Contact Energy Limited (CEN.NZ) Earnings Call Transcript & Summary

And welcome, everyone, to our presentation of the FY '25 results, and we're delighted to be here. You'll see on the front page, we've got a photo of the battery project at Glenbrook, which we're delighted about, making excellent progress. So without further ado, let's get into it. On my left is Matt Forbes, our newly appointed CFO. Usual disclaimer just around information, just note it as we go into the presentation. And so look, today, Matt and I will be sharing the presentation. I'll go through the highlights and the market update. Matt will take you into the details of the financial results. We'll jointly give a bit of an update on Manawa and strategic delivery. And then as usual, we have an abundance of supporting materials, which allow further analysis. Look, FY '25 has been a good year. The financial performance has been very strong with the lift in EBITDAF -- underlying EBITDAF up to $774 million. The NPAT obviously has followed that with the lift in dividend. The portfolio change, the acquisition of Manawa. We got the keys to the door on the 11th of July. The integration is well underway, and we're absolutely delighted with the acquisition and continue to be. Tauhara and Te Huka 3 both came online, delivering on an annualized basis, the best part of 2 terawatt hours, and we continue to have $1.1 billion of projects under construction with KÅwhai Park, Glenbrook Battery and the Te Mihi Stage 2 project, all making excellent project. On the demand side, we announced this morning the New Zealand Steel deal and as well as that, the electrification of Fonterra at the Whareroa plant as well as the Greymouth and OMV contracts. But more than that, over 140,000 households are choosing either discounted or free off-peak energy in our mass market, and that is all part of the story around creating resilience in the New Zealand electricity market and helping New Zealand decarbonize. In all this, we believe we have delivered for shareholders. Our entry to the MSCI was a recognition of this as well as our continued representation in the Dow Jones. And we're delivering for the market. We have worked hard in these last 12 months, securing the best part of 6 petajoules of Methanex flex to support the market in what were 2 dry sequences. We've also secured medium-term gas supply out to 2032, and we ran Taranaki, the combined cycle plant for an extra season, and that plant is coming to the end towards the end of this year. At the same time, we've refreshed the leadership team, preparing us for the next stage of the strategy as we look to refresh our strategy. Jack Ariel, after doing a stellar job, retired as Major Projects Director. Matt Forbes was appointed CFO, and we're delighted to welcome Carolyn Luey to the executive team as Chief Retail Officer. In terms of the details, look, you can see there everything going in the right direction in terms of EBITDAF profit, the operating free cash flow, the dividend per share, the ROIC continues to recover from its low in the middle of the last decade, dividend per share. It was a challenging time in the market. But as you can see there, we responded, not having 1 but 2 historically dry periods at the same time, as the upstream gas supply market declined by 20% in the best of times would not be easy to manage, but we responded to that. Geothermal output rose by 34% in that period. We retained TCC. We extended the AGS storage, and this enabled us to do those deals with Methanex. In the medium term, we can see ongoing gas scarcity. We can see that feeding into the market if we don't respond. And that means we have to continue that journey of building renewables. We have to continue at securing long-term gas. We can have to continue with strategic partnerships like Fonterra New Zealand Steel for decarbonization. But we also have to make sure that we integrate Manawa into our portfolio well because that portfolio flexibility and resilience is absolutely critical to supporting further renewable build. Four years ago, we put in place Contact26, and this slide in a very complicated way gives you how we've done. We have achieved a large number of those targets. You see significant greens up and down there. The one red on that page is where Southland Wind resource consent got declined by others and wasn't necessarily in our control, but we continue to work there. We have delivered on the growth in demand. We have added the flexible demand scope in the last year. We have delivered the FID for Te Mihi 2A. Te Huka 3 came online. The battery is on track. KÅwhai Park is on track for bringing online middle of next year. We have continued to create outstanding customer experiences by also not putting up the retail prices by more than roughly what inflation is going at, and the multiproduct customers have grown significantly in that period. We're delighted in short, with both the year that's been, but also the delivery of that longer-term Contact26 strategy, and we look forward to its renewal and refreshment later this year, as well as Manawa, which we'll come to later. We do have a significant number of projects under construction, Te Mihi 2 Stage geothermal. You can only photograph that site with a panorama version, photo. It is a huge site with a huge amount of earthworks. It's impressive. And when we come to Investor Day later in the year, I would be very hopeful that we can get you around to show you what it is like. Glenbrook-Ohurua battery, we're delighted with the progress there. You can see the site physically is as well as can be complete. They're now starting the last hookups. And we are hopeful that, that comes online towards the end of the year, early next year. Absolutely delighted with the progress on that. KÅwhai Park solar farm, what you see there, photographed is what they call the Golden Row. It's been a bit of hard work to get that in. They've got it in. And what they do is they take that row and they repeat it again and again and again. And we're looking forward to that coming online in the middle of next year. Delighted with the progress across all 3 of those renewable projects. Just in terms of the market, and I know there's been a lot of commentary. So it's worth just pausing and making -- giving our views of what happened in the last 12 months. Demand actually declined last year. A large part of that was also -- was the demand response from the smelter responding to the conditions that were experienced in the middle of last year and a slightly warmer winter. And there was a drop, obviously, with the closure of the Winston Karioi pulp mill and the Tangiwai sawmill. There was a decline also in the South -- at South Canterbury irrigation. Balancing that as the Pan Pac's plant at Whirinaki came back online, we saw that demand come back on. But overall, normalized, it was pretty much flat. You can see that 1% year-on-year long-term average. We maintain a very positive outlook on demand growth. Notwithstanding the dry conditions last year and the closure of the [indiscernible] industries in particular, we can see the market increasing to -- we expect around 46 terawatts by 2030. And that is off the back of confirmed conversions, the Whareroa conversions and other Fonterra conversions, which are underway. Dairy metals, New Zealand Steel, we can see data centers already coming into the market, and we can see residential growth as well. So we expect that, that growth will continue over the medium term in particular. And so that outlook looks positive. As I mentioned, last year was characterized not by 1, but 2 historically significant dry periods. You can see winter '24 and then summer '25 were dry, and that led to hydro generation, not just for us, but for others being significantly lower than previous years. You can see that '25 compared to '23, down some 6 -- to almost 6 terawatt hours. The market, to a large degree, did cope with that through the increased geothermal that was deployed into market, but also the growth in geothermal compared to previous years and wind as well. So you can see that renewable wind, that renewable build mitigating that drop-off in hydro that we experienced. And that will only serve to further diminish the amount of thermal in the market as we go forward and we return to a normal hydrology. Obviously, Tauhara and Te Huka 3 were absolutely key in that. But also the Methanex flex that was deployed not once but twice was also critical in making that thermal generation available to the market. Interestingly, and what's been done here is showing the linkages. If you go back one slide, those periods of dry 1 and 2 coincide with those peaks. That is a market responding to dry periods. The long-term price, we expect to be roughly about that [ $126 ]. So the market is volatile. What has caught everyone by surprise is the rapid decline in the upstream gas supply market. There is no hiding from that. But I think the response of the market to that has been exemplary with over almost 7 terawatt hours brought on in 7 years. That's a terawatt hour a year of renewable build every year, which is roughly 10 PJs a year equivalent in gas flow generation. That is a good response. That is a market working to incredible volatility. We continue to believe strongly in retail, mass market retail. We continue to see the growth in connections and the growth in the netback. That netback is growing on an energy basis at or around inflation. It is challenging for households at the moment in the market. Look, no one should hide away from that. And the increase in lines charges is something that we're all concerned about, and we have to work on as an industry to make sure households are protected against that volatility, which I referred to before. That will keep the pressure on prices, but we absolutely fundamentally believe that the solution to this is build more renewable energy, and that will bring those upward pressures caused by the collapse in the upstream gas market, that will mitigate and soften those over the medium to long term. Look, there are challenges in energy. Energy is always a fundamental human need. And as a result, there is a high degree of volatility. But if you think across the board, I do strongly believe that both the market and Contact have responded well to those challenges, whether it's energy well-being, where we now, as an industry, see disconnection as absolutely a last resort, and we are focused as an industry on energy well then. We've removed as Contact Energy, all disconnection and reconnection fees to make sure, and we've worked hard to minimize the number of disconnections we have, and we provide free power and broadband to women's refuge. We're investing at pace. We could not go further faster. As I said, almost 7 terawatt hours in 7 years. There is now 335 megawatts of grid-scale batteries either under construction or in the market, where 2 years ago, there was nothing. We have brought on those baselines, 225 megawatts of baseload renewables ourselves, Tauhara and Te Huka 3. We've got the battery in solar and Te Mihi 2A is well underway. We are looking for a more favorable consenting environment. The government has worked hard in this space, and I do want to acknowledge the efforts I've made to unjam this country and to get development underway. We were obviously frustrated with the decline of Southland Wind. We look forward to that fast-track resource consenting, really giving a boost to economic growth and in particular, enabling more renewable energy investment. We have worked hard on fuel security. Obviously, the signing of the NZAS deal, but also the Huntly HFO provides long -- medium to long-term security to the country. And also, we're developing the muscle fitness around flexing Methanex as dry years hit us to make sure that we don't have necessary A, B or C, but D, all of the above that has always got to be the answer. We were part of that HFO agreement, and we've also secured up to 10 PJs a year in additional gas supply out to 2032. And look, the renewable energy boom that is on at the moment. Now New Zealand is investing double any other country in the OECD per capita. And you can see the benefits of that renewable energy boom that's going on in the towns like Taupo and in the provinces. And that can only be a good thing for the country, not just in the security of supply it creates, but the jobs of every type that are created in towns and cities that need them. We will continue with our geothermal investment over the next decade. To give you an example, Tauhara had over 4,000 people come through the gate in its building and Te Mihi 2A and Te Huka 3 are part of that same story. And that is something I think as a company, we should be incredibly proud of. Now handing over to Matt.

Thanks, Mike, and it's a pleasure to present Contact's FY '25 results to you today. Contact has delivered a really strong performance in the face of really challenging volatile market conditions. And notably, we surpassed our initial EBITDAF guidance of $770 million and the updated $790 million, which excludes Manawa transaction costs, which were set in February. This outcome shows the resilience of our business, which is underpinned by execution across our growth development pipelines, the resilience of the portfolio of assets that we have within our mix and also the strength of our customer relationships. It also speaks to the dedication and capability of Contact's people, who continue to support New Zealand's decarbonization. Let me start with highlighting some of the key themes from the financial performance and how those themes have shaped our performance. They really set the context for the year, and I'll expand on these as we progress through the presentation. A significant milestone for Contact was the commissioning of those 2 geothermal power stations in -- on the Tauhara field in the Taupo region, delivering around 5% of New Zealand's total annual energy demand and offering renewable baseload power, which is not dependent on weather, and we've seen how important that is with the year that we've just had. Tauhara generated 1,255 gigawatt hours in the financial year at a capacity factor of 82%. So despite this lower generation as the plant ramped up, Tauhara on its own delivered $226 million in EBITDAF, a 12% return on invested capital. This represents a strong first year on our marquee $1.05 billion investment, which includes the capitalized interest on the project. In addition, Te Huka 3 has generated at a capacity of 54 megawatts since it came online in mid-December, which is above the 51-megawatt business case. The second major theme was Contact's role in supporting the market during a period of heightened volatility. 2025 started the year with very low hydro storage inflows, which were below average and included 2 historically dry periods. At the end of that first period between May and August of 2024, national hydro storage was at the third lowest level ever recorded. And then earlier this year, in January to March, the major catchments had their lowest inflows in the 99-year history. Contact itself was really well positioned, and we did not need any more fuel to support our customer load, but we actively supported the wider market by purchasing around 5.6 PJs of gas from Methanex, as Mike mentioned. Methanex paused their methanol production during those 2 periods, enabling Contact to fuel the Taranaki combined cycle plant, which ran for another winter and used our access to gas storage to facilitate further electricity sales to Meridian and Mercury, who are short of fuel. We put over $100 million online to purchase this gas and recovered a significant proportion of this from those contracts and used around 1/3 of the gas that we purchased from Methanex for these electricity sales. The balance was unsold with 1/3 used to top up our storage facility so that we are well set for winter 2026. Another key theme was the commencement of a 20-year supply agreement with the New Zealand Aluminum Smelter, and that was a key feature of our results. This contract not only delivers the term, which helps with build, but improved pricing and a demand response mechanism. In FY '25, Contact's 25% share of the demand response called was the equivalent of around 150 gigawatt hours of acquired generation. We paid around $45 million for this call and spot prices end up only delivering half of the value of that cost. This really reflects the difficulty that we have of managing hydro risk. We paid for demand reduction in a period, which quickly switched from very dry to very wet with surplus hydro and very low spot prices in Q2. Clearly, this call didn't deliver the value for Contact in this financial year, but it has a lot of value for the market. It supports industrial customers, reduces generation from coal and will provide the flexibility required as thermal plants shut and we continue to decarbonize. Additionally, the FY '25 EBITDAF reflects a $98 million write-back in the onerous contract provision we raised several years ago, and that is due to improved price spreads between summer and winter seen in the forward curve as well as expectations that we will now be able to store around 3 PJs of gas in this facility. While this is a noncash item, I'm calling it out because it increases our reported EBITDAF in FY '25, but doesn't reflect the operational performance for the year. Turning to our financial performance. We have adjusted EBITDAF to exclude the fair value movement in the onerous contract provision in both periods to provide a clearer comparison to the underlying performance drivers. Underlying EBITDAF for FY '25 was $774 million. That is up $111 million on FY '24. The volume impact of the new generation I mentioned at the outset was significant with a net 0.8 terawatt hour increase in renewable generation, which was driven by the 1.2 terawatt hours of new plants coming online, offset by the lower hydro we received in the period. The combination of these 2 factors added $133 million to EBITDAF. Pricing continued to support performance with long-term channel pricing up by $46 million through new NZAS pricing and a 7% uplift in the integrated retail contribution on FY '24. The pricing of our market-linked channels was also up by $36 per megawatt hour, contributing $151 million. This demonstrates our ability to meet market demand for energy during periods of fuel stress. Notably, on the cost side, the pricing impact from the Methanex gas and acquired generation reduced EBITDAF by $185 million. Other income decreased by $3 million, of which $12 million relates to the loss on sale of 2.3 PJs of gas that we didn't need that we purchased from Methanex, and fixed operating costs rose by $31 million, which is led by operating cost increases. That includes $18 million related to the Manawa transaction. On the left-hand side, turning to the movement in underlying net profit. Underlying net profit increased by $31 million or 13%, primarily driven by the $111 million rise in EBITDAF. Depreciation increased by $18 million on FY '24, and there was a $39 million increase in depreciation from Tauhara coming online, which was offset by the lower thermal asset generation during the period. Interest costs rose by $65 million, which is predominantly attributable to the cessation of capitalized interest. In the previous financial year, the Tauhara capitalized interest was around $61 million. Fair value movements in financial instruments was $43 million down on FY '24. Of that, $10 million relates to the movement in realized market making losses, which totaled $13 million in FY '25, so a cash item. It must be noted how impressive the performance was from the team in the second half of the year to end up with a $1 million gain in that second period. The remaining $33 million of the unrealized losses in the fair value of financial instruments relates to our 2 new long-term contracts with NZAS and KÅwhai Park, and that reflects the mark-to-market of where the price path is currently trading against expectations at the time that those contracts were entered into. So all relate to future periods. In FY '24, you'll recall that we had write-offs of around $50 million due to the engine peaker damage as well as costs associated with repairing the steam hammer event. So this results in a $49 million improvement on this year and tax interest expense increases on the underlying profit performance, but not as much as you'd expect as in the previous year, the removal of tax depreciation on buildings of $8 million was included. On to the high-level performance of our business segments. Performance highlights the strength of our wholesale business with EBITDAF rising by $149 million to $895 million in the period, supported by those higher renewable generation volumes I mentioned and improved prices. Those gains were partially offset with the higher costs of generation, in particular, when those thermal assets were required to support the dry periods. Our retail business recorded an EBITDAF loss of $49 million, which is down $17 million year-on-year as competitive pressures continued. Rising network and energy costs outpaced the tariff increases. And this underscores the ongoing importance of discipline within the retail business as it supports our performance and ultimately provides continued support for our renewable growth pipeline. Corporate costs increased by $22 million to $73 million, mainly reflecting those Manawa transaction and integration costs. Those are time-bound investments that we expect to get lots of value from during the acquisition. On to our wholesale business and starting with the generation costs, you'll see that renewable generation increased to 88% of total output, while thermal generation reduced by about 0.5 terawatt hours. It seems counterintuitive then to see a generation cost rising by $68 million, and that relates to the cost of gas and acquired generation during the period, which nearly doubled from $116 a megawatt hour to $200 a megawatt hour. That reflects the new normal. In addition to those new geothermal power stations online, we had major turnarounds at our Te Mihi and Ohaaki plants throughout the year, and TCC contributed very strongly to winter capacity during its final year of operation. It achieved an availability of 89%. Following TCC's closure, the importance of the peakers becomes clear with the expectations set for an improvement over the 70% availability recorded by these units over FY '25. Hydro generation was down by 9% on FY '24 and 15% below our long-term average expectations, marking the lowest output from hydro that we saw at Contact since FY '12. And that really supports why we have been so excited about the performance of this financial period. We continue to invest in our hydro assets at the [ Wyndham ]. We installed that first runner at Roxburgh, completed the second earlier this month with the third now underway with full completion expected in July next year. And this will add around 45 gigawatt hours per year in the mean year. At Clyde, 3 of the transformers have now been installed with the final one scheduled for January 2026. On to the performance of our wholesale sales channels, contracted revenue increased due to higher prices and strategic shifts to longer-term channels to support those larger industrial users. Sales to the retail business declined primarily due to warmer weather with electricity transfer price higher, increasing wholesale business revenue by $39 million. Commercial and industrial channel volumes and pricing improvements were quite constrained as Contact did not receive 36% of our contracted gas from OMV, which is needed to support long-term sales. A significant proportion of our C&I customer volumes are up for recontracting this year, which we will be expecting to contribute to growth through FY '27. Contract for different volumes fell as we shifted volume into longer-term sales channels, while CFD pricing rose to $205 a megawatt hour, which reflects the tight market conditions and those contracted sales to Meridian and Mercury. You see the strategic shift in the sales that we're making within our portfolio, and we increased long-term sales volumes by 42% in the year to support PPAs to NZAS, Genesis, [ Oji Fibre and Pan Pac. Pricing in the long-term channel was up by $30 a megawatt hour, predominantly reflecting the full year impact of the new NZAS agreement. And as you would have seen with our enhanced New Zealand Steel partnership announced, Contact continues to support major energy users, who are looking for long-term electricity contracts. These are all on terms that reflect long-term investment economics. Our trading strategy is unchanged over the year with electricity sales marginally above purchase positions contributing around $20 million to EBITDAF. The prices that we achieved for the year were aligned with our contracted CFD rates. In our retail business, the EBITDAF loss of $49 million reflects adjustments to tariff, which did not keep pace with the rising costs. Network charges comprise around 35% to 45% of our customers' bill. They increased by 18% from the 1st of April 2025. So that just means a 7% tariff adjustment is required to keep pace with these pass-through costs. Gas gross margins improved by $1 million in the year with the effective price received from retail customers for this gas of $20 a gigajoule. However, new long-term contracts are well above what the retail business paid in FY '25, and so that will pressure future retail margins without further tariff increases. Pleasingly, our telco business continues to grow strongly with connections up 14% and gross margins rising by $3 million to $13 million. Cost to serve is also a great news story with cost per connection down by $7 and operating costs flat nominal year-on-year. That shows the productivity gains within the business have offset not only inflation, but also the variable costs associated with the customer growth. On to operating costs. If you exclude the impacts of Manawa on both years, they increased by $23 million or 11% due to growth-related costs and continued inflation, which continues to remain above CPI in several areas. Performance incentives rose by $2 million, reflecting the strong FY '25 outcome. Inflation contributed $13 million to other operating costs with notable above CPI increases in underlying insurance, salaries, employee benefits and regional council rates, which for Contact are up 40%. Insurance savings of $3 million were achieved through program restructuring, offsetting the underlying inflation program costs. New geothermal power stations and spend on feasibility for new generation plants added about $9 million of that $23 million. You would have seen that we've intentionally grown our cost base over the last 4 years as we rightsize the business with Contact26 strategy. But going forward, cost changes will be driven by those delivery of those strategic investments and general inflation with productivity programs becoming more important going forward when you consider the size of Contact's operating cost base to where it was previously. Operating free cash flow, a key metric for Contact as it underpins the dividend was $434 million, up $10 million from the prior period as the higher EBITDAF was offset by negative working capital changes and higher interest costs. The $66 million working capital impact included $54 million from increased inventory costs of gas. The weighted average cost of our full 7.6 PJs of gas, so that includes the long-term gas and the gas that we can store increased by $5 a gigajoule, and we have 1.7 PJs more stored gas. And the interest paid was higher, reflecting the end of the capitalized interest. The $110 million stay-in-business CapEx includes some of the projects that were signaled in our enhanced program, and that is $12 million for the Te Mihi spare rotor, $9 million for the Peak engine and $7 million each for the Roxburgh and Clyde transformer projects. $18 million represents spend on the outages at Te Mihi and Ohaaki during the year. Our EBITDAF to operating free cash flow conversion was 55%, which is slightly lower than history due to the onetime impact of that noncurrent gas increasing. Importantly, we invested around $406 million in renewable growth projects and our joint ventures, which represents 94% of FY '25 operating free cash flow, further demonstrating our commitment to growth. Turning on to the makeup of our growth capital projects. There are no changes to approved project costs in the period and activity is progressing well across the portfolio. On our balance sheet, we've seen net debt increase in line with the progress of investment with our renewable assets. In the period, we issued a $250 million green capital bond, which access efficient funding and supports our BBB credit rating. And we also issued a $400 million AMTN note to support our investment program throughout the year. Net debt to EBITDAF on a point basis is now at 2.3x, reflecting the 50% equity credit for that capital bond. These results cover the period to the 30th of June, and we have added around $900 million to support the acquisition of Manawa. The balance sheet continues to remain supportive to develop and deliver on the $1.1 billion of growth projects we've committed to. On to dividends, the full year dividend declared was $0.39 per share, which meets the target and results in a final dividend of $0.23 per share. The payout sits at the upper end of our rolling historic operating free cash flow basis, and that reflects the higher share capital on issue following the issue of scrip to support the Manawa acquisition. Our 2% dividend reinvestment plan discount continues. And over the past 2 dividends, we have been able to retain around 36% or $111 million in equity as investors continue to put their capital into Contact to deliver the growth projects. In FY '26, our target full year declared dividend is $0.40 per share, a 3% increase and in line with expectations. On to our guidance. Looking ahead, normalized and expected EBITDAF is targeted at $980 million, which excludes the Manawa transaction integration costs. This simply consists of $810 million from Contact stand-alone, as we outlined in February, around $150 million from Manawa and $20 million in delivered in-year benefits with transaction integration costs estimated at around $35 million at the midpoint. For FY '26, other operating costs are expected to be $400 million to $410 million, and that reflects inflation-only increases from Contact underlying OpEx of [ $272 ] million with productivity gains offsetting those new plant additions. We've also added Manawa's costs and expect between $10 million and $20 million of in-year benefits delivered. SIB CapEx is guided at $175 million to $190 million, which is higher than you'd normally expect covering the regular SIB BAU, the last of Contact's accelerated SIB CapEx program in FY '26, the costs associated with the WairÄkei extension, which show up at stay business CapEx and geothermal well drilling. We anticipate that our EBITDAF to operating free cash flow conversion rate will be around 50% for FY '26. And this projection considers the increased debt levels that we will have and the suppressed contribution from Manawa in FY '26, which is expected to improve once the Mercury contract is adjusted to market rates and the enhancement program, SIB CapEx spend ends.

Right. Just -- thanks, Matt. Just turning to Manawa and strategic delivery and where we're at as we stand today. So just recapping the reasons for acquiring Manawa. One is the incredible diversification both geographically but also seasonally that we get from the acquisition and everything we've seen to date in the first 30 days or so since it has confirmed that those benefits will certainly accrue to us. The hydro flexibility is also expected to provide firming to further support intermittent renewable development, both the solar and wind that we've talked about extensively. The combined portfolio sees us get to around 98% renewable with more than 11 terawatt hours of renewable output in a mean year, which accelerates our rapid progress towards decarbonizing the portfolio. And what has been really nice about the Manawa acquisition is the combined development portfolio introduced on a very diversified portfolio, but one in which we will have active competition for capital to ensure that the best projects move forward. And you can see just a reminder both the seasonal shape, but also how Contact and Manawa have that countercyclical reinforcement of each other's portfolio. In terms of what we promised for the acquisition, so the generation normalization, that is absolutely on track. Obviously, the Mercury PPA and the CL&I (sic) [ C&I ] contract rollovers, those are absolutely on track. The cost synergies 30 days in, those are on track, and we expect to deliver the $23 million to $28 million. We can -- that will turn up primarily as OpEx savings, and we expect that the 100% exit run rate will be achieved in 12 months to 18 months. The portfolio benefits, we actually do believe that those will continue and they are on track, and we can see that value shift in the additional flexibility that we have in the portfolio coming through already. We do expect that we will -- overall, the transaction is best described as being very much on track, aided by the market tailwinds and the better and expected or the proven integration approach that we've had. Everything has been planned down to the last detail in terms of the integration. Look, in terms of the program that was underway in Manawa in terms of the asset upgrades, they continue to progress well. A large portion of them are completed. Highbank and Coleridge are on track, and that generation uplift is continues to build. We continue to have confidence in that program being delivered and completed on time. And you can see the additional -- the increase in the electricity futures prices as those come through, those further improve the benefits that we expect to come through as that Mercury volume in the bottom right-hand corner there comes off. So overall, we are very confident going forward. Matt, I'm just going to hand the next one back to you on the cost synergies.

Sure. Well, I'll just reiterate that we have committed to make OpEx reduction of around $23 million to $28 million. The integration efforts that Mike has referred to do give us confidence that we will achieve these cost reductions. And we have updated our view to anticipate that we will deliver in the top half of the guided range. On the portfolio benefits, clearly, combining the 2 businesses has significant portfolio benefits. And in the first month since we've completed the transaction, we've been able to confirm that the risks within the combined portfolio are lower than the sum of the combination of each of the companies on their own, which is fantastic and clearly reinforces the business case for the transaction. What we're going to be doing over the next 6 months is co-optimizing those assets to understand how we can run them in a way that can deliver more output for industrial consumers to purchase and help facilitate the build of more intermittent renewable generation, and we're very excited to run through that process. It's an incredible set of assets and an incredible team. When the Contact strategy was launched in FY 2021, Contact was 81% renewable. The strategy was all about how do we transition towards a highly renewable asset portfolio. And I remember many conversations I had with shareholders around how Contact could become a highly renewable company. So it's a pretty exciting opportunity to now talk about the fact that we anticipate to be around 98% renewable in FY '26. It has taken about $4.5 billion worth of investment to get there, but I think it's really pleasing to show the progress that we've made. Ongoing thermal support will be required to maximize the value from our hydro assets, and that includes the Manawa assets that we've just acquired. And we're fortunate to have been able to purchase the gas from Greymouth to support the ongoing running of our peakers, which over time, will allow us to continue to build more renewables, and that gives us a really strategic low-cost base and long life with long-life assets. Our capital allocation framework continues to serve us really well. Basically, it's anchored in strong disciplined investment. We're always focused on delivering that operating free cash flow, and we've got a commitment to reliable dividends that reflect the cash flow of the investments that we've made. Since FY '23, we've increased dividends by 14%. The significant growth investments are delivering above WACC returns. and we've opened up off-balance sheet funding options to expand our balance sheet. We also remain very focused on restoring stay-in business CapEx to normalized levels and making sure that the balance sheet going forward prioritizes the highest value projects for Contact. Mike has been a big supporter of making sure we've got a portfolio of investments that do compete for capital, and that's a great place to be than we were just a few years ago. Investment-grade credit rating is incredibly important. So we will continue to make sure the performance holds up as expected to be able to support our renewable development growth. Over to you, Mike.

Okay. So look, in terms of the development pipeline going forward, there remains significant or there are significant solar and wind options going forward. I'm not going to go into these in detail. But fair to say the portfolio is significant now. There is obviously the top 3 at the bottom, which are in execution, which we're incredibly focused on ensuring that we deliver. And beyond that, there is competition for capital and diversification across the full length of the motto. And those are the key takeaways there. Obviously, consenting remains a continued focus area, and we continue to support the government's efforts in the fast track consenting process. But the focus for the next 6 to 12 months is delivery, delivery, delivery. We will give you an update on the refreshed strategy in the November Capital Markets Day. We'll give you a view in the medium to longer term. But in terms of the next 12 months, growing demand, we've got New Zealand Steel deal to land and achieving FID. The renewable development, we've got Glenbrook, we've got KÅwhai Park, we've got Te Mihi 2A, and we will continue to focus on delivering those and getting Glorit and Argyle Solar farms potentially underway as well as additional battery storage at Glenbrook. TCC will close at the end of this calendar year. We are very grateful to for what has achieved in the New Zealand market these last 25 years, but we are confident in winter next year that we will continue to create or support security of supply. We are targeting additional multiproduct customers in our mass market retail base that they do provide a stickier customer, and we're able to deliver better outcomes for the customer in that space. And obviously, we continue to focus on the Manawa integration, creating one truly great company for the go forward. We expect to deliver on those OpEx savings, and we expect to absolutely deliver on those portfolio benefits. So that gives you a view of the next 12 months. We look forward to updating you and welcoming you later in the year with the updated Contact31+ strategy. And with that, I will close. Thank you, Matt, and we'll move to questions.

Thank you, Mike and Matt. We're going to move to questions now, starting with questions from the room. Over to Andrew Harvey-Green from Forsyth Barr.

A couple of questions for me. Just first of all, just looking at the CapEx development pipeline. So it looks to me at this stage, you're still in the process, I guess, of you assessing the Contact and Manawa portfolios and working out which ways -- which projects will sort of go first. A couple of things did stand out, though. First of all, on the Glenbrook battery, that's 200 megawatts. That's probably a bit bigger than what we've sort of seen in the past. Can you sort of talk to that? And is there sort of any transmission capacity increases required at Glenbrook to deliver that?

No, I think there's a couple of things. One is the connection at Glenbrook is outstanding. It has on [indiscernible] basis, I might have this wrong, 650 megawatts of capacity. And so the batteries play well into that. They actually strengthen the transmission connection because they provide backup for periods of outage and they actually allow a much more resilient grid in that particular part of the network. So no, no stress on the transmission whatsoever there.

Okay. And secondly, Tauhara Stage 2, it looks like all of the Te Mihi, Tauhara is post FY '28 from that FID perspective, which suggests it will be coming on FY '30 or later earlier. So I mean, is it still a possibility that falls between the 2 Te Mihi projects? Or are we looking more likely that it's going to be having to go sort of after the last of the Te Mihi projects?

It's still very early days. So we're assessing the reservoir impact. So far, as you can see in the production figures, everything is looking favorable. But there are a number of options around the further development of Tauhara because the next developments at Tauhara will be the last developments on Tauhara. So it's really important we get them right. Te Mihi, we are focusing on getting 2A and then indeed, we have to have Te Mihi 2B online sort of 2030, 2031. So there is -- the real question mark is that reservoir response at Tauhara. And once we've got a good handle on that, we will have an appropriate response to that in terms of development going forward.

Okay. And last question, I guess, around the CapEx side of things. Are you thinking about, I guess, increasing the pace at which you develop now that you've got the Manawa projects as well? And secondly, how you, I guess, intend to fund that if that's the risk to go down?

So -- we're looking, obviously, we've got the solar portfolio. So Argyle is consented. So we'll bring that into the solar portfolio and look to potentially maybe execute that in conjunction with one of the other projects. Wind, most likely the thinking is at the moment is we will probably need partners off-balance sheet type structure, similar to solar. There are a number of options around wind that we're looking at in terms of which turbine manufacturers we partner with the contracting strategy. There's a whole range of questions, which we have to answer. But at this stage, we haven't been disappointed with the off-balance sheet structure that we've got in KÅwhai Park, and we'd look to continue certainly for solar and probably most likely for wind as well.

Yes. The balance sheet is relatively strong. So while there's a pinch point in FY '26 because of the debt that we've taken on as part of Manawa, that reduces quite quickly. S&P, they don't actually look at the 1-year net debt-to-EBITDA ratio, they have a forward view around the trajectory. And because of those repricing features of the Mercury contract, EBITDAF will be supportive. The projects that we've got within the combined portfolio with the possible exception of Glorit, if we get some good news around the consent later in this month, they're all pre-consent. So on that basis, time is on our side as we deliver the benefits of the Manawa integration, as we develop -- as our new plants come online, it sort of opens up quite a lot of balance sheet capacity. But we do have a lot of options. The Manawa transaction provides us with further capacity for around $500 million of hybrids. And obviously, we've got this DRP, which is retaining around 36% of equity at the moment. So we feel like we have quite a few options for the stage projects that we have.

And just last quick question. Integration costs for Manawa. So I think you've called out FY '26 and FY '27 costs. I'm assuming it stops after that [indiscernible].

Thanks, Andrew. I've got some questions from Nevill Gluyas at Jarden.

Just 2 market sort of topics to explore with you guys. One is you pointed out sort of the declining risk for gas. I mean, do you see that as sort of material risk in the next 2 or 3 years that perhaps there won't be enough gas available for generation compared to what we've been able to secure in the last 2 years?

No, we're relatively confident with the gas contracts we've now got in place that we're in a good position to be able to support our peaking plant, and that gives us some confidence. I think there is potentially a little bit of turbulence if gas supplies continue to decline with major gas users. But for peaking, which is where we want the gas to play in our portfolio, we're very confident.

Do you think there's some chance of gas reservation for industrial customers at the expense of generation?

We obviously -- look, we're out of baseload gas for generation. So we only require it for peaking. There may be some symbolic move. The most important thing is we keep building renewables to push gas out of that baseload. The Greymouth contract that we purchased, I think we've signaled we need around 300 or 3 PJs of gas for generation. We bought 7. We've got obviously a retail customer base. So there is gas available within our portfolio that we've purchased. So if there are any customers that are looking for gas, it's cool.

Excellent. Great. And the second topic was just around the Frontier review. Have you had conversations with officials, [ most have ] they approached you -- what are you hearing from them? And what are you telling them?

So we were engaged in the Frontier process. We were interviewed extensively for 2 hours. And that has been the extent of our contribution to that. We have heard nothing about what's in the review. It has been remarkably tight. And so, we can only do what others do and wait and see what the outcome is.

Thanks, Nevill. We'll move now to questions online. [Operator Instructions] So the first hand is from Grant Swanepoel from Jarden.

Can you all hear me?

Yes, we can.

Loud and clear.

Just first of all, on the geothermal [ 4950 ] for FY '26, is that only including a single shutdown for Tauhara 2? And how many days is that going to be?

Yes, the shutdown -- 1-year shutdown for Tauhara is included, and it's 30 days.

Yes. That's right. Grant, we've -- in the appendix, we've highlighted the sort of 2 key outages. I think there's one at Tauhara and there's one at Te Huka 3.

Te Huka 3 end of period for next year.

Now Mercury having identified 5 terawatt hours of potential opportunities in geothermal. Is there anything in change technology or where you just haven't looked at your own resources that can give Contact an opportunity to come up with a new number?

We're always looking. Look, obviously, we have a decade of work in front of us in terms of the Tauhara and the WairÄkei fields. I think the world is getting excited about geothermal. And so there are 2 ends of the spectrum. There is a super critical geothermal, which is a super hot deep stuff. most of the earth crust, which the government obviously expressed an interest in. And there is what we call cool geothermal, which is sub -200-degree geothermal, which requires more intense drilling. It's probably more akin to coalbed methane or shale gas in the oil and gas sector, where your ability to get low-cost repeatable drilling and pumping technology down in the hole to get the enthalpy lifted to the surface and into some form of plant. The like coalbed methane and shale gas, it will be more expensive. And like deepwater oil and gas, super critical will be more expensive. So it's important that we explore those fringes, but remain very focused on what we have in front of us.

Okay. And then my final question is back to the Frontier report. I think there's some talk around maybe even reigniting the thermal coal type opportunity. Now that Genesis and the rest of the industry has signed 150 megawatts on these firming options, do you think that that's still a possibility? And is there anything that the government -- because they seem to be getting excited about the opportunity to bring down wholesale prices or retail prices. Is there anything that they could come up that can cause you guys an issue in your outlook?

There's all sorts of things politicians could do to add an issue. Look, thermal coal, you're right, is that the Huntly firming option effectively delivers a substantive part of thermal coal. You've effectively kept thermal capacity in market with a strategic coal reserve, which was very much the thinking around thermal coal. And the fact that we're keeping our peakers, [ Todd ] have their peakers, AGS is secure and as evidenced by the write-back indicates that the elements of thermal coal are there, and I think will lead to a far more stable. What will soften prices over the medium to long term and even the short term is building more renewable energy, in particular, baseload geothermal. And that will mitigate the volatility that we've seen over the last few years. Now of course, there will be a whole range of people queuing up to claim the credit for that, and we shouldn't deprive them of their moment in the sun. But that ultimately is what is going to soften prices.

Thank you, Grant. We'll move to Vignesh Nair from UBS.

Can you hear me?

Yes, we can.

Awesome. Lots of detail on the slide pack. A few questions. I just want to start with New Zealand Steel. Obviously, 50 megawatts added to the existing 30 megawatts starting next year. I think on the slide pack, you pointed to 0.2 terawatt hours from the deal or rather from metals conversion in terms of overall demand. I just wanted to know some more color on the deal and perhaps some commentary on price. Also curious to know how competitive of a process it was to win.

Look, a couple of things. So the deal is based on our long-term view of firmed electricity price corrected for location and the credit rating of the counterparty, and we're very clear that, that is the basis of which long-term deals with the likes of Fonterra and New Zealand Steel are always price accounting for location and the like. In terms of competitiveness of the process, that's for New Zealand Steel to comment on, but we have been absolutely delighted with the collaborative nature of the process, which has allowed things like the demand flex in there, which again has softened the impact for New Zealand Steel and creates a real win-win. And so, it's not so much the competitiveness of the process as the high degree of collaboration, creativity and thoughtfulness that has gone into that deal, which are the important features for me. Yes, longer term, it will be full-scale '27, '28.

Yes.

And so post completion, there's 2 coal-fired furnaces left, if I'm not wrong. Is there any early discussions to replace those with an EAF as well?

I couldn't comment on that at the moment at this stage, the focus is on getting the EAF up and running.

And so also earlier, you mentioned there's a lot of C&I contracts up for recontracting this year. Can we expect longer-term dated sort of structures like you've done this time around with this 11-year deal with those as well?

Yes. I mean you would have seen, as I mentioned, I think in FY '25, we're up 40% of those long-term arrangements. For next year, we're up to 2.5 terawatt hours of strategic long-term sales. And the announcement today adds the 50 megawatts to the already existing 30 megawatts. We've got 500 gigawatt hours to Fonterra. We're absolutely extending the term of our book. We're connecting ourselves to customers, who are looking to decarbonize, who are looking to get off gas and are looking to play a strong role in improving the economic situation in New Zealand. So we're very proud to go longer term.

Okay. Very clear. And finally, just on the excess gas that you have from before, will you be still exploring to use Unit 5 as a tolling plant to run that gas through? Or is the bulk of the excess either being sold to counterparties or being added to [indiscernible]?

The bulk of the counterparties is direct users, whether it's mass market, our retail arm, whether it's under C&I users, small amount for peak. If there's something left, then we're always looking at potential tolling arrangements, but that's not the focus. The focus was to secure the direct supply customers that we have.

The value of the gas beyond risk management is not there. You'd rather build more renewables because it's a lower cost than running gas at current market prices through any type of gas-fired power station.

Thanks. We'll move to Joshua Dale at Craigs Investment Partners.

Guys, can you hear me okay?

Yes.

Brilliant. Just coming back to the balance sheet question earlier. In terms of time frame, what's the leeway you get around exceeding 3x net debt to EBITDAF before your credit rating comes under pressure?

Yes. So you can look at the exact words in the S&P updates that they provide. But basically, what they say is, first of all, they use a 3-year averaging period. So current year, next year and the year after, and there's a weighting between each of those periods. They say that you need to be significantly higher than 3x net debt to EBITDA (sic) [ EBITDAF ]. So read into that what you will, without any pathway to getting below 3x. So that's the sort of the functional area that you are sort of located within. So they understand that we're building lots of renewable generation. They understand part of the generation that we're building has got to do with replacing our plants, and that's why we've moved from a 2-back current and 2 forward style arrangement to 3 forward. And it's really is about what is the pathway for you to return to 3x or below. I think in the last report, they saw us peaking in the FY '26 year around 3x to 3.1x. We're hoping to do a bit better than that.

Okay. And just switching to imputation, at FY '24, you expected future dividends to be imputed up to 65%. Now it's 80%. Is it solely Manawa that's dragged that upward? Or are there other drivers?

Yes. So clearly, this imputation on the final dividend for this year is impacted by the additional share capital that we've got through the scrip issue. So therefore, we haven't paid any more tax from a stand-alone basis to then. So we always try and match our paid tax in year to the imputation provided. There's also a benefit that we are receiving as a result of bringing the Te Huka 3 plant online after the government announced changes to the investment tax boost, which means we have to pay less tax than we would otherwise have paid. Clearly, on average, over time, that increases back up to more sort of normalized levels. So the imputation credit attached to this final dividend is the odd one out.

Okay. And just a couple on batteries and peakers. If you do end up committing to the batteries now in the pipeline, what are the implications for keeping your peakers and I guess, by extension, your gas storage?

We actually see batteries as a perfect partner for peakers because what they do is take the really high-stress operation, the stop start, running at incredibly low rates to provide reserves. They take that away from the peakers and allow the peakers to run more as shoulder support in those dry autumns and slightly dry springs. And so we see them as a perfect partner because that volatility, that stop start up, down, low flow running all that can be moved to the battery. We see them as a real partner.

Yes. So they sort of play 2 different roles. The peakers are there to support our hydro generation volatility. And so if you're running peakers, 2 peakers for 4 months, for instance, you'll get sort of a P 25-year hydro event, whereas the batteries are there for intraday shapes.

Okay. That's helpful. One last related question. Given you have the peakers and the fact you've signed 50 megawatts of long-term HFOs at Huntly, should we think about that 50 megawatts as being the limit of your interest in capacity contracts at Huntly? Or might you have appetite for more?

We're happy with what we've signed up to at this stage, and that ensures that the 3 rank can stay in the market. So it's fair to say we're happy with what we signed up to.

We'll move to Stephen Hudson from Macquarie.

Can you hear me okay?

Yes.

This is a bit of an old question, but can you just help us on the retail transfer price that you're using at the moment and how that sort of relates back to the $164 per megawatt hour that you've got in your $980 EBITDAF guidance?

Yes. It's a 3-year weighted average. Matt can give you the details, but it's a 3-year weighted average and it's done on the basis that that's what we'd credibly sell to a third-party retailer.

Yes. That's a very good summary. So basically, it takes the ASX price and gradually hedges up a baseload price based on the quarter that it's referencing adjusted for shape location.

And so if we were to sort of assume kind of like a 20% shape location factor on that $980 guidance, the sort of $30 on 4 terawatt hours. So you've got about maybe more like $120 million of [ EBITDA ] (sic) [ EBITDAF ] to catch up through your CPI adjustments. Would that be ballpark?

I think it's a bit -- I think the transfer price in this year was $165 a megawatt hour and our net price that we received it was about if you exclude OpEx around sort of about $160 million as well. So I think we're sort of broadly aligned with the net pricing impacts with the transfer price. But clearly, that's not paying for all the [ $75 million ] of operating costs, and we're $49 million down. So about $120 million sounds about right if you were going to get up there. Now clearly, with more generation being brought online, we expect prices to more towards long-term averages.

Yes. Excellent. And just on to Roaring 40s. Can you just remind us the exclusivity arrangement, how long that has to run and how that partnership is delivering for you at the moment?

It's delivered a wide range of sites. Obviously, Southland Wind was first amongst those, but also there are sites in the [indiscernible] and up north in [indiscernible]. So we're delighted with how the partnership has worked to date. I think it's got another 2 years to run on the existing deal. But no, we're delighted with what they've done so far.

Yes.

Yes. And you're likely to hang on to them beyond that 2 to 3 years, do you think? Sorry, you just cut out there, but interestingly you said yes.

Yes.

Yes. And just demand response and HFO premiums within the $980 million guidance, can you give us being a little bit lazy here, but exactly how much you built in for those looking at you now?

Yes. We have built the premiums within our acquired generation costs. And that's why on a dollar per megawatt basis, it looks a little bit higher than what we can get away from as a short-run cost of gas. The only thing I would say, obviously, the HFO starts on the 1st of January, so it's a part year for that one, but we won't be divulging what the associated with that.

No. And if I've done my little calculation correct, you seem to be picking about 150 megs per annum of new data center demand. Is that right? And where do you get that number from?

What we had in the presentation was what we have publicly -- what we've seen publicly announced committed data centers. We do see continuing interest in the New Zealand market, in particular, given its high penetration of renewables and additional data center growth. But what was presented in the pack was what we had gleaned to have actually committed.

Thank you. That's all the questions we have time for today, and we'll now close the call. Thank you all for joining.

Thank you.