50 million cost out program, I just wanted to confirm slide 20 where you've showed that sort of cost step-up for '26 on the forecast.

Are we to assume FY27 costs are then 1,780? Is that right, or is some of the cost out being realized this year?

The way you should look at that, Dale, and I'm sort of repeating Damien to a certain extent, is it's a $50 million net reduction, so that's obviously after the impacts of inflation. We would expect that we would see roughly a $50 million reduction year on year.

On that, okay, year on year. Then as we think about the EBITDA comment you'd said previously around flat EBITDA outlook, that was obviously before this cost out and before electricity costs fell away a little bit.

Should we be thinking about they're the two big moving pieces for '27 and they're largely offsetting each other still, or are there other moving pieces we should be thinking about?

Just to be really clear, we have not guided for FY27. I think that the discussion there was around probably consensus versus where we've put out forecast out.

We have not provided any guidance into future periods at this stage.

Okay. Can you maybe provide some comment on the moving pieces that we should be thinking about?

It seems like cost out, electricity price, but growing battery earnings. Is there anything else we should think of?

I think that's right. It's cost out, one, well, not one, but not in a particular order.

Two, it will be movements in the wholesale electricity prices. Then three, I think, ongoing performance of the business and operational performance, plant performance, that's the other one.

Battery, I forgot battery earnings. We said that in last results too, Dale.

We still stand behind that position where we said last August that battery earnings, as the batteries come in, will more than offset the loss of earnings from coal and gas. I think that's an important statement to continue out there, because the battery performance is going better than we had anticipated.

You can see that through the results, and you can see that's why we continue to invest heavily there.

Thanks, guys.

Thanks, team, for taking another one. Just interested in the Bayswater-Tomago contract expiry.

Can you share how you're expecting, maybe Snowy would supply that power, and whether Bayswater would need to support in a kind of swaps, or what prices you might expect as that contract rolls?

Thanks. Firstly, pleased to see that Tomago smelter will still be in the system from both an industrial point of view and people point of view.

We don't have any details yet as to how that will play through Snowy. All we understand through the press, it will go through the Snowy vehicle.

In terms of how Snowy then is able to service that, that's really a question for Snowy. From our perspective, we've obviously got one of the lowest cost or we have the lowest cost generator in New South Wales.

We are well-placed in the market whether that's Snowy or other opportunities.

Got it. Thank you.