Contact Energy Limited (CEN) Earnings Call Transcript & Summary

Welcome, everyone, to the Contact Energy half year results presentation. It's brilliant to have you all here in what's been a very big 6 months. And so without further ado, let's get into that. Just to note the disclaimer and presenting today, I have on my left, Matt Forbes, the acting Chief Financial Officer, and I apologize for those initial technical difficulties. Right. Looking at the agenda, I'll present the first half highlights and give you a bit of an overview of the market context, which is obviously getting a bit of discussion at the moment. Matt will then present the financial results and give you a bit more detail around it. We flick to the next slide. Look, the highlights today, I said it's been a busy 6 months. It's been a hell of a busy 6 months. Glenbrook battery is obviously underway. We entered into the Manawa scheme of agreement, announced dividend uplift to Huka 3 online. Construction is underway on Kowhai Park, and we can talk about that a bit later. Obviously, there was a little bit of drama around August and the deal we did with Methanex to bring additional gas to the market. We confirm the investment in Te Mihi Stage 2 and the earth movers are on site shifting as we speak. Last week, we announced the Fonterra deal for an additional 415 gigawatt hours of demand conversion at Whareroa and the retail arm of the business to continue to go from strength to strength, particularly in the Demand Flex products and time-of-use products, the latest being the Hot Water Sorter. The team are doing the [ TCPR ] inspection of TCC as we speak to make it available for autumn and winter this year. We continued with our representation in the DJSI Index as one of New Zealand's leading sustainability proponents. And last week, we also saw the announcement around the MSCI entrance. So all in all, it has been a very busy 6 month, if we move to the next slide. One of the things I do want to just touch on is there have been executive team changes. Obviously, Jack, our Major Projects Director, is retiring and Jacqui announced her retirement late last year. Dorian has moved to Chief Development to Major Project Officer, and we see benefit in that merging of those 2 groups. Tighe Wall has been appointed Chief Technology Officer, combining ICT and digital and Matt Bolton has moved across to the manage the transition for Manawa. Mike Robertson is the acting Chief Retail Officer. And obviously, both for both CFO and CRO, we're running a recruitment process. All big changes, but also you'll see some continuity there, which is so, so important as we look to continue to invest. We go to the results themselves on the next slide. The overall EBITDAF is up on an underlying basis and on an end-to-end basis. Profit underlying is also up, though last year was inflated a little bit with an AGS write-back. That hides the – may be some of the turbulence that was in the market where we did the right thing with the low hydro inflows in June, July, August and back that with the Methanex gas deal. We continue to see increased prices, obviously, with the lines charges going up for the retail market, but we continue also to see growth in our retail market share, and we're delighted with the growth in the telco arm of the business in both broadband and mobile. Obviously, we've seen the benefit, the primary driver of that increased profitability is Tauhara and more lately Te Huka 3 coming online and those plant coming in and running, particularly Tauhara running well is the result of some really hard work by the team to bring those on reliably. SIB CapEx, we continue to invest, particularly in the Roxburgh runner and the first runner is in, and we're delighted to report that the performance uptick that we promised looks as though it's going to be delivered. And so there's 3 more of those runners to be installed. If we move to the next slide. Contact 26. I hope this is probably the most boring slide of the presentation given we have been rigorous in putting it up each time since we presented the strategy back in May 2021. We continue to see the growth in demand underlying, if you take out the smelter, backing off last year, demand continued to grow. You can see the Tauhara-backed PPAs with both the smelter, but also Oji and Pan Pac and other parties and the Fonterra deal. We continue to progress towards an FID on the CO2 plant at Ohaaki. And as I said, underlying demand looks as though it's growing. Renewable development, Te Huka 3, obviously coming online in December. Glenbrook construction and Kowhai Park are well underway. The base is in at Glenbrook. We expect the battery units to start arriving from April this year. Some of the inverters and panels have already arrived on site at Kowhai Park. And also, we got underway with the investment in the 100-megawatt plant at Te Mihi 2A, and the earthworks for that are well underway. With the decarbonization, look, we're obviously keeping TCC around for this year at least, if I need to provide surety to the market. We did purchase the forestry partners investment to make sure that we have offsets if we need to continue to provide peaking gas electricity, and we're doing the right thing by New Zealand in that regard. Retail total connections were up, again, but mainly based on telco, which is broadband. You've seen the good plans that time-of-use products, the ability of households to shape their own electricity usage and to get access to low price or free electricity in those off-peak periods. That continues to adopt both. The Hot Water Sorter, which is already at 7,000 connections or the best part of 2 megawatts per day being moved out of the peak and doing the right thing by ordinary Kiwis in tough times, removing those disconnection and reconnection fees to make sure we're looking after the most hard press of New Zealand society. We're a finalist 3 years in a row for Energy Retail of the Year. That just speaks to us being recognized for the good work being done for ordinary Kiwi households. If we go to the next slide. Our ESG commitment remains the same. We remain committed to our environmental sustainability governance objectives. We remain in the DJSI. We're rated AA in terms of the 4 bar and ranked second out of 61 New Zealand companies, which we're delighted with. Thank you, Andrew. And we extended our partnership with Women's Refuge. Operational excellence. Look, this is the heart and soul of the company, making sure that good people turn up each day and doing the ordinary things extraordinarily well. You've seen the process safety upgrade. We completed the Te Mihi shutdown, which was a 10-year event. That was completed safely, on time, and we're delighted with the outcome. We launched the trade deal capture, start digitizing our trading of our business, which I think is important for the road forward. And we launched new mobile apps and self-service for retail. Transformed ways of working. We were recognized for that with the Well-being Award. We've launched our leadership program, which is part of the Mau taniwha transformation to make sure our leaders of the future are well equipped, and we received our Well-being Tech. So all of those things we continue to deliver on. It's important to note in terms of the strategy that has served us well. 2026 is looming fast. So it's inevitable that there will be a refresh of the strategy, and we will continue that after we complete the Manawa deal. Demand, if we move to the next slide, you can see the decarbonization of New Zealand heavy industry continues. New Zealand Steel have announced the Electric Arc Furnace, the Fonterra deal, which was announced last week. We can see that the transition of New Zealand to a low-carbon economy does not mean the industrialization of this country, but with good and willing participants on the other side, we're actually able to create growth opportunities for the country, which the Prime Minister has talked about as being so important for the recovery of this economy overall. And as part of that, if we look at the renewable energy build online, the equivalent of 200,000 homes have been decarbonized and powered with the investment in Tauhara on May 2024 and with Te Huka 3 coming online late last year, and we're delighted with the outcomes on both those projects. But that's not all, as I'd say. We have the battery well underway and the units, as I said, arriving early April. Kowhai Park, the inverters and the panels start to arrive on site already. And Te Mihi Stage 2, we have taken FID and the earthworks are advancing very well, building on the experience that the team have built up already in terms of Tauhara and Te Huka 3. We move to the next slide. We have a strong and robust pipeline in front of us outside of geothermal, where obviously we have Te Mihi 3 and Tauhara South in the pipeline, we have Glorit Solar North of Auckland. We have Stratford Solar, both solar and battery. So that site at Stratford has been transformed -- is being transformed into a renewable energy hub of the future, which is great to see. And Southland Wind, we continue to await the conclusion of the resource consenting process and look forward to that mid- to late March. In terms of the regulatory focus, it's fair to say there has been a lot of focus on the industry these last 6 months. Obviously, fuel security is number 1. We continue to transfer away from the reliance on gas for baseload electricity generation. That's not to say gas won't have a role in peaking in the go forward, but I think the days of baseload gas being used for generation are numbered and well on their way out. We are making TCC available this year. But after that, we do see its retirement. What's important is that we continue as a country and as a company to invest and in baseload geothermal in particular, which has risen from 20% of the market to 25% in the last 6 months alone. And that investment is what ultimately will provide security of supply. You'll have also seen our announcement last week of being part of the heads of agreement on the HFO and strategic energy reserve for the country. That is also important to cover the variability implicit in hydrology. We participate in the industry study in LNG, and I'm happy to take questions on that later. The conclusion is probably LNG at a global scale as we team of directors and management went up to the Middle East to have a look. The scale is mind-boggling and probably not appropriate to the size of the New Zealand market, but there are continuing investigations as whether a fit-for-purpose option is available. But what's important is that we do not wait that we actually make sure that there is security of supply in the here and now. And that is why that strategic energy reserve at Huntly is so important. We do support the continued evolution of the market as market settings obviously have to evolve. We note the government's task force, which will report back later this year. And in terms of Resource Management Act, look, we -- the Fast-track Consenting cannot come soon enough. It's really important that behind the legislative change, there is also investment in the capability of the people working on consents. Remember, there are 150 projects already in the Fast-track process. That means we need 450 commissioners. And so lifting the capability and capacity of those people to make decisions and make good decisions quickly is critical for the country and critical for the government's growth agenda, and it cannot come soon enough. Moving to the next slide, just about the market context. Obviously, there was a little bit of drama last year with the high prices over August and then the rain came. And while for 2 weeks, we had the highest prices in the OECD for 3 months, we had the lowest prices in the OECD. One of those things didn't quite make media. But the demand is growing. You are seeing the conversion of both homes and industry to electricity and decarbonizing and the underlying electricity demand is growing, which we're delighted about. Hydrology does impact the generation mix, obviously. You can see on this slide, the increased amount of geothermal, which is great. Hydro was down on average, which may led to a higher-than-normal amount of thermal in the market. Hopefully, as geothermal as base continues to grow, that amount of thermal will continue. But we are very dependent on hydrology, which can fluctuate. In terms of forward wholesale pricing, we've put this graph up. It's one of Matt's specials from many years ago. And those factors which influence the price remain the same. And the key thing that's changed here, if you look around that, yes, hydrology is a bit lower. But obviously, gas and the turmoil in the upstream gas industry is having an impact, a downstream impact on the electricity industry. And the sooner we can reduce our dependence on that gas, the more or the sooner common sense will be restored to the market. And so we recognize the volatility in the wholesale market. We recognize that prices remain at an elevated level, even above what we see as the forward price path, which is exactly what we announced last year, $115 to $125 real terms '24. But that price will only be realized as we continue to invest in renewable energy in the go forward. What you also see in the retail market is differences in retail strategies. We obviously have diversified into telco and have invested significantly in time-of-use products to allow ordinary Kiwi households to decarbonize their own usage -- energy usage in the home. And we will continue to support that. The tariff changes, you can see there the impact of increased line charges, and those will continue to be passed through. We do recognize that ordinary Kiwi homes are doing it tough, and we do recognize these lines charges are the tail end effect of a high inflation, high-interest rate environment. And the sooner we can get through the better for everyone. Matt, handing over to you.

Thanks, Mike. Good everyone. I'm Matt Forbes, and it's a privilege to present the first results as acting CFO. While this is a new role for me, many of you will know me from the 15 years that I've spent at Contact, starting out in our geothermal business in Taupo and more recently heading up our Investor Relations strategy, market risk and corporate finance functions. It's a real great time to step into the role, especially when considering the health of the business and Contact's continued commitment to decarbonizing New Zealand and building a better New Zealand. The first slide highlights some of the key themes over the past 6 months, and I'll spend some extra time in this context before showing how these themes impacted our key performance drivers later in the presentation. The key theme is that our new geothermal power stations are now delivering electricity. During the period, we commissioned the Tauhara geothermal power station at a capacity of 174 megawatts. This is the largest geothermal power station commissioned globally in 2024 and accounted for 45% of all global geothermal capacity additions. That just shows the context and the scale of the Tauhara investment in the New Zealand renewable development space. Tauhara generated approximately 600 gigawatt hours in the year, which is at a capacity factor of around 77%. So that is lower than the normal 95% we expect from our geothermal plants. This reflects the commissioning activities to get the plant from 150 megawatts limit at the start of the period up to the 174 megawatts that it's running at today. Despite these outages, the Tauhara plant contributed around $92 million of EBITDAF to the period. The newly constructed Te Huka 3 plant, which commissioned in December, has been running above its 51-megawatt business case and delivered over 40 gigawatt hours in the period. The second theme was our role in supporting the electricity market. The period between May and August 2024 was exceptionally dry and hydro storage levels were at the third lowest ever recorded. This is an interesting start, but it's not unexpected, especially when you consider that we are in a hydro-dominated market with limited storage. That's why we maintain dispatchable thermal generation, access to gas storage and a sophisticated risk management system. However, the inability of the gas producers to meet their contractual obligations did mean that there was more risk, especially if that dry period had continued for much further. which was obviously unknown at the time. But Contact was well positioned. We didn't need the extra generation to meet our customer demand, but we did have TCC available. So we purchased gas from Methanex who shut down their methanol production until October and sold a short-term CFD to Meridian. The total cash cost of this gas was around $100 million in the period with the electricity sales covering much of this exposure. In Q2, it turned from very dry to very wet. Consequently, the available gas in – gas in our AGS went up from around 1.6 PJs to 3.4 PJs and the weighted average cost of that gas went from $9 a gigajoule to $15 a gigajoule. Now that's a material increase in our gas cost and inventory, but compares very favorably to the long-term arrangement we just signed with OMV. We were also forced to sell 1.8 PJs of gas in Q2 as AGS approached its limits. This led to an $18 million loss on that transaction. Contact is really proud of the role we played in security of supply. Even though it did not improve our operating earnings, it was the right thing to do for New Zealand. The third theme of the period was the start of a new contract with the New Zealand Aluminium Smelters or NZAS. In the period, we commenced a new 20-year arrangement with NZAS with improved pricing relative to when we last struck the contract in 2021. A new feature of the contact is demand response, where Meridian can call the smelter to reduce their demand and Contact gets access to 25% of that demand. The cost of this demand response in the period was $38 million for Contact. The settlement cost, which is in effect, the benefit that we received from this 134-gigawatt hours of acquired generation was $20 million, a negative $18 million impact from this call. This reflects the fact that the smelter was being paid to reduce demand, but we had a glut of hydro generation and very low spot prices in Q2. The fourth theme is around actions we've taken to prepare for winter 2025. Well, why is this a topic? Contact has materially lower levels of contracted gas in 2025 and has had an epically dry start to the year, with inflows into our Clutha catchment over February to date, the lowest ever recorded. In response to these risks, we extended the operations of TCC when it was planned for closure in 2024, and we've also kept storage in AGS and Ahuroa very high. In addition, we've also changed our timings of outages and brought forward an outage of Ohaaki from August to May. We're really taking a lot of proactive steps to make sure these power stations are available, ready to run, looking to get additional gas supply into the market and strengthening our risk management systems. With all these measures in place, we are very confident we can navigate a wide variety of market conditions, while we're always cognizant of the fact that one large rainfall event can materially lower wholesale prices. The fifth theme talks to our proposed acquisition of Manawa Energy. We announced the Manawa scheme of arrangement in September and are actively preparing for the potential combination. The strategic rationale for the transaction remains compelling. We continue to provide the Commerce Commission with all the evidence that they are going to need to support clearance of the application under the Commerce Act. And we are really eager to get to work on delivering those benefits to New Zealand that the combination will provide. On to the high-level movements in the financial performance now. But to provide a clearer picture of the underlying performance, we have removed the impact of the AGS storage contract -- onerous contract from FY '24, which was positive. This allows for better comparability between the periods and understanding into the underlying performance of the business. EBITDAF for 1 half '25 was $404 million. The chart on the right shows the impact of price and volume across our generation and sales from an integrated business perspective. All comparisons and variances I will talk about relate to 1 half '24 underlying EBITDAF. So let's start with the volume impacts. We had higher hydro and geothermal volumes, which increased our EBITDAF by $55 million. Total electricity sales increased EBITDAF by $7 million, which is a comparatively lower amount to the renewable generation that came on, which reflects the fact that in 1 half '24, we already had a higher level of contracted sales in advance of Tauhara coming online. Moving to channel pricing. Pricing on our market-linked channels was higher and improved EBITDAF by $114 million. This reflects the stressed market conditions in July and August. Pricing improvement on the long-term channels added an additional $25 million. This is where you see the impact of the improved NZAS pricing, the start of our PPAs linked to Tauhara generation and a 0.5% increase in the integrated energy margin from our retail business. On the cost side, the price impact of the expensive Methanex gas, the acquired generation and the demand response payments can be seen here. It reduced EBITDAF by $83 million. The very wet Q2 saw an increase in location losses, which reduced EBITDAF by $18 million and the movement in other income, which was negative $16 million reflects that loss of sale on gas, which I referred to upfront. Fixed operating costs reduced EBITDAF by $13 million as other operating costs were up by $20 million with $10 million of that related to the Manawa acquisition. If we turn our attention to the movement in profit, underlying net profit after tax was up by $8 million or 6%. As outlined, underlying EBITDAF was up by $70 million, with depreciation only up by $4 million. This reflects the Tauhara $16 million in depreciation, which was offset by lower generation at our thermal business, reducing depreciation on those thermal assets. Interest costs were up by $32 million, which reflects our higher debt levels and the -- removal of capitalized interest to the Tauhara plant as it came online. Capitalized interest in 1 half '24 was $29 million. Fair value of financial instrument movements reduced net profit after tax by $26 million. The key driver of this was our realized market-making losses of $14 million in the period, which was $12 million unfavorable. This relates to our obligation to continue to make a market even in volatile trading conditions as experienced in July and August. As the new NZAS contract has got a termination option after 10 years, we are unable to hedge account this contract. So fair value movements in the contract will now be flowing through to changes in financial instruments and potentially increase the volatility of our net profit after tax. This comes about if the forward projections of future wholesale electricity prices differ from our projections at the time in which we entered into the contract. We have added a new slide in the appendix to outline the key movements in financial instruments, especially those as those relate to movements in the income statement. Moving from our integrated business view into the performance of our operating segments next. The wholesale business saw EBITDAF increased by $109 million to $466 million. This is led by higher renewables, improved pricing across all our channels and partially offset by the higher cost of generation. The retail business EBITDAF reduced by $24 million to record a $25 million loss in the period. Competitive cost pressures meant that increases in network costs and energy costs were double what we were able to pass through in tariffs. Ongoing pricing discipline in retail is critical to support the ongoing development of our renewable pipeline. Corporate costs have increased by $14 million to $37 million, with $10 million reflecting costs associated with the Manawa transaction and preparation for integration. Now diving into the performance of the generation division of our wholesale business. Despite our share of renewable energy increasing to 89% in the period and the thermal generation down by 300 gigawatt hours, we saw costs of around $53 million. This reflects the short-run costs of gas and acquired generation, which are now over $220 a megawatt hour, double what they were in the previous period. This is the new normal for backup generation. Gas costs are structurally higher, demand response costs more, and there are more fixed costs in the thermal system than there were previously over fewer periods to trade. In our geothermal operations, we successfully completed the turnaround at Te Mihi, which reduced generation by 137 gigawatt hours in the period. We've added a new disclosure in the appendix, which outlines the schedule of geothermal outages going forward, which is more important as replacement costs during these outages are now north of $200 a megawatt hour and now demonstrates the value of having those Tauhara-linked PPAs. Thermal generation has been incredibly important in supporting the energy system and TCC had an outstanding 6 months, was available 100% of the period. TCC is currently on outage, so that it will be available to run over winter 2025. The key constraint is not going to be around availability of station capacity, but rather if there will be gas to fuel the power station. Those with the potential to bring new gas into the market over the next 6 months have been waiting, hoping for maximum leverage. History cautions against waiting too long as the opportunity might be beyond them. Hydro generation increased by 2% during -- due to high inflows in the second quarter, but this belies the fact that it was very dry in the first quarter and very wet in the second quarter. The first Roxburgh runner has been installed and has been delivering the expected performance uplift. And once all 4 of those runners are installed by 2026, we will get an additional 45 gigawatt hours of generation. Looking ahead to our performance of our wholesale channels and our wholesale business. Wholesale contracted revenue was higher on both higher volumes and improved pricing. CFD revenues were up by $134 million and volumes were up by 154 gigawatt hours. This step change reflects the sale of electricity to Meridian backed by the Methanex gas. Strategic fixed price sales volumes were lower with the reduction on sales to NZAS from the demand response, but the pricing received in this channel was materially higher. Both the volumes of sales through our strategic fixed price channels have increased from the 1st of January with an additional 45 megawatts sold to the smelter and up to 62.5 megawatts sold to Genesis. Our commercial and industrial volumes have increased by 72 gigawatt-hours in the period, but pricing remained flat and below our expected guidance. Given the fuel risks and our upcoming starts to those long-term PPAs that I just mentioned in January, we decided to prioritize the shorter-term CFD channels. So while channel pricing in this specific area has lagged, yields across contact are up. The retail sales pricing reflects the movement in our arms-length transfer price, which references the ASX those prices have been higher, and we are now seeing a much more pronounced swing of pricing between those summer contracts and those winter contracts. And as we all know, retail demand is higher in those winter contracts. The volume in that channel reflects our target of maintaining 3.8 terawatt hours in retail over a financial year. Again, the other income reflects the loss in sale of gas mentioned previously. On to our wholesale trading position and performance. We typically generate electricity only above our contracted sales to offset the price impact of where we purchase electricity to supply customers and where we generate electricity into the spot market. This is colloquially known as LWAP GWAP or location losses. In the second half of the quarter, because of the low wholesale prices, we generated electricity below our contracted sales, which is effectively sing power from the grid and keeping our gas and storage for 2025. As a result, while trading EBITDAF is $6 million lower, we've put ourselves in a much better position for the second half of the year and didn't have to run expensive thermal. On to our retail business performance. The retail business recorded an EBITDAF loss of $25 million. We continue to adjust retail tariffs in the period to meet the higher network costs and elevated wholesale pricing. And in addition to the recovery of energy costs, tariffs are going to be need to be reset in 2025 to reflect the Commerce Commission-approved changes to lines costs. These costs account for between 35% and 45% of the customer's bill and are estimated to go up by an average of 18% from the 1st of April 2025. These costs are a hangover from the normalization in global interest rates following the last reset period in 2020. We don't take pricing decisions on our retail base lightly, and it shows the importance of having those time-of-use products where customers can switch their electricity usage into the cheap and free periods, providing them the choice. Gas gross margins decreased from $10 million to $7 million, which reflected the lower sales volumes in that channel alone. We're achieving an effective price of around $20 a gigajoule in that channel, which is reasonable when you consider the opportunity cost of gas through our Peakers. However, with the decline in domestic gas production and contact is only a retailer to support upstream gas production, we're really going to need to have more engagements to continue to supply our retail channel at the volumes required. Telco, which is a combination of broadband and our newly launched mobile products grew strongly in the period with connections up by 24% and gross margins up by $1 million to $6 million. Margins per connection were temporarily impacted as we aligned our pricing changes on electricity and retail broadband. Increases to the local fiber costs continued unabated. Our industry-leading cost to serve was again a standout in the period with cost per connection down by $6. In absolute terms, cost to serve was down by $1 million. However, there is an element of unwind in advertising and promotional expenditure that we expect in the second half of the year as we target growth in multiproduct customers. On to operating costs in the period. Operating costs, excluding Manawa, were up by $9 million, which is a 7% increase on last year. This reflects growth relating to our new plants coming online and continued above CPI inflation in key cost items. $2 million reflects the higher performance incentives following a very strong FY '24 performance. Inflation increased operating costs by $6 million. This reflects an increase of 3.5% for salaries, 25% for insurance, 2% for general inflation, and regional council rates, which continue to increase at between 15% and 30% per annum. Pleasingly, we delivered a $1.5 million savings in our insurance program through the restructure of this program. New geothermal stations clearly add operating costs and the $5 million bucket around growth OpEx, the highest proportion of that relates to the Tauhara coming online. Over the past 4 years, we've intentionally increased our base operating costs to be rightsized for growth. But as we've confirmed in our FY '26 guidance, we are now rightsized with future cost changes reflecting portfolio shifts such as new power stations online and general inflationary allowances. This level is clearly the base for us to bring in our ongoing productivity programs. On to cash flow and capital expenditure. Operating free cash flow of $138 million was $36 million down on the prior period. Offsetting the increase in EBITDAF, we had higher working capital movements in the period and higher interest costs. Of the $80 million negative working capital movement, $61 million relates to inventory and our purchase of higher-cost gas. The weighted average cost increased by $6 a gigajoule over the full 7.7 PJs that we have in AGS, and this increase is compounded by the fact that we increased the gas and storage by 1.8 PJs over the period to prepare ourselves for 2025. A $43 million increase in net interest paid includes lower capitalized interest with Tahara now commissioned. We're now nearing the end of our accelerated stay-in-business capital program and same business CapEx for the period was $65 million. Included within CapEx was $9 million spent on the Peakers, $13 million on our geothermal outage program, most notably the Te Mihi outage that I've referred to, and $10 million on a spare rotor at Te Mihi. EBITDAF to operating free cash flow conversion is 34% with a full-year estimate of around 50%. This is lower than our historic 60% due to the onetime permanent working capital impact from the higher cost of gas on that 4.3 PJs of gas, which might only be extracted at the end of the contract in 2033. Contact invested $179 million in growth capital investment, which is around 130% of our operating free cash flow delivered. On to the details around our growth CapEx. There are no updates on the expected costs of any of our growth capital projects, but pleasing to see the activity coming through. Going forward, capitalized interest will only be accrued on the Te Mihi 2 project and our battery at Glenbrook. On to the impact of this activity on our balance sheet. As should be expected, net debt levels have continued to rise in line with our renewable generation project investment program. Aligned with our strategy to access the lowest cost funding sources while maintaining our BBB credit, we issued a $250 million green capital bond in the period. Net debt to EBITDAF ticked down to 2.3x, which reflects the 50% equity credit that S&P give to the capital bond as well as our increase in EBITDAF. With our continued use of capital bonds, dividend reinvestment programs and off-balance sheet structures for solar, we remain very confident of the strength of our balance sheet, including the additional debt we need to take on above the script issue if the Manawa acquisition proceeds. On to dividends per share. The dividend for FY '25 is targeted at $0.39 per share. This equates to an interim dividend of $0.16 per share, which is up $0.02 per share on the prior period. We can -- continue to offer a 2% discount on our DRP. This delivered a 34% or $64 million retention of the dividend at the final dividend last year. With Contact's inclusion into the MSCI coincidentally happening around the same time as the DRP pricing period, I suspect we could get an even larger take at this time. Finally, on to the outlook. Excluding the costs associated with the proposed acquisition of Manawa, Contact delivered an EBITDAF uplift of $29 million in the first half. This has given us the confidence to revise our expectations of full year normalized and expected EBITDA excluding the Manawa costs to $790 million from $770 million. The change to the second half expectations reflects the fact that we have brought that Ohaaki outage into this financial year from next financial year and the dry conditions over the last 6 weeks. There are a number of changes to our portfolio and these include the high cost of gas, the high cost of acquired generation, demand response. We also have a number of new long-term contracts that are starting. We have an annualized impact of a lot of staggered geothermal outages that have come through the commissioning programs and many different changes to the way that prices are set in our market. To help navigate these changes, we have provided an early view on our normalized and expected guidance for FY '26. And we're proud to demonstrate the ongoing improvement in our EBITDAF as a result of the continued delivery of our Contact26 program. Now over to questions.

Thank you, Matt and Mike. We're going to move to questions now. We will start with questions in the room. [indiscernible] Andrew Harvey-Green.

Good morning. A couple of questions from me. First, a couple just around, I guess, guidance first of all, starting with FY '25. And just in terms of what your thinking is around since sort of dry conditions going on in [indiscernible] selling more gas [indiscernible]. What are you thinking around the potential for that? I assume it's not included.

No, that's not included. So obviously, the guidance, I think we guided to $790 million normalized with a $20 million allowance for transaction costs and that's normalized -- on a P50. Obviously, how the market develops over the coming months with the Methanex, potential Methanex transaction. We're exploring a range of alternatives there. It will be within [indiscernible] that result, plus or minus.

And I'm assuming we would probably see [indiscernible] take place much sooner than last year?

Yeah, that's the wish of all stakeholders involved. Yes, absolutely.

FY '26 guidance, [indiscernible] that looked a little bit conservative. There are a couple of things just sort of [indiscernible]. One of them was the CFD sales price [ projection ] is actually lower than FY '25 slightly unusual I guess, given the [indiscernible] price environment.

Sure. Yes, absolutely. So clearly, the FY '25 CFD price reflects the deal we did with Meridian during very stressed conditions and that was linked to the cost of the Methanex gas. Going forward, we will be selling more CFDs during the summer periods because we are closing TCC and replacing it with baseload geothermal generation, we are more biased towards selling more electricity in the short-term CFD market through summer and the pricing is slightly different for those periods. Now clearly, there's still a reasonable amount of sales contract in the CFD position and depending when we do these slides, they can be out of date very shortly thereafter. So, I think it's a reasonable balance between being confident we can deliver FY '26 18 months out, but with upside.

And the other piece that looked, I guess, high was the cost of power generation up to about $300 a megawatt hour is what you're indicating.

Yes. So, what that reflects is our mean expectations for generation. In that acquired generation line, you will see all of our premiums for risk management products. But in the [indiscernible] we wouldn't expect to have to call a lot of those risk management products. So, on a dollar per megawatt hour basis, it is relatively high. That will average down if we do have to call some of those mitigations.

Next question just around [indiscernible] it's not fully commissioned, it's been operating for about 2 months now. What's actually left to do on and how far away?

So it's been operating remarkably reliably -- what there's some minor pipe work changes to be put in place towards the end of March, early April. And then that will be it. It's just a matter of prudence that if you declare it fully commissioned, then the EPC contractor is effectively finished and there's clearly work to do. So, it's more a nuance of the technicality of the contract that we are continuing to obviously to generate. We are generating at or above the capacity of 51.4 megawatts. That's great. But there's a little bit of work still to do, and we fully expect that to be completed by, let's say, mid-April. [indiscernible] We are in discussion that officially starts with the formal completion of commercial handover, but we are in discussions with Microsoft about early delivery of the renewable energy certificates that have been generated to date.

And last question for me. I just noted in the slides you're talking about Fast-track fixability. Does that -- storage flexibility or is that actually future potential?

It's a range. So, it's accessing the what's currently called contingent storage, the 2 meters in hardware, potentially getting some access to -- in the extreme dry years to -- there's a further 6 meters that's been used in the '70s as truly contingent for the transition. It's also about getting increased flexibility on the flows down the Clutha. There's a number of quite stringent obligations on minimum flows, which were probably appropriate 20 years ago, but for the transition are probably not appropriate. And if we want to solve that problem of very high evening and morning peak prices, I think that's part of the solution. We see that as being really important. We have an incredible resource here in this country in hydro. And we have given away a lot as an industry over the last 30 years in individual resource consents. And quite frankly, that generation needs to be made available to the country again to get us through this transition.

More question from the room. Nevill Gluyas?

Good morning. Thanks. A few for me. First one, just on the long-run price view. You have reiterated the $115 to $125.

Real terms '24.

Right. But you have [indiscernible] but there's a bit of commentary just brief note in there about seeing structural pressure on cost of new wind farms which was in business in the latter half of this most recent year, they've gone up by maybe EUR 200,000 per megawatt, and it looks like that's what they think might be. That would suggest another $10 a megawatt hour pressure. Any reason to revisit your long-run view? Do you think that might change your view or do you still think that long run view is encapsulated even with that change?

I would say it's a dynamic situation. The long-run view is predicated on more wind being built out. I think what we're seeing because of the consenting regimes is that it's easier to build solar, and we are seeing much more solar come to market. So, we are considering whether we need to update our thinking around our long-term pricing to reflect the proportion of new generation from solar and potentially more batteries than we ever imagined as part of our investment thesis. I think as regards to the sort of current pricing we've seen on wind projects, I think we'd say our Southland Wind project is at scale. And I think you're going to need scale projects to be able to hit that target. The smaller projects that we're seeing come through are probably not going to do that.

And just on the sort of the short run kind of issues [indiscernible] are there other options on the table that the industry and you are involved with -- you can talk about? The HFO discussions, do they encompass potential actions this year or are they...

It's fair to say that there are existing HFO and what was the -- MSO obligations already in place, which I think will take care of this winter. I think you've also got to recognize that there's Tauhara and Te Huka 3 will be online for the winter. That's an additional 220 to 225 megawatts, just quietly chugging away there in the background. There are other potential gas supply options that we're investigating. And as we said, we've actually shifted our shutdown schedule around, so bringing Ohaaki into May so that the 34 megawatts is available over that down July, and August period. So it's never A, B, or C, it's D, all of the above.

And in the long run, obviously, you've got frontier review happening in quite short order. They're not familiar with our market, hydrothermal issues, or a different market. What do you think the odds are you come up with sort of an industry solution as opposed to a mandated regulatory government solution securing supply beyond this year?

At the end of the day, it will always be an industry solution. It has to be an industry solution. And that's the whole dynamic of energy markets, whatever type of market is that ultimately, the markets will provide that solution. And where governments have intervened the experience overseas has that's never been a very happy ending. It's always led to even more turmoil and even more disruption. And whatever form of energy you're talking about there, it never ends happily. And so the industry has a duty of care to step into that space and provide a solution around the security of supply. Having said that, it's also really important, that the best cure for security of supply issues is further investment in reliable renewable generation, which is geothermal and firmed wind and solar. And so whatever can encourage and support that investment, that's the appropriate direction of travel.

I think if you just go back a few years, we talked in industrial about demand response, even Tiwai. Even other industrials, they always put production above the cost of new electricity generation. And that conversation we're now having with our industrial customers about the demand response is a much more mature conversation. They're seeing the benefits in their own operations of having lower prices but retaining the value from those demand response periods. And it's just a much more constructive conversation we're having with them. And if we bring our technology around demand response to simply energy, it's a fantastic outcome for New Zealand. We'll get more people on to electricity. We've been talking about demand for 10 years. And now we're seeing people switch from gas to electricity. So it's really cool.

Segue into 2 additional questions. One is of Fonterra deals have that built-in [indiscernible] demand response built in as well as [indiscernible].

The beauty of those deals is that they are summer-weighted. There is no demand response per se built in, but the summer weighting just means that they are absolutely perfect to be lined up with solar development.

And last [ bit of ] question. Would you contemplate the possibility of [indiscernible] of the general structure [indiscernible] which will be a great site for diesel generation [indiscernible] in the industry? Would you be interested in such?

We're open to looking at all options in the going forward. That's why, as an industry, we looked at the strategic energy reserve at Huntly going forward. And yes, there are options at, say, Marsden Point where they have significant diesel storage. Remembering diesel is a much more expensive option than other options available to the market. And hopefully, for the sake of ordinary Kiwi households, we can explore those other options to their fullest extent before we talk about diesel.

Our focus is more on delivering battery solutions. I think if you go back, we would have said 500 megawatts of batteries is a reasonable amount. With the decline in natural gas, there's such a larger -- there's a much larger market for us to invest in. We think about $100 million paid for that methane gas, which was burned over a period of 4 months versus $150 million for a battery that can last for 20 years, you can see where our focus is going to be.

Thank you, Neville. So we'll move now to questions online. [Operator Instructions] Grant Swanepoel from Jarden, please remove yourself from mute and ask your questions.

Can you just repeat, I know it was Andrew's question, but it was breaking up on the feed. The $770 million going to $790 million, is that after taking off $20 million from the Manawa deal? So actually would been $810 million?

No. The $790 million versus the $770 million is on the same basis as we gave at the beginning of the financial year, which did not include the expectations of costs around Manawa. So as Mike mentioned, we expect to spend around $20 million this financial year on Manawa. So the reported EBITDAF will be $790 million less than if this comes to fruition.

And now talking about another Methanex deal, but your gas book showed 8 PJs of gas in storage as well as contracted and almost 350, 400 gigawatt hours of thermal production ahead of a normalized period as well as a hockey in place. Why would you even approach Methanex when you guys seem to be quite well-orientated for a dry winter?

So you've got to remember of that, I think you're talking the 4.2 PJ of gas, which will come out at blowdown, and we had 3.4, 3.5 PJs of accessible gas, which I think is sitting at about 3.1 PJs now. And we have a contracted supply with obviously with OMV. But that contract is for 4.5 PJ annually. Remember, our annual demand last year was in the order of 12 to 14. So yes, Tauhara and Te Huka 3 have stepped into that space. But if the market needs it, then we're going to have to go out and get more gas.

Yes. Grant, we know that TCC is a large unit. And so therefore, we'll be looking to supply others in the market that don't have some of those risk mitigants that we have and making sure we sell through the winter.

Okay. So what I'm hearing is Contact doesn't need it, but the market might need it and you can supply it… It's not a risk that's Contact's sitting with. So, therefore, you're not going [ into the mix ] in a position of [indiscernible] like last year.

No.

Fantastic. Then your $0.02 uplift in dividend. This year, you had to really push the $0.39 of last year's dividend up. You talked about how once the Manawa deal had been settled in, you'd be adding to dividends. So what are we looking at dividends for this year, $0.41 plus, or where we're going with this one?

No. As we mentioned, we haven't changed tack on that grant. We said that the dividends were targeted at $0.39 per share. That's up from $0.37 last year and $0.35 the year before. Absent the Manawa transaction, dividends will be flat until FY '27 when the Te Mihi station is substantially complete. And then we'll think about changes to the dividend based on Manawa once we get the keys.

And then my last question is just on the Tauhara takedown in FY '26. How many days have you penciled into that geothermal pullback before we get to the 174 steady state?

We're at effectively 170, 174 now if -- the team has done a cracking job there. There's a little bit more well optimization that we have to do. And so the once – the October shutdown next year... 3 weeks. It's 4 weeks. It's a 4-week shutdown this calendar year, next financial year, right? But that's more about the statutory inspection. There is a couple of few remedial works we've got to do as is normally the case, but it looks like the team have got a clear path to 170 to 174 already, and you've seen that in the generation stats to date.

Yes. Grant, you'll see a new disclosure on Slide 39. We've got the Tauhara outage of 118 gigawatt hours. Te Huka 3 will come down, as Mike mentioned, to finish those commissioning activities we format. And so those are the sort of 2 commissioning outages that are impacting geothermal generation expectations.

Thanks for asking those questions and particularly to Matt for his maiden result -- well done well.

Thanks, Grant. And we will move to Cameron Parker from Craigs.

Just a couple for me. Just thinking about your role with the supporting the Huntly ranking unit that's coming off and how you're thinking about that with regards to sweating your assets on your last TCC and also Stratford Peakers and so forth? Just wondering if you can elaborate on that.

So TCC, we've extended the hours a number of times, and we really are at the last extension of ours, and that is a well-sweated asset, which deserves to retire at the end of the year for a job incredibly well done. We remain very committed to those Peakers. We continue to refurbish the engines. And with the revised operating regime, we're hopefully seeing the start of a much more reliable period with them. But we see them, remember, as peaking in support of the shoulder period. So we see batteries providing the shape over intraday and doing that very easily. And the great thing about batteries is obviously, they're powered by a multiple set of fuels, whether it's solar, wind, hydro, geothermal. The Peakers we see is providing cover for the shoulder periods. And so that strategic energy reserve at Huntly it is about the dry years and sort of they quarterly the dry periods in the quarter at a minimum. And so, it's actually quite a neat portfolio fit there. Longer term, this year is different. We've got TCC potentially there. But longer term, you've got intraday batteries providing the shaping each day. On the shoulder periods, you've got the Peakers providing into week, into month. And there for those really dry years, you've got that strategic energy reserve of Huntly.

Great. And just following on from that just you alluded to your LNG conversations earlier in the presentation. Just wondering if you -- do you have an indication of landed cost and backup that might -- if a project was to progress, what that's looking like at the moment and what sort of options could be possible? Or are they..

And this is important. So, on LNG, both the industry commission study and our own observations. So, we sent a group of managers, senior executives and Board members up to the Middle East last November. And the thing about LNG is the sheer scale that you're talking about. One of those floating storage regasification units standard size is 800 TJs a day, which is sort of 4x our daily demand. And that's one. And so, the scale and the investment required, I think, from the study was in the order of $1 billion for the whole industry. And so, the standardized technology wasn't going to work for the New Zealand market and the New Zealand market requirements. Now as an industry, we've commissioned further study, is there a fit for purpose, a fit-for-size option available. But that's still going to be two to four years away by the time you get through deciding you're going to do it, taking FID, getting the various parties contracted up and then actually building it as infrastructure. And so, we'll investigate that. But what's important in the meantime, four years is a long time. We have to get that security of supply now, which is why the strategic energy reserve at Huntly while keeping that all three rankings available to the market, keeping our peaking capacity, making sure Ahuroa's working well, all those other options available to industry as well as continuing to invest in geothermal and other renewables. All those other things are critically important in these coming years.

Okay. And just the last one for me. Just concerning the Manawa Com Com kind of response that you'll be making, what are the key messages you want to send back they obviously had some concerns around third-party hedging and so forth and the potential lessening of competition there. I don't know whether you're able to talk to that or not.

Look, I think what's important at this stage is to respect what the Com Com are doing. They are doing their job. They are investigating every market segment to a high degree of rigor. And so, they've raised a number of questions, and we'll obviously be answering those questions in full. We still believe that the deal is the right thing for New Zealand, for the New Zealand consumer that the ability to provide additional energy into the system ultimately will lower prices. We still believe that the quantitative analysis and the facts will support that. Remember, our electricity market is one of the most quantitatively analyzed both in terms of any market here in New Zealand, but also in terms of the globe. And so, there's plenty of facts and data to back the analysis and to make sure we all arrive at a common conclusion, but we still believe this is the right deal for New Zealand.

And we'll move to Vignesh Nair from UBS.

A lot of questions have been asked. So, I've just got a fairly quick and easy one. I suppose just going on that Fonterra deal from last week, I suppose what's Contact's appetite for more boiler conversion deals? And the sort of -- what's the kind of size you're aiming for? And the reason I'm asking that question is, if you go forward, I suppose, 4 years without getting too in the details, I've sort of got maybe 750 gigawatt hours worth of additional supply, including both Glorit and Stratford and the 3 projects you've announced. And so, backing out Fonterra and New Zealand Steel, you're sort of only sitting at maybe 100 gigawatt hours worth of additional generation. So, it feels like if you want more Fonterra style deals, you'll need to bring wind to market. Is that a fair assumption?

Yes, that's a very fair assumption, and that's the whole dynamic is that we haven't just been developing a geothermal pipeline where you can see a decade of work in front of us. We also have a solar pipeline, which, as you rightly say, has about 0.9 terawatt hours. But Southland Wind in and of itself at full capacity is worth about over a terawatt hour a year. And so, if we can match those industrial conversions with new development, that's the sweet spot. And so yes, absolutely, we've got to make sure that those go in step with each other, absolute lockstep.

I just want to say, Vignesh, one of the transaction rationales for the Manawa acquisition is the development of their development pipeline as well. Now we believe that we've been the most forward thinking in bringing new investments to market. We've got the best balance sheet settings to apply capital to these. So, we think that those investment options will continue to help us support those industrials going forward.

Okay. That's very clear. And just quickly, an update on Tauhara 2.0, the additional 70 megawatts. I feel like that's the lowest hanging fruit.

Tauhara South. Yes. The team has started to look at the options around that. And that's in terms of -- it will be the last development on the Tauhara field. And so, it's important we get that right. But certainly, we are looking at the option both in terms of its size and what the offtake will be for it. So actively looking at it.

So in terms of water operations, it feels like solar than wind than Tauhara 2?

Continuing with solar. Tauhara South will be what it will be, that will progress. And wind, we will -- if we're going to do wind, it will probably be in an off-balance sheet type arrangement SPV and be linked to demand conversion.

And we'll take questions from one more online participant, Stephen Hudson from Macquarie.

Just a couple from me. Just on the Glorit and Stratford solar projects, could you give us some clues as to how the economics of those two projects are looking? And maybe if you can relate that to Kowhai Park?

Yes. So, we see very similar economics to Kowhai Park. Notwithstanding a slight drop in the exchange rate since Kowhai Park was announced, but the nonrecourse project finance obviously provides a bit of a kicker there as well. And so, correcting for exchange rate, they are of the same order of magnitude. They have -- obviously, in the case of Stratford, they have a connection readily available there. Yes, we're looking forward to -- and the thing about Glorit like Kowhai Park, it's very close to demand. And so, location factor starts to play out there. So we're very confident in the economics of both those projects, both very similar sizes, 0.3 terawatt hours net output per annum.

Yes. Stephen, I'd just like to add they're really great economics, but they've all got different characteristics and they're good for different reasons. Obviously, the Stratford site has got access to the network, the grid because of our existing assets there, and Glorit from a location perspective is closer to Auckland. So while there's sort of idiosyncrasies in every one of the projects, they're all looking very favorable when you consider the forward view for prices.

That makes sense. Just starting around, you mentioned the capital bond issuance and your equity recognition there. Just can you just remind us, Matt, just the capacity for further issuance in that space?

Yes. So we have the ability to issue up to about $900 million of capital bonds at this stage, and we've got the 2 capital bonds outstanding. So that's the $225 million bond and a $250 million bond. So we do have some reasonable headroom there.

So you're about half capped out.

Yes.

And then just on the FY '26 normalized guidance, useful as always. Can you just point us in the direction -- right direction around, I suppose, some of the quirks to that page? And I'm thinking here, you've had quite a change in the gas cost assumption. We've got quite a large network and transmission step-up to think about. So I'm kind of thinking we might have to normalize the normalized number for pass-through to the fixed price channel. So it'd be just super useful if you can give us a feel for how we should think about that.

Yes. I think what you would have noticed over the last number of years is our allocation of sales to the strategic fixed price channel has increased materially. If you go back to 2018, we only sold about 1,000 gigawatt hours per year into that long-term channel, and we're forecasting to sell over 2.4 terawatt hours. So that reflects all the work we've been doing with those industrials to get long-term PPAs, inflation-linked to help them decarbonize the market. So I guess that's a really key change to the portfolio composition. I think in the retail space, with those large changes to the lines costs, eking out increases to the energy costs is going to be a bit more moderate than we've previously expected, but still positive, helping us get integrated energy margins up to an appropriate level, reflecting the long-run costs of electricity. The thermal and acquired generation just reflects the cost that we're paying for that long-term gas, and remember, that's just the short run cost of that fuel. And the cost for gas storage and OpEx associated with the plant is in those fixed operating cost lines.

And you called out the geothermal outages. You've usually given a lot more disclosure there. I think there's about 170 gigs that year and then it actually steps up in FY '27. So should we actually normalize for that? Or is that just an ongoing?

No. Every new plant is required within 10 to 14 months of starting after shutdown for a statutory inspection. So that hopefully won't have a repeat. So you saw the same with Te Mihi, where we took a 1-year shutdown, 1 year after startup. And then last year, we took the 10-year shutdown, which was the biggie. And so going forward, to Te Mihi 2A will have a 1-year outage. But by then Tauhara and Te Huka 3 should be running and just running at that point.

Yes. So you're right. The geothermal generation of 5 terawatt hours is 200 gigs below our expected average due to those large outages.

Thanks, Stephen. So that's the end of our question session. So we're able to close the meeting. Over to you Mike.

No. And just thank you all for coming on. It's fair to say it's been an incredibly busy 6 months. It's 6 months I'm incredibly proud of in terms of what the company has delivered, both in terms of the bottom-line financial result, but also that underlying operational and safety performance, the maintenance of continued assets, the continued delivery to ordinary Kiwi homes and the delivery of those projects, which both contribute hugely to both security of supply in this country and to the decarbonization of the overall economy. The government have emphasized the need for growth. And I think you have in Contact Energy what growth and delivery and investment and innovation actually looked like for the rest of the country. Thank you.