[Foreign language] Welcome everyone to our Presentation of the FY 2025 Results. We're delighted to be here. You'll see on the front page we've got a photo of the battery project at Glenbrook. We're delighted about making excellent progress. Without further ado, let's get into it. On my left is Matt Forbes, our newly appointed Chief Financial Officer. Usual disclaimer just around information, just note it as we go into the presentation. 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. As usual, we have an abundance of supporting materials which allow further analysis. FY 2025 has been a good year.
The financial performance has been very strong with a lift in EBITDAF, underlying EBITDAF up to NZD 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 July 11th. 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 TWh . We continue to have NZD 1.1 billion of projects under construction with Kōwhai Park , Glenbrook Battery, and the Te Mihi stage 2 project all making excellent progress. On the demand side, we announced this morning the New Zealand Steel deal as well as the electrification of Fonterra at the Whareroa plant, as well as the Greymouth and OMV contracts.
More than that, over 140,000 households are choosing either discounted or free off-peak energy in our mass market. 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 recognition of this as well as our continued representation in the Dow Jones, and we are delivering for the market. We have worked hard in these last 12 months securing the best part of 6 PJ and Methanex flex to support the market in what were two 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 one but two 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 have to continue with strategic partnerships like Fonterra and 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 what 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. Kōwhai 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 multi-product customers have grown significantly 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 looked forward to its renewal and refreshment later this year as well as Manawa, which we'll come to later. We do have significant number of projects under construction to meet two 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. 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 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 Kōwhai 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. We're looking forward to that coming online in the middle of year. Delighted with the progress across all three 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 giving our views of what happened in the last 12 months. Demand actually declined last year.
A large part of that 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. There was a drop obviously with the closure of the Winstone Karioi pulp mill and the Tangiwai sawmill. There was a decline also in the South Canterbury irrigation. Balancing that is the Pan Pac 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 Tangiwai industries in particular, we can see the market increasing too.
We expect around 46 TW 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. We expect that growth will continue over the medium term in particular, and that outlook looks positive. As I mentioned, last year was characterized not by one but two historically significant dry periods. You can see winter 2024 and then summer 2025 were dry, and that led to hydro generation, not just for us but for others, being significantly lower than previous years. You can see there 2025 compared to 2023, down some 6 TWh to almost 6 TWh .
The market to a large degree did cope with that through the increased thermal that was deployed into market, but also the growth in geothermal compared to previous years and wind as well. You can see that renewable wind, that renewable build mitigating that drop off in hydro that we experienced. 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. Also, the Methanex flex that was deployed not once but twice was critical in making that thermal generation available to the market. Interestingly, what's been done here is showing the linkages. If you go back one slide, those periods of dry one and two coincide with those peaks. That is a market responding to dry periods.
The long-term price we expect to be roughly about that NZD 126. The market is volatile. What has caught everyone by surprise is a rapid decline in the upstream gas supply market. There is no hiding from that. I think the response of the market to that has been exemplary with over almost 7 TWh brought on in seven years. That's 1 TWh a year of renewable build every year, which is roughly 10 PJ a year equivalent in gas power 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. No one should hide away from that.
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. We absolutely fundamentally believe that the solution to this is build more renewable energy. That will bring those upward pressures caused by the collapse in the upstream gas market. They will mitigate and soften those over the medium to long term. There are challenges in energy. Energy is always a fundamental human need, and as a result there is a high degree of volatility.
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-being. 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. We provide free power and broadband to Women's Refuge. We're investing at pace; we could not go farther faster. As I said, almost 7 TWh in seven years. There is now 335 MW of grid-scale battery either under construction or in the market where two years ago there was nothing. We have brought on those baselines 225 MW of baseline renewables ourselves, Tauhara and Te Huka 3.
We've got the battery and 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 they'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 INSYS deal, but also the Huntley 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 necessarily 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 PJ a year in additional gas supply out to 2032. The renewable energy boom that it's 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 towns like Taupō and in the provinces. 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. That is something I think as a company we should be incredibly proud of. Now handing over to Matt.
Thanks Mike, and pleasure to present Contact's 2025 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 NZD 770 million and the updated NZD 790 million, which excludes Manawa transaction costs, which was 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 two geothermal power stations on the Tauhara field in the Taupō region, delivering around 5% of New Zealand's total annual energy demand and offering renewable baseload power, which is not dependent on weather. We have seen how important that is with the year that we've just had. They generated 1,255 GWh in the financial year at a capacity factor of 82%. Despite this lower generation as the plant ramped up, Tauhara on its own delivered NZD 226 million in EBITDAF, a 12% return on invested capital. This represents a strong first year on our major NZD 1.05 billion investment, which includes the capitalized interest on the project.
In addition, Te Huka 3 has generated at a capacity of 54 MW since it came online in mid-December, which is above the 51 MW 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 two 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 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 PJ of gas from Methanex.
As Mike mentioned, Methanex paused their methanol production during those two 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 were short of fuel. We put over NZD 100 million online to purchase this gas and recovered a significant proportion of this from those contracts and used around a third of the gas that we purchased from Methanex for these electricity sales. The balance was unsold, with a third 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 Aluminium Smelter, and that was a key feature of our results.
This contract not only delivers the term, which helps with build, but improves pricing and a demand response mechanism. In FY 2025, Contact 's 25% share of the demand response called was the equivalent of around 150 GWh of acquired generation. We paid around NZD 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 2025 EBITDAF reflects a NZD 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 PJ of gas in this facility. While this is a non-cash item, I'm calling it out because it increases our reported EBITDAF in FY 2025 but doesn't reflect the operational performance for the year. Turning to our financial performance, we've adjusted EBITDAF to exclude the fair value movement in the onerous contract provision in both periods to provide a clearer comparison in the underlying performance drivers. Underlying EBITDAF for FY 2025 was NZD 774 million, that is up NZD 111 million on FY 2024.
The volume impact of the new generation I mentioned at the outset was significant, with a net 0.8 TWh increase in renewable generation, which was driven by the 1.2 TWh of new plants coming online, offset by the lower hydro we received in the period. The combination of these two factors added NZD 133 million to EBITDAF. Pricing continued to support performance, with long-term channel pricing up by NZD 46 million through new INSYS pricing and a 7% uplift in the integrated retail contribution on FY 2024. The pricing of our market link channels was also up by NZD 36/MWh , contributing NZD 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 NZD 185 million.
Other income decreased by NZD 3 million, of which NZD 12 million relates to the loss on sale of 2.3 PJ of gas that we didn't need, that we'd purchased from Methanex, and fixed operating costs rose by NZD 31 million, which is led by operating cost increases. That includes NZD 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 NZD 31 million, or 13%, primarily driven by the NZD 111 million rise in EBITDAF. Depreciation increased by NZD 18 million on FY 2024, and there was a NZD 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 NZD 65 million, which is predominantly attributable to the cessation of capitalized interest. In the previous financial year, the Tauhara capitalized interest was around NZD 61 million.
Fair value movements in financial instruments was NZD 43 million down on FY 2024. Of that, NZD 10 million relates to the movement in realized market making losses, which total NZD 13 million in FY 2025. It must be noted how impressive the performance was from the team in the second half of the year to end up with a NZD 1 million gain in that second period. The remaining NZD 33 million of the unrealized losses in the fair value of financial instruments relates to our two new long-term contracts with INSYS and Kōwhai 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 2024. You'll recall that we had write-offs of around NZD 50 million due to the engine peaker damage as well as costs associated with repairing the steam hammer event.
This results in a NZD 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 NZD 8 million was included onto the high-level performance of our business segments. Performance highlights the strength of our wholesale business, with EBITDAF rising by NZD 149 million to NZD 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 NZD 49 million, which is down NZD 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 NZD 22 million to NZD 73 million, mainly reflecting those minor work, transaction, and integration costs. Those are time-bound investments that we expect to get lots of value from during the acquisition onto our wholesale business. Starting with the generation costs, you'll see that renewable generation increased to 88% total output while thermal generation reduced by about 0.5 TWh . It seems counterintuitive then to see generation cost rising by NZD 68 million. That relates to the costs of gas and acquired generation during the period, which nearly doubled from NZD 116/MWh to NZD 200/MWh . That reflects the new normal.
In addition to those new geothermal power stations online, we had major turnarounds at 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 expectations set for an improvement over the 70% availability recorded by these units over FY 2025. Hydro generation was down by 9% on FY 2024 and 15% below our long-term average expectations, marking the lowest output from hydro that we saw at Contact since FY 2012. 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 midlife. 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.
This will add around 45 GWh per year in the mean year at Clyde. Three of the transformers have now been installed, with the final one scheduled for January 2026. Onto 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 NZD 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 CNI customer volumes are up for recontracting this year, which we will be expecting to contribute to growth through FY 2027.
Contract for different volumes fell as we shifted volume into longer-term sales channels, while CFD pricing rose to NZD 205/MWh , which reflects the tight marhket 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 NZD 30/MWh , predominantly reflecting the full-year impact of the new INSYS 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 NZD 20 million to EBITDAF. The prices that we achieved for the year were aligned with our contracted CFD rate in our retail business. The EBITDAF loss of NZD 49 million reflects adjustments to tariff which did not keep pace with the rising costs. Network charges comprise around 35% - 45% of a customer's bill. They increased by 18% from 1st 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 NZD 1 million in the year with the effective price received from retail customers for this gas of NZD 20 /GJ . However, new long term contracts are well above what the retail business paid in FY 2025 and so that will pressure future retail margins without further tariff increases.
Pleasingly, our broadband business continues to grow strongly with connections up 14% and gross margins rising by NZD 3 million to NZD 13 million. Cost to serve is also a great news story with cost per connection down by NZD 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 onto operating costs. If you exclude the impacts of Manawa on both years they increased by NZD 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 NZD 2 million reflecting the strong FY 2025 outcome. Inflation contributed NZD 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 NZD 3 million were achieved through program restructuring offsetting that underlying inflation. Program costs, new geothermal power stations, and spend on feasibility for new generation plants added about NZD 9 million of that NZD 23 million. You would have seen that we've intentionally grown our cost base over the last four years as we right size the business with Contact26 strategy. 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 a dividend, was NZD 434 million, up NZD 10 million from the prior period as the higher EBITDAF was offset by negative working capital changes and higher interest costs.
The NZD 66 million working capital impact included NZD 54 million from increased inventory costs of gas. The weighted average cost of our full 7.6 PJ of gas, so that includes the long-term gas and the gas that we can store, increased by NZD 5 /GJ and we have 1.7 PJ more stored gas. The interest paid was higher, reflecting the end of the capitalized interest. The NZD 110 million stay-in-business CapEx includes some of the projects that were signaled in our enhanced program and that is NZD 12 million for the Te Mihi spare rotor, NZD 9 million for the Pica engine, and NZD 7 million each for the Roxburgh and Clyde transformer projects. NZD 18 million represents spend on the outages at Te Mihi and Ohaaki during the year. Our EBITDAF operating free cash flow conversion was 55%, which is slightly lower than history due to the one-time impact of that non-current gas increasing.
Importantly, we invested around NZD 406 million in renewable growth projects and our joint ventures, which represents 94% of FY 2025 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 NZD 250 million green capital bond, which accesses efficient funding and supports our BBB credit rating, and we also issued a NZD 400 million AMTN note to support our investment program throughout the year. Net debt to EBITDAF on a point basis is now at 2.3 x, reflecting the 50% equity credit for that capital bond.
These results cover the period to the 30th of June and we have added around NZD 900 million to support the acquisition of Manawa . The balance sheet continues to remain supportive to develop and deliver on the NZD 1.1 billion of growth projects we've committed to. Onto dividends, the full year dividend declared was NZD 0.39 per share, which meets the target and results in a final dividend of NZD 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 two dividends we have been able to retain around 36% or NZD 111 million in equity as investors continue to put their capital into Contact to deliver the growth projects in FY 2026.
Our target full year declared dividend is NZD 0.40 per share, a 3% increase and in line with expectations onto our guidance. Looking ahead, normalizing expected EBITDAF is targeted at NZD 980 million, which excludes the Manawa transaction integration costs. This simply consists of NZD 810 million from Contact standalone as we outlined in February, around NZD 150 million from Manawa, and NZD 20 million in delivered in-year benefits, with transaction integration costs estimated at around NZD 35 million at the midpoint for FY 2026. Other operating costs are expected to be NZD 400 million- NZD 410 million, and that reflects inflation-only increases from Contact underlying OpEx of NZD 272 million, with productivity gains offsetting those new plant additions. We've also added Manawa's costs and expect between NZD 10 million and NZD 20 million in new benefits delivered. SIB CapEx is guided at NZD 175 million- NZD 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 2026, the cost associated with the Wairākei extension, which sharpens site business CapEx and geothermal well drilling. We anticipate that our EBITDAF operating free cash flow conversion rate will be around 50% for FY 2026, and this projection considers the increased debt levels that we'll have and the suppressed contribution from Manawa in FY 2026, which is expected to improve once the Mercury contract is adjusted to market rates and the enhancement program SIBI CapEx spend ends.
Right, just thanks Matt. Just turning to Manawa and strategic delivery and where we're at as we stand today. 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 TWh of renewable output in a mean year, which accelerates our rapid progress towards decarbonizing the portfolio.
What has been really nice about the Manawa acquisition is the combined development portfolio introduced by a very diversified portfolio, but one in which we will have active competition for capital to ensure the best projects move forward. 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. The generation normalization is absolutely on track. Obviously, the Mercury PPA and the CLNI contract rollovers, those are absolutely on track. The cost synergies, 30 days in, those are on track and we expect to deliver the NZD 23 million- NZD 28 million that will turn up primarily as OpEx savings, and we expect that the 100% exit run rate will be achieved in 12 - 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 had in the portfolio coming through already. We do expect that overall the transaction is best described as being very much on track, aided by the market tailwinds and the better than expected or the proven integration approach that we've had. Everything has been planned down to the last detail in terms of the integration. In terms of the program that was underway in Manawa, in terms of the asset upgrades, they continue to progress. A large portion of them are completed. Highbank and Coleridge are on track and that generation uplift continues to build. We continue to have confidence in that program being delivered and completed on time.
You can see 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. Overall, we're very confident going forward. Matt, I'm just going to hand the next one back to you on the cost synergies.
Sure. I'll just reiterate that we have committed to make OpEx reduction of around NZD 23 million- NZD 28 million. The integration efforts that Mike has referred to do give us confidence that we will achieve these cost reductions. 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 two businesses has significant portfolio benefits. 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 six 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 and renewable generation. 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. I remember many conversations had with shareholders around how Contact could become a highly renewable company. It's a pretty exciting opportunity to now talk about the fact that we anticipate to be around 98% renewable in FY 2026. It has taken about NZD 4.5 billion worth of investment to get there.
I think it's really pleasing to show, you know, the progress that we've made. Ongoing thermal support will be required to maximize the value from our hydro assets. That includes the Manawa assets that we've just acquired and we're fortunate to have been able to purchase the gas from Greymouth t o support the ongoing running of our peakers, which over time will allow us to continue to build more renewables. That gives us a really strategic low-cost base and 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 I've made. Since FY 2023 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 stand 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. Over to you, Mike.
Okay, so look, in terms of the development pipeline going forward, 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 three 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 their fast-track consenting process. The focus for the next 6-12 months is delivery, delivery, delivery. We will give you an update on the refresh strategy in the November capital markets day. We'll get with you a view in the medium to longer term.
In terms of the next 12 months, growing demand, we've got New Zealand Steel deal to land, and we're achieving FID, the renewable development. We've got Glenbrook, we've got Kōwhai 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 for what it has achieved in the New Zealand market these last 25 years. We are confident in winter next year that we will continue to create or support security of supply. We're targeting additional multi-product customers in our mass market retail base; they do provide a stickier customer, and we're able to deliver better outcomes for the customer in that space.
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 almost portfolio benefits. 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. 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 .
Thanks Kelly. Morning Mike and Matt. A couple of questions for me. First of all, just looking at the CapEx development pipeline, it looks to me at this stage you're still in the process of assessing the Contact and Manawa options and working out which projects will go first. A couple of things did stand out though. First of all, on the Glenbrook Battery, that's 200 MW. That's probably a bit bigger than what we've sort of seen in the past.
Can you sort of talk to that?
Is there sort of any transmission capacity increase 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 been on an N - 1 basis. I might have this wrong, 650 MW of capacity, and the batteries play well onto 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. No stress on the transmission whatsoever there.
Okay.
Secondly, Tauhara stage 2. It looks like all of the Te Mihi, Tauhara is post FY 2028 from an FID perspective, which suggests it'll be coming on FY 2030 or later in the year. Is this still a possibility that falls between the two Te Mihi projects, or are we looking more likely that it's going to be having to go 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. There are a number of options around the further development of Tauhara because the next developments of Tauhara will be the last developments on Tauhara. 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 around 2030, 2031. The real question mark is that reservoir response at Tauhara. Once we've got a good handle on that, we will have an appropriate response to that in terms of development going forward.
Okay, our last question, I guess around the 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 route that you go down?
We're looking, obviously we've got the solar portfolio, so Argyle's consented. 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 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. At this stage we haven't been disappointed with the off balance sheet structure that we've got in Kōwhai Park, and we'd look to continue it certainly for solar and probably most likely for wind as well.
Yeah, the balance sheet is relatively strong. While there's a pinch point in FY 2026 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, you know, one year net debt/EBITDA ratio. They have a forward view around the trajectory, and because of those repricing features of the Mercury contract, you know, 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 this month, they're all pre-consent. On that basis, time is on our side as we deliver the benefits of the Manawa integration. As our new plants come online, it sort of opens up a lot of balance sheet capacity. We do have a lot of options.
The Manawa transaction provides us with further capacity for around NZD 500 million of hybrids. Obviously, we've got this DRP, which is retaining around 36% of equity at the moment. We feel like we have quite a few options for the stage of projects that we have.
Just last quick question. Integration costs for Manawa. I think you've about FY 2026 and FY 2027 costs. I'm assuming it stops after that currently?
That's correct, yeah.
Thanks, Andrew. I've got some questions from Nevill Gluyas at Jarden.
Just two market topics to explore with you guys. One is you pointed out sort of the declining risk for gas. Do you see that as sort of material risk in the next two or three years that perhaps there won't be enough gas available for generation compared to what we've been able to secure in the last two 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. 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. 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 g as 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've purchased, I think we've signaled we need around 300 GWh or 3 PJs of gas per generation. We've bought 7 PJ. We've got obviously retail customer base, so there is gas available within our portfolio that we've purchased. If there are any customers that are looking for gas, give us a call.
Excellent.
Great.
The second topic was just around the Frontier review. Have you had conversations with officials or ministers? Have they approached you? What are you hearing from them and what are you telling them?
We were engaged in the Frontier process. We were interviewed extensively for two 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. We can only do what others do and wait and see what the outcome is.
Thank you.
Thanks, Nevill. We'll move now to questions online. If attendees wish to ask a question, please raise your hand. We will then call you individually and invite you to unmute yourself at that time. The first hand is from Grant Swanepoel from Jarden. Grant, please remove your seat. You can go ahead.
Good morning, can you all hear me?
Yes, we can.
Loud and clear.
Just first of all on the geothermal. NZD 4,950 million for FY 2026. Is that only including a single shutdown for Tauhara 2? How many days is that going to be?
Yeah, the one-year shutdown for Tauhara is included, and it's 30 days.
Yeah, that's right, Grant. In the appendix we've highlighted the sort of two key outages. I think there's one at Tauhara and there's one at Te Huka 3 in the period next year.
Yeah, thanks. Now, Mercury having identified 5 TWh of potential opportunities in geothermal, is there anything in change technology or where you just haven't looked in your own resources that can give Contact an opportunity to come up with a new number?
We're always looking. Obviously, we have a decade of work in front of us in terms of the Tauhara and the Wairākei fields. I think the world is getting excited about geothermal. There are two ends of the spectrum. There is a supercritical geothermal, which is a super hot deep stuff, most of the Earth's crust, which the government obviously expressed an interest in. There is what we call cold geothermal, which is sub 200 degree geothermal, which requires more intense drilling, is probably more akin to coal bed 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 barn like coal bed methane and shale gas, it will be more expensive.
Like deep water oil and gas, supercritical will be more expensive. It's important that we explore those fringes but remain very focused on what we have in front of us.
Okay, thanks. My final question is back to the Frontier report. I think there's some talk around maybe even reigniting the thermal code type opportunity now that Genesis and the rest of the industry has signed 150 MW on these firming options. Do you think that that's still a, and is there anything that the government, 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 create an issue. Look, ThermalCo, you're right, is that the Huntley firming option effectively delivers a substantial part of ThermalCo. You've effectively kept thermal capacity in market with a strategic coal reserve, which was very much the thinking around thermal coal. 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 market. 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'll 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.
Thanks Mike.
Great. Thank you, Grant. We'll move to Vignesh Nair from UBS.
Vignesh?
Morning.
Morning Mike, can you hear me?
Yep, we can. Yep.
Awesome. Thanks for the presentation. Lots of detail on the slide pack, few questions. I just wanted to start with New Zealand Steel, obviously 50 MW added to the existing 30 MW starting next year. I think on the slide pack you pointed to 0.2 TWh 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, couple of things. The deal is based on our long-term view of firmed electricity price, corrected for location and the credit rating of the counterparty. We're very clear that that is the basis on which long-term deals with the likes of Fonterra and New Zealand Steel are always priced, accounting for location and the like in terms of competitiveness of the process. That's for New Zealand Steel to comment on. 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. 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. Yeah, longer term it will be full scale. 2027, 2028. Yeah.
Post completion, it's two qualified 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, their focus is on getting the EAF up and running.
Earlier you mentioned there's a lot of CNI 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?
Yeah, I mean you would have seen as I mentioned, I think in FY 2025 we're up 40% of those long-term arrangements. For next year we're up to 2.5 TWh of strategic long-term sales. The announcement today adds the 50 MW to the already existing 30 MW. We've got 500 GWh 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. We're very proud to go longer term.
Very clear. 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 Tauhara?
The bulk of the counterparties is direct users, whether it's mass market, our retail arm, whether it's CNI users. Small amount for peakers. If there's something left, we're always looking at potential tolling arrangements. 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 by power station.
Okay, great. Thanks, guys.
Thanks, Vignesh. We'll move to Joshua Dale at Craigs. I'm guessing it's yourself, Josh. Go ahead.
Thanks, 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 3 x net debt to EBITDAF before your credit rating comes under pressure?
Yep. You can look at the exact words in the S&P updates that they provide. Basically, what they say is, first of all, they use a three-year averaging period: current year, next year, and the year after. There's a weighting between each of those periods. They say that you need to be significantly higher than 3x net debt to EBITDA. You know, read into that what you will without any pathway to getting below 3x . That's the sort of functional area that you are located within. 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. That's why we've moved from a two back current and two forward style arrangement to three forward. It 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 2026 year around 3x- 3.1x . We're hoping to do a bit better than that.
Okay, thank you. Just switching to imputation. At FY 2024, you expected future dividends to be imputed up to 65%. Now it's 80%. Is it solely Manawa that's dragged it upward, or are there other drivers?
Yes. 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. Therefore, we haven't paid any more tax from our standalone basis to the end. 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 normalized levels. The imputation credit attached to this final dividend is the odd one out.
Okay, thanks. 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, them running at incredibly low, 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. 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.
They sort of play two different roles. The peakers are there to support our hydro generation volatility. If you're running peakers, two peakers for four months, for instance, you'll get sort of a P25 year hydro event, whereas the batteries are there for intraday, intraday, intraday shapes.
Okay, that's helpful. One last related question. Given you have the peakers and the fact you've signed 50 MW of long-term HFOs at Huntley, should we think about that 50 MW as being the limit of your interest in capacity contracts at Huntley, 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 three rank can stay in the market. It's fair to say we're happy with what we signed up to.
Okay, thanks very much, guys.
Thanks, Josh. We'll move to Stephen Hudson from Macquarie.
Hi guys, can you hear me okay?
Yep.
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 NZD 164/ MWh that you've got in your NZD 980 million EBITDAF guidance?
Yeah, it's a three-year weighted average. Matt can give you the details, but it's a three-year weighted average, and it's done on the basis that that's what we'd credibly sell to a third-party retailer.
Yep, that's a very good summary. Basically, it takes the ASX price and gradually hedges up a base load price based on the quarter that it's referencing, adjusted for shape and location.
If we were to sort of assume kind of like a 20% shape location factor on that NZD 980 million guidance, there's sort of NZD 30 on 4 TWh . You've got about maybe more like NZD 100 million- NZD 120 million of EBITDA 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 NZD 165 /MWh . Our net price that we received was about, if you exclude OpEx, around sort of about NZD 160/MWh as well. I think you sort of broadly align with the net pricing impacts with the transfer price. Clearly that's not paying for all the NZD 74 million of operating costs and we're NZD 49 million down, so yeah, about NZD 120/MWh sounds about right if you were going to get up there now. Clearly with more generation being brought online, we expect prices to drive more towards long term averages.
Yeah, excellent.
Thank you. Just onto Roaring40s , can you remind us the exclusivity arrangement, how long that has to run, and how that partnership's 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 flood sites in the Mamakus, Kaimais, and up north in Pouto. We're delighted with how the partnership has worked to date. I think it's got another two years to run on the existing deal. We're delighted with what they've done so far.
Yes.
Yep.
You're likely to hang onto them beyond that two to three years, do you think?
Sorry, you just cut out there, but I'm assuming you said yes. Yeah. Just demand response and HFO premiums within the NZD 980 million guidance. Can you give us a, being a little bit lazy here, but exactly how much you've built in for.
Those looking at you?
Yeah, we have built the premiums within our acquired generation costs, and that's why on NZD 1 /MWh 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 1st of January , so it's a part year for that one. We won't be divulging what the [crosstalk].
No worries. If I've done my little calculation correct, you seem to be picking about 150 MW per annum of new data center demand, is that right? 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. What was presented in the pack was what we had gleaned actually committed.
Useful. Thanks, gents.
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.