Contact Energy Limited

Good morning everyone and welcome to the presentation of Contact's FY26 results. Delighted to have you all here. Put simply, FY26 was a year of delivery. We completed the acquisition of Manawa Energy and welcomed its people and the assets into Contact. We delivered renewable energy growth with renewable output up 37%. Contact was 98% renewable in this last year, up from 88% last year, and just 81% in FY21. We took strong and pragmatic steps to support security of supply and the resilience of the electricity sector. We contracted with others, the HF Island Huntley, to ensure a strategic coal reserve for dry years. We bought our first battery online at Glenbrook and confirmed our investment in the second 200 megawatts. And we secured gas to support essential community services through the all-in-government contract. Meanwhile, we continue to work closely to support our customers. This includes supplying discounted or off-heat free electricity to now around 165,000 households and supporting customers and communities most in need through the 5 million contact good initiative initiative. The FY26 results reflect this delivery across the board, with EBITDAF of $1 billion, up 31% last year, and a step up in our average return on investment capital of over 100 basis points. Given this, the board has declared a final dividend of $0.24 per share, taking the total final dividend for the year up to $0.40 per share, up 3% on last year, and delivering as promised to our shareholders. Go to the next slide. Market conditions in this last financial year 26 were a significant contrast to those in FY25. The market was 93% renewable, the highest rate achieved since the market was introduced in the 1990s. And yes, this reflected higher than average hydro inflows, 180% above mean this year, but it also reflected the investment the sector has been making in building new renewable generations. bringing around four terawatt hours online in the last five years alone and pushing out baseload thermal. Another three terawatt hours is committed and expected to come online by the end of 2027. This is a cheaper supply of electricity and it builds resilience and economic independence for the nation. This investment is now being reflected in longer-term ASX future prices, up nearly 30% since the start of the year. These have settled at the lower end of our long-term wholesale price expectations and reflect the market moving back into a supply and demand balance. Demand is tracking up, up about 1% when you normalise for the fact that NZIS demand response was deployed last year. The market will need to be disciplined in bringing forward new renewable electricity projects backed by new demand sources. and alongside that will have to show both capital and cost discipline. Only the best projects will get through. Pricing for winter 26 has also come down sharply since the start of the year, with market confidence backed by high energy storage across each of hydro, gas and coal. Recent market trends continue, like the ongoing decline in gas production, with 2p reserve forecasts now 24%. we continue to address this strong headline. However, what is clear is that the market has learnt from the challenge it faced in winter 2024 and has come through in a much stronger position to support Aotearoa's changing energy needs. The market has already adapted for the energy transition. Secular investment has continued at a pace and market settings have evolved at the same time. We have now a fast-track consenting regime in operation and further planning reforms expected to pass by the end of the year. Industry is delivering the highest rate of new renewable investment in the nation's history. We have moved as an industry to put in place dry-air support across a range of mechanisms, demand response of large industrials, the HFO with a strategic coal reserve, stored gas and AGS, and changes in the way we use hydro. And yes, there may still be a role to play for right-sized, a right-spec LNG facility to support those remaining gas customers who are finding it difficult to convert off-gas and to provide for the nation a diversity of energy supply. But we also expect extended HFOs and diesel storage to play part of this resilient story. Remember, it's always been a matter of all of the above, not just one magic bullet. And we have already moved the dial on this as a sector to mitigate dry year risk and deliver energy security for all. Market and regulatory settings have evolved in step and are now very clear with non-discrimination obligations now in place and the super peak product and the associated market making obligations both now implemented. We continue to innovate for our customers as they electrify their own energy use with tools like shaped electricity supply contracts and demand flex, making conversions to electricity all the more possible. And we remain focused on energy well-being for those most challenged by energy prices, consumer cares and reducing barriers to access. This year, the Contact Good initiative alone provided $5 million of customer and community support and we expect it to grow to $7.5 million in the coming year. And we're advocating for a market-wide obligation to connect, to lift energy well-being outcomes, no matter your circumstance. We continue to deliver on our very strong renewable investment program. We've had a continuous build program on the go since 2021 with Poha, to Hookah Free, and our first battery all now online, and Kofi Park Solar now in commissioning. This investment has directly contributed to the supply-demand balance that you can now see in the broader market. Coming back to the market, early works are now also underway on Solar, which together with Kofi Park will help support committed dairy electrification load, the conversion of dairy off gas and coal. Construction also got underway on our second battery at Glenbrook in March, which will ultimately take our battery capacity at that site to around 300 megawatts, helping us to free up natural gas use in peak periods and supply this to customers. And it's worth noting that the role that batteries have played in these last few weeks in keeping the country safe through those morning and evening demand spikes, which were at record levels with significant amount of conventional generation offline demand, And yet, as a nation, we got through that. Construction has well progressed on a Temiti Stage 2 geothermal project with a steam fuel separator, heat exchangers and turbines for the first unit already installed. Temiti 2 is scheduled to be online quarter three next year and will replace Wairakei to a degree, which has been running since the 1950s. We have an extremely experienced team there on the ground, continuing to demonstrate the project delivery and geothermal development expertise is so core to our value proposition as a company. With Manawa, it's been a transformational year for Contact, having completed the acquisition of Manawa on the 11th of July last year, welcoming Manawa's people and the 26th generation sites into the Contact fold. It has truly been a merger of two great companies. And we're delighted to have already delivered the benefits of the integration. One of the pleasant surprises has been the quality of the development options of Costa, including the Huriwaka and Kaihiku wind projects and Argyle Solar. These have been actively advanced in enhancing the optionality within Contact's already high-quality pipeline. Cost synergies have already been secured at 100% of the upper end of the range we signalled. That's $28 million on a runway basis, and together with the net repricing benefits that have already been confirmed going into FY27, we have secured an $84 million up for FY27, up 35% on the long-run benefit announced at the acquisition. And this is before the expected value from long-run generation normalisation, but the high-rank and college upgrades ongoing and expected to come online in the coming year in hydrology during year-on-year. The delivery of manna has just, however, been one part of the story this year. FY26 has seen an impressive delivery of our in-year strategic targets across the board. As we closed out the Contact 26 strategy, which was, remember, to lead New Zealand's decarbonisation, we did decommission our final baseload gas plant, TCC, after 30 years of service to the nation. And we met both our run rate and in-year scope one and two emission targets that we committed very publicly years ago. We beat our contract demand targets, and importantly, almost all new demand contracted in-year had a favourable shape, being some awaited. Our CO2 commercialisation project hasn't quite met the project timeframes we set, But we continue to see this as an important part of the future of our Haki geothermal field. The project remains under development with a pilot-scale test planned for Aholahaki later this year. I've covered our renewable investment activity in detail. Again, a very good result against the ambition set at the start of the year here, noting that Kaukai Park is now in commissioning with the energy to the grid later this month, in fact, in the coming weeks. In retail, we've over-delivered on our multi-product customer and net price targets, and we're broadly in line with our cost-to-serve targets. Finally, we've met all of the targets, as I outlined above, that we set ourselves for matter-of-delivery. On that note, I'll hand over to Matt now to take us through the financial results. Thank you very much, Mike, and kia ora, everyone.

I'm Matt Forbes, contact CFO. And before I talk about the numbers, it's just worth remembering they're a product of thousands of decisions made every day across contacts and we're enabled by the 1,400-plus people who operate our assets, serve our customers, and deliver change across the business. It's our job to turn those efforts into long-term strategic value for shareholders, and FY26 is the year the strategic choices made through Contract 26 and the model acquisition have clearly translated into strong financial performance. FY25 tested contracts' resilience through dry hydrology, fuel constraints, and high replacement energy costs, And FY26 shows what the expanded portfolio can deliver in a more balanced market. There are three key takeaways from the result. The business has performed through very different conditions. Manawa and recent investments are now delivering measurable financial benefits. And the resulting cash generation and balance sheet capacity support our forward investment program and give us confidence in further dividend growth. The headline for FY26 is that earnings growth came through more renewable generation and the additional sales it supported, not higher average electricity prices. EBITDAF was $1.011 billion, up 31% on underlying FY25, and operating free cash flow increased 49% to $648 million. FY26 return on invested capital reached 7.5%, lifting the four-year average from 4.9% to 5.9%, as returns from Manawa and recent renewable investments began to flow through. The bridge on the right nets to a $237 million increase in underlying EBITDA, with two interconnected movements explaining most of the change. Renewable generation added $225 million, reflecting Manawa's hydro, the first full year of Te Hookah 3, and improved inflows. That additional generation supported more contracted sales, while materially reducing our alliance on gas-fired generation. Pricing moved the other way, creating a $53 million headwind. The average price across contracted sales reduced from $157 to approximately $140 per megawatt hour, reflecting the move away from FY25 stress conditions and the greater proportion of generation sold through longer-dated contracts. This illustrates the two sides of hydrological volatility. Sector earnings have rebounded as conditions moved from very dry in FY25 to wet in FY26. The distinction for contact is our portfolio delivered through both. Lower gas, carbon and acquired generation prices added a further $40 million, reflecting the reduced costs of replacement energy in the year, while other income improved by $51 million, reflecting new income streams acquired with Manawa and the absence of losses incurred on excess gas from methanic sales in FY25. Fixed costs increased principally through the Manawa cost base and transaction integration expenditure, partly upset by the synergies and productivity benefits delivered during FY26. Turning to profit, underlying profit increased 62% from $261 million to $423 million. Importantly, it also increased on a per-share basis. Underlying profit per share rose 27%, from $0.327 per share to $0.415, after a line for the shares issued during the year. And that per-share outcome matters. The capital we raise must translate into stronger earnings and value for each share, and not simply to deliver a larger company. Below you with us, high depreciation and interest reflects a larger asset base and our approach to acquisition funding, while tax includes the benefits of the government's investment boost settings. One item worth explaining is the unrealised movement within the change in fair value of financial instruments. Around $39 million of the year-on-year improvement relates to commercial contracts that are not eligible for hedge accounting. They relate to future periods, are non-cash in the current period, and do not reflect current period operating performance. And that's why reported profits should be considered alongside EBITDAF and operating free cash flow per share, and most importantly, delivering improving return on invested capital. The segment view shows where the EBITDAF was generated, and I'll keep this brief and return to the details in the slides that follow. Wholesale EBITDAF increased by $250 million to $1.145 billion, reflecting the scale in renewable generation drivers already described. Retail EBITDA improved from a loss of $49 million to a loss of $41 million. That's despite a $130 million increase in electricity and network input costs. Corporate and unallocated costs increased from $73 million to $93 million, and that includes $24 million of minor transaction and integration costs compared with $18 million in the prior period. With the remaining increase reflecting the acquired minor cost base, inflation and investment supporting the development of our new Contact 31 Plus strategy. On to our wholesale business. FY26, the generation from renewable sources was 98%, up from 81% when Contact 26 began in FY21. That shift has changed not only our emissions profile, but also our cost base and the resilience and quality of our earnings. Manawa has added 2.4 terawatt hours of hydro generation and contracted renewable PPAs, and combined with geothermal storage, flexible thermal capacity and access to markets, that has created greater geographic and technology diversity and gives us materially more ways to manage volume and price risk. And the value lies in using all of those resources together. Let me bring that to life with a practical example from FY26. The year included planned outages at Tohada and Tehuka III, unplanned disruption and some assets taking longer to return than expected. We did not respond by replacing every one of those lost megawatt hours at any cost, and when Samedi and Puefi experienced an unplanned five-day outage and geothermal generation was approximately 20 gigawatt hours below our forecasts, increased hydro and thermal generation largely offset that shortfall. And that's exactly what resilience looks like in practice. It doesn't mean avoiding every disruption. It just means having those portfolio options to manage the financial and customer outcomes and consequences when that disruption invariably occurs. Thermal generation fell to 229 gigawatt hours, its lowest ever recorded level. High inflows contributed, but so did the expanded renewables portfolio. Thermal remains valuable in dry periods and during major outages, but is now just one option within a broader mix. The contract and Manawa assets are already being managed commercially as one portfolio, and the next source of value is integrating the support system's data and decision processes. On wholesale contract revenue, the larger renewable portfolio also allowed us to increase contracted revenue by $281 million to $1.666 billion. The largest movement was in strategic fixed price sales. where revenue increased from $146 million to $361 million, and volumes increased by 2.2 terawatt hours. That reflects the Mercury contract acquired with Manawa, a full year of Tohada-backed PTAs, higher ENZUS volumes, and the commencement of the New Zealand Steel Agreement. And this is our channel management flywheel in action. Durable customer demand supports renewable investment, and that generation and customer commitments are managed together through our trading team. Long-term contracts are important. They provide earning certainty and help underpin new generation. The trade-off is that they can underpin before merchant exposure in tight markets, but become particularly valuable when supply increases and near-term prices fall. The wholesale price conditions in FY26 demonstrated that value. And the allocation across each of these channels is deliberate. Each carries different price, shape, location, duration, and risk characteristics, and no channel is always superior. For example, in retail, that meant preserving the long-term value of a customer franchise rather than materially reducing volumes over the last six years when input costs were higher and it was tempting to do so. In wholesale, it meant retaining a balance between long-term contracts and shorter-dated market-linked channels like C&I and CFDs rather than concentrating the portfolio for one market outcome. So that balance preserves options as the conditions change to deliver that purposeful alignment between customer demand, renewable investment and the risks that contact chooses to retain. That contracted book provides the foundation of how we set up the business and our trading business manages the residual position as the conditions change from those starting assumptions. So, 2006 began with fuel scarcity, planned outages, and the risk of constrained gas delivery. And by the second half of the year, high hydro inflows and wind generation had driven those spot and short-term dated prices materially lower. So, in year, we continually re-optimized the portfolio rather than operating to a fixed annual plan. And the clearest example in FY26 was our move fuel strategy. Through autumn and early winter, the team increased market purchases when electricity was inexpensive and retained a valuable hydro storage for periods when winter prices are expected to be higher. In June alone, that meant buying an additional 22 gigawatt hours when spot prices at Otahoo averaged $41 per megawatt hour. Viewed asset by asset, buying electricity when water is available can appear counterintuitive. But when viewed across the portfolio, it can be economically the right decision when the expected future value of the water exceeds the current purchase price. And we had similar examples within our gas portfolio. Lower electricity prices and that limited thermal generation created a risk that Ahoroa gas storage could reach capacity. The team therefore sold the gas, including at a standalone loss for that gas, to preserve the flexibility across the wider portfolio rather than potentially face forced sales later. And again, those are the decisions that bring the mind of the thesis to life. We've got greater hydro and geographic diversity. That just doesn't reduce the risk, though. It gives us more ways to respond as conditions change. Now to the performance of our retail business. Retail price increases. They're never comfortable decisions. And average electricity tariffs increased by around 12% as we sought to recover the $130 million increase in electricity and network costs. while recognising the pressure on household affordability and the importance of protecting customer trust. Even after that significant increase, pricing did not fully recover the additional input costs and the electricity gross margin was approximately $5 million lower. In deciding how far and how quickly to move, we modelled and we debated the expected effects on customers' churn, call and acquisition. Customer response was more resilient than expected, supporting our judgment that we'd struck a reasonable balance between cost recovery and customer trust. Network and metering costs are third-party costs that must be recovered, and energy recovery requires more judgments because customer demand is weighted towards winter and peak periods, while retail prices adjust less frequently to our wholesale market channels. There will always be channels and choices about the pace, timing, and extent of price changes. The most significant progress in the business came through multi-product growth. Total connections increased by around 50,000 to 692,000, including 24,000 in telco and 26,000 across energy. Gas and telco margins increased by $15 million and $4 million respectively and were the main contributors to the improvement in retail EBITDAF. Retail operating expenses increased by only $4 million while OpEx for Connection remained broadly stable at $117. That demonstrates the value of a more diversified customer and margin base. Our next phase of retail growth is not simply adding more customers to our current operating model. It's simplifying the processes and products, modernizing our platform and converting the customer growth into stronger margins through improved operating leverage rather than price. Reported other operating costs increased from $295 million to $387 million, principally reflecting the acquired Manawa cost base and integration expenditure. Manawa added $93 million of operating costs. Inflation and other headwinds added $11 million, while a further $4 million was associated with growth, including the fully operating costs of Seahooker 3 and investment support in retail connection growth. Against those increases, we delivered $24 million of synergies and productivity benefits during FY26, $22 million from Manawa, and $2 million from continued improvements in retail cost to serve. As Mike mentioned, that full $28 million Manawa run rate synergy target is now being secured. Delivering the transaction synergies was important, but it didn't impact or determine the integration sequence. The integration was deliberately sequenced around operational continuity first and foremost, control and clear accountability. We transferred operating knowledge and established ownership before redesigning processes, all going on to those duplicated costs. And that allowed us to secure the full synergy targets while maintaining stable operation of the combined portfolio. A word on discipline. We only recognize the synergy once the action is complete. Finance has independently validated the value and the saving is embedded in the receiving business unit's budget. The $28 million is therefore a reduction in the future cost base, not simply a piece of information on the PowerPoint or an opportunity identified within the acquisition case. For FY27, we expect EAU OPEX of approximately $360 million, broadly flat on FY26, despite around $11 million of inflation and $4 million of growth. Those pressures are offset by a further $15, $16 million of synergies and productivity. Reported FY27 costs are expected to also include approximately $7 million of remaining integration expenditure and $12 million of time-bound SaaS implementation expenditure, principally related to the potential future retail platform, which remains subject to final investment approval. Accounting standards require those SaaS implementation costs to be expensed, with the equivalent investment removed from forward SIV capital guidance. Across FY26 delivery and the FY27 outlook, the cost bridge incorporates approximately $40 million of in-year synergy and productivity benefits. The most important outcome is that the enlarged business is expected to absorb inflation and growth by holding BAU operating costs broadly flat. That represents a meaningful reset of our operating cost base and provides evidence that the wider productivity program is beginning to deliver. Earnings converted strongly into cash. Operating free cash flow increased 49% from $434 million to $648 million. And the cash conversion improved from 55% to 64% of EBITDAF. That is the cash generated after SID CapEx, and it's available to support dividends, improve balance sheet strength, and drive discipline growth. Higher EBITDA was the principal driver, while working capital improved by $55 million, largely as a result of lower fuel and carbon inventories, more than upsetting the higher cash tax interest and standard business capital expenditure. Standard business capital expenditure was $145 million, below guidance of $170 to $185 million. Within that, BAU expenditure was $82 million, also below the $115 to $125 million guidance range. The balance relates to identifiable time-bound programs, including the final year of the Accelerated Asset Program launched in 2021, the Wide Arca Extension, Manoa Hydro Enhancements and the First Payments on the Spare Toe Highly Rater and the integration activity. And that attention is really important. The underlying expenditure that's required to maintain reliable operations remain well controlled, while the higher total reflects those deliberate programs to extend asset lives, complete prior commitments and integrate the expanded portfolio. Some of the FY26 underspend reflects timing with delayed activity moving into FY27. Operating free cash flow increased by 18% from 54.4 cents to 64 cents, despite the issued shares during the year. Together with the equity-raised DRP retention and appropriate use of debt, that cash funded the model acquisition, $375 million of growth capital, and the $387 million of declared dividends. And that's consistent with the capital allocation hierarchy that we set out yesterday in November. One, maintain the assets. Two, preserve investment grade strength. Three, support reliable dividends. And four, commit growth capital only when the returns just fired. The February equity raise and the consolidation of acquisition financing leaves us with a strong and more flexible balance sheet. Net debt was $2.2 billion at 30 June, and S&P adjusted net debt to EBITDAF reduced from 2.3 times to 2.1 times. That's a strong outcome following the Manoa acquisition and continued renewable investment. It reflects the equity raise, the stronger earnings and improved cash generation, and the equity credit treatment of our capital bonds. The balance sheet is also simpler and more diversified. A €500 million EMTN termed out the acquisition funding and extended our maturity profile while we repaid the more administratively complex U.S. private placement facilities. Average tenor is now 7.2 years, and the weighted average gross interest rate reduced from 5.8% to 5.2%, matching our efforts in the low interest rate periods earlier this decade. This gives us the capacity to complete the Contract 31 program, plus the additional growth where customer demand and project economics support us, while continuing to support reliable dividend growth and remain resilient through changing market conditions. But capacity to invest does not lower our return thresholds. For projects not yet committed, the depth of our pipeline over 11 terawatt hours gives us a choice over timing, sequencing and funding. It allows us to prioritise the project that best meets our customer return and risk requirements rather than creating an obligation to commit to every project. That combination of cash generation and balance sheet capacity supports the dividend, and the Board has declared a final dividend of 24 cents per share, taking the FY26 total to 40 cents per share. That's a 3% increase on FY25 and delivers the guidance provided at the beginning of the year. The dividend represents 65% of FY26 operating free cash flow and is well supported by the cash generated during the year. Against the formal policy measure, The dividend represents 114% of average free cash flow over the preceding four years, and that reflects a temporary timing mismatch following Manawa, as the enlarged share basis included immediately in the dividend, while Manawa's FY26 cash contribution only begins to enter the rolling average from FY27. The Board has therefore applied the discretion previously communicated for the initial post-acquisition years. Contact expects the FY27 dividend to increase to 42 cents per share, a further 5% increase at the top end of the range previously indicated. That reflects confidence in the forecast operating free cash flow, the secured money with synergies, and balance sheet capacity. As always, each dividend remains subject to board approval and business and market conditions at the time it is declared. We also retain the 2% DRP discount as part of the Contact 31 funding framework. For FY27, we expect normalized EBITDA of approximately $1045 billion based on mean hydro and wind conditions. That outlook is stronger than the headline comparison suggests. It includes $19 million of remaining integration and platform investment. For those items, the expected underlying operating result is approximately $1.064 billion. The outlook also absorbs a substantial planned reduction in geothermal output during the Wairakei Extension and Tamehi II transition. The Wairakei generation output is expected to be reduced by approximately 428 GWh, partially offset by Tamehi II commissioning later in the year. The output also includes a planned 10-day Tauhara outage. The principal sources that give us confidence in earnings visibility are the full year contribution from the combined portfolio, both secured minor synergies and our contracted revenue position. Approximately 97% of FY27 repricing is confirmed, materially limiting the near-term effect of ASX features on FY27 earnings guidance. Retail net price is expected to reduce by approximately 2% from $174 to $171 per MWh. That reflects moderating wholesale energy input costs and deliberate pricing simplification and retention choices ahead of a potential future retail platform investment decision. So importantly, the FY27 outlook doesn't rely on further increases in retail net price. But we expect that energy components of customer pricing to reduce year on year, with customers beginning to benefit from increased renewable supply and moderating wholesale input costs. That benefit that's under our control will be partly offset in total customer bills by continuing increases in regulated network charges. The acquired Manoa and Mercury arrangements provide an FY27 repricing benefit of approximately $56 million, together with the secured $28 million of cost synergies. That provides approximately $84 million of uplift over FY25 before generation normalisation and demonstrates the acquisition economics we outlined. The outlook also includes renewable generation from Core Fire Park and a full-year contribution from Denbrook Battery One. To conclude, FY26 delivered that step change we promised through Manawa and our renewable investment program, and we converted that delivery into stronger cash flow per share, improving returns and increased dividends. FY27 is supported by largely confirmed pricing. Mercury repricing and the secured synergies within our expanded portfolio. Together, those outcomes provide the financial platform for the next phase of Contact 31. I'll now hand back to Mike. Thank you, Matt.

Look, building on the success of Contact 26, November last year, we launched the Contact 31 strategy, which many of you were present for, to lead New Zealand's renewable energy future. The basics of this are we will extend our advantage as New Zealand's geothermal leader. We will scale on high-quality existing fields, exploring new options and continuing to improve on our cost leadership position. We will lead on new flexibility in this country through batteries, hydro and gas racks, and smart portfolio optimisation, which Matt expanded on. We will deliver lowest-cost diversified wind and rapidly deployed solar. all backed by long-term industrial partnerships. And we'll lead the energy transition at home, empowering our customers to shift their energy use to the times of low cost and demand. All of this will be enabled by empowering our people, maintaining trusted relationships with our key stakeholders, establishing an edge in data and AI, and maintaining discipline, growing productivity as we grow in bulk. We never lose hope. site of the fact that it is our ongoing focus on operational excellence and underlying performance that allows us the privilege to keep growing. I do want to make it very clear that the Contact31 strategy is anchored on building renewables backed by long-term partnerships. This is not a build-it-and-they-will-come strategy. We've talked about the three terawatt hours of new demand sources that are known and committed across dairy, metals, data centres and residential. Just today we saw New Zealand Steel's electric gas service come online in reality and we have the contract to convert the Foriora Dairy Factory. These are clear demonstrations of this commitment to grow, demand and supply at the same time. Beyond these committed projects, we can see up to an additional 8 TWh of live potential across the same three sectors. The potential restart of Plotline 4 at TY is a great example. Some of these are large projects and are potentially binary in their outcome, i.e. are going to happen or they won't. However, even partial conversion of this potential would act as a step change for the demand factor. unlocking renewable development pipelines across the board. This is particularly true with large data centre projects. Leaning into these opportunities, Contact is able to draw on its experience as a developer and operator of renewable energy sites around the country. We have long-term community and stakeholder relationships. We have the experience in planning, consenting and environmental management. And we have that track record of bringing innovative solutions to our customers to help them manage and contract their energy needs into the future. All of this, we will continue to bring to the table to work alongside our existing and potential new customers to unlock future electricity demand opportunities, and more broadly, the economic growth of Aotearoa. We are well prepared to take hold of this opportunity. We have over 41 hours of priority development options across New Zealand. that we plan to build to meet customer needs as they materialize. We have a diversity of options here across technologies and geographic locations, with many either fully or partially consented, putting us in a unique competitive position. And we are prepared to accelerate high quality options from our wider 11 terawatt hour pipeline as the market continues to evolve. Turning briefly to Southland Wind, look, this is a really good example of how we're working closely with our customers to build renewable energy online, hand-in-hand with that new demand. We were granted consent in April this year and immediately kicked off an RFI process to look for a strategic wind partner. We're now engaging with a short list of very credible parties and are close to bringing our partnership plans to life. We intend to bring to wind what we have already successfully done in solar. Not only can a partner bring additional expertise, but an off-balance sheet structure will help to share risk and reduce costs. On the customer side, we assigned a non-binding letter of intent with Rio Tinto for a PPA to support the restart of the idle hotline 4 at TY Point. Line 4 has been idle since 2020. Its restart would require 50 megawatts of additional electricity or around 400 gigawatt hours per annum. and will deliver increased production and export earnings for the nation. Having a credible baseload partner such as Rio Tinto is critical for bringing new renewable generation online. The letter of intent helps underpin our Southland Wind Farm and shows how industry and renewable energy can work hand-in-hand to deliver long-term benefits for Aotearoa. You will have seen our announcement today that Contact has partnered with CDC to explore data centre development at Stratford. This will give new life to the site of our decommissioned baseload gas plant, TCC. It represents a significant step forward in Contact's strategy to lead New Zealand's renewable energy future. Our approach is based on the principles of additionality and support for broader electricity system resilience. Remember that Contact has more than 11 terawatt hours of uncommitted renewable generation projects across its development pipeline. Long-term contracted demands like the proposed Stratford data centre will underpin our ability to bring more of those projects forward. Six years ago, I would have said the Stratford site was likely heading for total closure, aligned with the impact of the decline in the downstream gas market. Now, we're making plans to leverage the unique combination of the site's resources, unlock the development of more renewable energy, and support growth in the Taranaki region with investment across multiple technologies. We have been at Stratford for over 50 years. These opportunities across multiple state-of-the-art technologies could well secure it for the next century. Stratford has existing high-capacity fibre connections, transmission capacity opportunities, onsite firming and a wonderfully skilled workforce. It has all the ingredients for success. We have 500 megawatts of consented battery development and a large-scale solar hybrid battery development currently in the consenting process. And we have an existing footprint with adjacent land under option. We've chosen to partner with CDC, one of Australasia's largest data centre developers and operators. They bring incredible expertise in data centre development,

construction operations and customer connectivity and capability.

They also bring their proprietary closed-loop cooling system that enables exceptionally low ongoing water consumption. They have had strong ties already to this country, both through their operations and through local ownership by Infrator. I do want to be clear that no decision has been made to construct the facility and no material capital commitment has been made The project remains in early stage and is subject to customer commitments, consenting, project level financing arrangements and final investment decisions. Looking at the year ahead, we will see Contact already making strides, big strides on its Contact 31 strategy. We will deliver on the initial milestones laid out when we released the strategy last November. And we will continue to work with customers to advance our active data centre and electrification opportunities, accelerating the strategy and bringing forward more renewable generation for this country. I have huge aspirations for this country and the part that the renewable energy economy can and must play in creating jobs for our children and grandchildren, in building regional communities, powering manufacturing, attracting new industry and technologies and growing the country's export earnings and therefore its wealth. We have a clear strategy, a strong balance sheet and proven execution capability to see us lead New Zealand's renewable energy future. And with that, I'm delighted to take questions.

Thank you, Mike. Thanks, Matt. We'll now open for questions. If you wish to ask a question, please raise your virtual hand. We'll then invite individuals to come off mute one at a time. With that, we'll go to our first question from Vinesh Nair at UBS. Vinesh, you can take yourself off mute.

Good morning. Can you hear me? Yes, I can. Yes. Awesome. Thank you for the very thorough presentation. A couple of questions, I suppose, on the data sent to Neil, and I understand it's early days, but came from pretty high-level reads from you guys at the stage. Just probably to begin with, do you have a view on what it could cost to build out a DC of this scale in New Zealand? If you look at CDC's assets in Australia, the average cost is around about $15 million in megawatts. I think a few industry people have mentioned that sort of New Zealand has a slight premium against that given the size considerations but wondering sort of what style of cost we can expect from an asset of this size Matt maybe you want to

Yeah, those international benchmarks sound about right, and because this is a regional facility in New Zealand, we haven't built data centres before, you could expect a slight premium on that cost. But going the other way, New Zealand has got other features, including cooling costs and renewable energy costs, which are lower than international jurisdictions, and that's what makes it such an appealing proposition.

Okay, so extending that a little bit further, if you do take the kind of Australian benchmark at 250 megawatts, you kind of get to a potential capex of close to $4.5 to $5 billion worth of overall spend. I know you sort of mentioned in footnote four on page two of the release that you might be sort of contributing equity towards it and an off-balance sheet for the project finance structure. Just keen to know if there's a potential upper limit in terms of the equity investment that you guys are willing to contribute to the project?

Yes, the upper limit would be 50-50 from our perspective because we would require this to be financed at the project level as well. We have a range of scenarios which we've tested with our credit rating agencies to see whether we could support an investment up to that scale on our balance sheet, but clearly Any decision around any equity investments would be highly dependent on the economics of the project, the certainty around the capex, the customer credit quality, which is incredibly important, not only from a data center payment perspective, but also to give us the confidence to invest in more renewable growth. So we've run to ground many different scenarios and we're confident that as we sort of step through the details and the risk allocation that we're well-placed.

Okay, and so just finally on the data center piece, any color on, I suppose, timing? That's kind of obviously been absent from the release. Is it fair to assume it's this decade?

This decade is not a bad assumption. Obviously, there's a lot of mahi still to come. We have to get a resource consent. We have to get a customer. We have to complete the concept and detail design. So there's a bit of hard mahi to go. So that's not a bad assumption. That's very clear.

And I suppose just on a couple of other things, I think, you know, that battery from Glenbrook One sort of began operations earlier this year. Any specific learnings to comment on there? Understandably, we're less than ideal wholesale price environment from an arbitrage perspective. But sort of what are your observations?

Oh, we're learning every day and adjusting the models every day. And you saw the value of that battery last week. where the combination of batteries in the market got the market through a record high demand with almost 1,000 megawatts of conventional generation out of the market with TCC, 3P and 100 unit form not in the market. And so, one, it's valuable. We're learning every day about how to integrate the operation of the battery with our existing peaking plans in particular, but we're delighted with the operation of the battery in particularly these last two weeks.

And last one before I pass it on. I think Matt mentioned 420 gigawatt hours worth of lost load from Wairaraki. I think you've got 320 gigawatt hours net on slide 43 there. What's the timing of that turnaround? Does that begin in 1H or is it entirely 2H skewed?

Yeah, predominantly 2H activity there, Vignesh, obviously dependent on a number of different moving pieces, including the Tamiki 2 project, the Wairakini Extension Project, and as well as, you know, micro-conditions at the time. So, you know, we're optimising all those three sort of topics. And as you would have seen, we're really highly contracted. So, you know, the key swing for this year will be hydrology and the management of those outages.

Okay, very clear. I'll pass it off to my peers. Okay.

Thanks, Ignis. We'll now move to Andrew Harvey-Green from 4SFAR. Andrew, please come off mute and go ahead.

Morning, everyone. Thanks for that. A couple of questions for you. First of all, just following on the CDC side of things, is this at this stage very much a project-specific relationship, or are you looking at potentially a longer-term relationship here?

The answer is all of the above, obviously the clear and incisive focus is on getting that initial project off the ground. If that leads to a longer-term relationship, that's a wonderful outcome, but let's keep the focus on the gain in front of us.

All good. Okay, and the next question I just had was, I guess, thinking about the impacts of the lower ASX futures prices. That's probably the biggest talking point in some ways over the last six months. First of all, are you able to sort of talk to a little bit what sort of impact we might expect for FY28, FY29, noting there isn't a huge impact in FY27, but as things reprice, we would expect a bit of a headwind. Are you able to give us a bit of colour on that?

Obviously, the sort of impacts of ASX pricing on FY28 and FY29 are highly dependent on how those ASX prices are going to hold up or not over the next few years. Obviously, when you think about the 12 terawatt hours of generation that we contract, we only have around four terawatt hours that is linked to ASX or those short-term channels, including CNI, and sort of roll up on those is probably a third a year. So it's probably not as impactful as you can imagine. And I guess talks to that... strategy that we've had around terming out our book.

Yeah, thanks, Matt. And then thinking about the FY31 goals that you had in the November strategy day, that was $1.2 to $1.3 billion with a run rate $100 million higher than that at the end of that. You still feel comfortable with those particular targets given the drop we've seen? Absolutely.

Yeah, absolutely. Just to echo Mike, I guess, you know, our targets were always based on a reversion to, you know, 120 to 130 real from the ASX and the ASX is probably tracking, you know, in line with that. The key sort of swing factor in us achieving those targets, Andrew, is really on the demand side. And, you know, if we continue to be as successful as we have been on initiating new demands into the market, then we're very confident on those targets. If we can get this Stratford data centre site up and running, I think that would be an enhancement on that FY31 set of targets.

Yeah, yeah, that makes sense. And just lastly from me, just around the gas situation and looking at your gas book, noting you still have reasonable volumes coming from Posacoura, How confident are you of those volumes actually being delivered over the next five years or so?

I think we've all learned our lesson. We've built resilience into our gas supply book. We are reasonably confident that both the volumes from Pokura and the contracted glass volumes that we acquired from Grey Mouse have good, robust operating performance to back them. So, yeah, we're reasonably confident in that.

Of the 10 PJs, approximately, you know, only 30% or so is from Paokura, which is the variable payers delivered. Greymouth, you know, is a flat contract.

Yeah. Yeah. Great. That's all from me. Thank you. Thanks, Andrew.

Thanks, Andrew. We'll move now to Grant Swanepoel from Jardin. Grant, please go ahead.

Thank you. I am unmuted, I assume? Yep. Thanks. First question just on hydro. So you guys did just over 5,000 gigawatt hours in FY26. Yep. You set yourself a target of 5,750. Everybody else beat their average while you guys didn't. Is that something to do with the way you dispatched Manoa, and how do we have confidence that you're going to do the 5850 normalized into FY27?

Great question Grant. I'll give you the sort of two second summary. On the contract assets, obviously our assets are sort of further down to the bottom of the South Island. So when we had those mega inflows over spring and summer, prices were zero dollars anyway. We couldn't have actually got any more generation out and Meridian sort of stepped into the fold there. So there was quite a significant amount of spill through that period. I think From memory, O2 prices for January were $2, so it wasn't really something that impacted performance, but did impact the volume numbers. On Manawa, there was less generated at Manawa throughout this year. Two factors there. Firstly, wholesale prices have been very low coming into winter, so we're coming into FY27 with higher storage rates. And then the second point, as Mike mentioned, a couple of the larger Manawa assets had extended outages over this period. That's most notably Coleridge and High Bank. And, you know, once we can get those assets back into service, you'll see an improved Hydra output. Clearly, this year hasn't been impactful because of the field situation, but clearly getting up to those capacity factors, you know, is incredibly important, even more so as those big GFML outages come to view.

Thanks, Matt. Next question, just on pricing through your channels, following on from Andrew's question. So your CFD book is more short to shorter term, and you've got almost 20%, 25% of your channel through the shorter term CFD. Are you comfortable with that sort of position going into 28%, 29%, particularly with the forward curve and the potential overbuild relative to lack of demand in the short term?

Yeah, it's there or thereabouts. As I said, I think, you know, 25% to 35% of the total book more leverage to those shorter-term channels. You know, I remember analysts were asking us why we went 110% leverage to those short-term channels when prices were high. And also, just a key point to note in our CFD channels is a large proportion of that is in Mercury CFD sold as part of the Trust Power retail acquisition, which reprices over a two-year period and is more heavily weighted to winter pricing when those prices are still Robust. Very robust. It's the summer pricing, as we've mentioned previously, where the key impacts and changes and challenges are. That's helpful, Matt. Thanks.

And then on data centers, so your 50-50 maximum exposure to equity in that business just surprises me. Your decision to potentially go into data center equity ownership, is that driven by CDC wanting you to have skill in the game, or is that your board saying, actually, I want to be in data centers?

No, it's the value that's inherent in that straightforward decision. with you have a very high capacity connection available. You actually have a 400 MVA transformer available. You have land available and you have the electrical infrastructure available. And in order that that package delivers value to our shareholders, that's where we landed. It's a very unique site and it also has wonderful fiber connectivity. Yeah, it's about getting the value out of that site.

So, in effect, what you're saying, you want a discounted entry into a big data centre?

There would be no payments grant. This would be a sort of organic growth into the data centre. It's the structured site and the speed to market that, you know, is unique to contacting CDC to deliver those projects within the timeframes that customers are currently searching for. You know, it's an undersupplied market and the data center, then this is a unique opportunity for contact because power and speed to market is the most crucial thing that we're hearing.

Okay. So, sorry, I need to get to the bottom of this. So as a contact investor, I don't have to worry too much that you're going to be taking on too much data center risk. Absolutely. So we can actually get that exposure elsewhere if we want to. No, absolutely.

Correct, correct, Scott. And that's why sort of all partnership and investment options on the table. You know, we'd want to understand the relative economics, the, you know, what the customer is going to, you know, deliver to the project from a credit perspective, you know, how long they're going to be around for, and we want to sort of be moulding into that decision.

Thank you. And then my final question. Excellent news on the fourth part that you guys have more or less got the front running on that. But what worries me, you've got 1.2 terawatt hours in the wind project and only 400 gigawatt hours in this sort of load side. How can we be sure that you will stick to your word, that you'll make sure you've got backing before you go and build a big wind farm like that?

I mean, look, it's not just the smelter. The smelter is part of that equation. It's obviously the data center story as well. It's also the other sources of demand growth and the further conversion of dairy. As we said throughout the presentation, the key to unlocking those renewable development options is the demand side effort that we put in. And so we will stick to our word.

Fantastic. Thanks so much for answering those questions. Thank you.

Thank you, Grant. I think we're going to move to Joshua Dale from Craig's Investment Partners.

Josh?

Mute and go ahead.

Good morning. Can you hear me okay? Yep. Brilliant. Thank you. I'm looking at your EBITDAF target for FY31 from your capital markets day, $1.2 to $1.3 billion. The Manawa block in there had a $96 million total contribution, but they had a share in the ASX pricing of $160 per megawatt hour, which is probably... not the case now that futures have fallen 30%. It seemed to be the block that was the odd one out and that the pricey assumption on it was more aggressive than the other blocks building up to that FY31 target. Would that not suggest some pressure on those FY31 targets?

Not enough for that, but no.

Yeah, no, what we're showing is that the FY27 movement on FY26 is up by $84 million, and that reflects the fact that AFX pricing is higher than our long-run average for that portion of the contract that has been locked in with Mercury for next year. The reason the 92 reflects the long-run estimation of wholesale prices, that's $115 to $125 million. The reason why we are getting more next year is because the hydro generation volumes normalising from that 1.5% terawatt hours that we delivered in FY26 up to more like 1.9, which is the benefit of having all of those enhancement projects back online and hydrology improvements. So in the near term, yes, we're over-earning on that contract versus long-run estimates because of where the wholesale prices have been, and that Mercury contract has been progressively repricing for the last two and a half years, but our targets all reflect a reversion to a balanced market.

Right, okay. Perhaps I'll dig into that offline. Just a second question. On slide 22 in your FY27 EBITDAF guidance build-up, you have 12 million of SaaS implementation costs in there. How do you know what that will be if you haven't selected a software vendor yet? Or are you actually quite progressed on that front?

Yeah, we're reasonably progressed on that front. The future retail platform, getting that to the right customer platform is... and they have made the teams of the retail and technology teams have made some good progress on that.

Yeah, but the quantum and the timing, you know, you're right, it's really dependent on whether we go to file an investment decision or not. We just thought it appropriate to put our sort of best estimate of where we're at within the process today so that sort of the models can assume that they'll be coming through OPEX as opposed to Stan Bookman's capital and, you know, maybe the waters on our, you know, productivity program which is delivering good value.

Makes sense. I mean, I appreciate you're looking to sign this off over the next 12 months. Are you sort of thinking sooner rather than later or perhaps later in the year or any indication?

It'll be sometime during calendar 27, the timing's yet to be determined.

Yeah, but obviously there's not only the work to really get an understanding of the implementation timelines, the risks associated with it and the benefits that we're going to achieve. We need to keep our sort of eye on the regulatory environment and carefully manage any investment expenditure which could not deliver for contract shareholders through sort of potential other political machinations.

Got it. Thank you. Final one, the data centre at Taranaki. I was interested to read there might be a demand response type component to that. Are you able to give any indication... as to what that might look like?

Yeah, look, not at this stage. Obviously, data centre load, depending on the load, has a certain amount of variability, and I think it's important that you are able to manage that variability through, might be batteries, might be various other syncons and the like. But when that variability is not being used for the data centre, you're then able to deploy that back in the market, and that's the extent of the thinking around that.

Okay, makes sense. Thanks very much, guys. Thank you.

Thanks, Josh. And we'll move to one more set of questions. So Steven Hudson from Macquarie, over to you. Steven. Can you come off mute and go ahead?

Right, Steven, gotcha.

Hey, just a couple from me. just on the uh retail tariffs i know it's a sensitive issue as you explained but um the 171 dollars per megawatt hour that you've penciled in for fy27 versus the sort of roughly 125 long-dated futures in the north island can you give us a bit of a feel for Yeah, so that's a 37% differential. Can you give us a bit of a feel for what the shape and location uplift on, you know, a time-rated price is, just, you know, based on what you can see of your portfolio, just so we can kind of square some of your questions around downside risks?

Yeah, great question, Stephen. So, you know, when we're thinking of $120 per megawatt hour at Odaho, when you think about the fact that two-thirds of customer electricity is in winter, and winter prices are clearly higher than summer prices. Customer use more electricity in the peak periods, morning and evening, and customers are not all, thank goodness, living in Auckland. That sort of adds $10 to $15 per megawatt hour premium over your $120. Remember, you also need to recover your operating costs associated with the retail channel, so $78 million over our volume is about $27 a megawatt hour. When you add in the margins needed to support things like our future retail platform of around 5%, which is, you know, pretty small when you consider the risks taken within that business, you're sort of broadly, broadly, broadly sort of up at the $155 to $165 per megawatt hour mark. So, you know, we're not expecting sort of large changes in that retail channel. You would have known for the last six years we've been very moderate around how we've recovered those energy prices. And so... That's just a function of the way that we manage retail as a long-term channel. It doesn't go up as fast, and any big shifts like we've seen over the last six months are not as impacted.

Thanks, Matt. That's useful. Hey, just a quick question on LNG, maybe for Mike or for you or Shelley. Just what you're seeing is the probability that that will be part of our dry year energy swing source. And without loading the question too much, what are the 30 PJs of industry, industrial demand going to do if it doesn't transpire?

And I think that's why the thing with LNG is that I think there are other ways to manage value risk primarily, but that's important. those gas users who are finding it difficult to convert off gas that we continue to look after them because they do make a significant contribution to the broader economy. And so the answer on LNG is yes, as a country, we need to give it serious consideration, but we also need to convert those gas users who can convert to electricity as quickly as possible. We possibly need to increase the coal stockpile at Huntly. We need to look at potentially increasing the diesel strategic reserve of the country and we need to look at increased hydro operating ranges. And as part of that mix with the continued decline of upstream gas supply, LNG has to be given also serious consideration.

So, Mike, the probability that it does actually get off the ground this year?

That's dependent. Look, like any investment decision, it's dependent on what the assessed cost is. It should be developed as a robust and economic project. If we can make sure that it is right sized and right specced, it's probably got a reasonably good chance of getting off the ground. If it's gold plated, it's the wrong thing for the nation.

Okay. And just a question on the CDC announcement. Well, maybe a couple of questions. Firstly, it looks as if it's a 350 megawatt built project that you're applying for, not 250. Can I just clarify that?

Yeah, it's 250 output, 350 input.

Yep. And were you hinting that actually it could be larger than that, given your infrastructure, your existing infrastructure there?

No, no, we're saying that's what we're focused on today. There is capacity potentially for more, but no, that focuses on that one data center and getting that off the ground.

Yeah, but sorry, what's the envelope given your grid connection?

Well, the grid connection is 400 megawatts, 400 MVA, which is the existing transformer there for TCC. And I think the maximum capacity at the site is 600 megawatts or in that order before grid upgrades are required.

Yeah, okay. That's exciting. And is there a sort of a... Presumably there is actually a US hyperscaler or an anthropic that's actually put some megawatts of demand in front of you and CDC.

Oh, we can't. Obviously, we can't discover... any of those conversations. It's fair to say that we were on an international tour recently promoting New Zealand as a data centre destination and we were right up there with the Nordic countries in terms of the attractiveness of New Zealand. We have the renewable energy, we have the cooler climate, we have a strong pro-investment market and we have the digital connectivity. And so like Norway and the rest of Scandinavia and Iceland, we are right there at the top of the pecking order in terms of attractiveness for a data centre, a renewable energy-powered data centre.

Well, I guess you're also not within a 2,500 kilometre missile range of Tehran as well, which has been... And outside the range of any known Sata drones as well. Yeah. Just in terms of what leverage meant, you kind of assumption you were... running under your scenario? Is sort of a seven times stabilized debt to EBITDA number kind of something that we could use, do you think, realistically?

That's probably sort of a little on the high side, Stephen. You know, our existing sort of business, as you know, attracts sort of three times debt to EBITDA ceiling for our BBB investment grade, and that will continue to be our target. you do get a different dispensation for data center revenues because of the relative stability, the long-term nature of those contracts, but that's more sort of like five times net debt to EBITDA, so the sort of relative proportion of earnings from any potential data center would be sort of included within that calculation to give us a more favorable net debt to EBITDA metric within our existing measures, but obviously all that to be work through and we know that we can do it. It's now about securing sort of all the risk questions which are fairly going to be important as we work our way through the project.

Yeah, okay, that's useful. Sorry, last one. You talked about an upper limit of 50-50. You know, it's obviously a bit of a silly question, but presumably you would then entertain something like, you know, a 10% or 25% stake as well.

to put your foot on the... Yeah, we'll firm that up over the coming months, but yes. Okay. Thanks, everyone. Thank you. Thank you.

Thank you, Stephen. That's our quick question, so we'll close the meeting. Thank you to everybody for joining online.

Thank you.