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,