Genesis Energy Limited (GNE) Earnings Call Transcript & Summary

Kia ora, and welcome to Genesis Energy's FY '24 Results Presentation. I'm Malcolm Johns, Chief Executive; and I'm joined by Emma Oettli, our Interim CFO. FY '24 was challenging, but we're delivering our strategy. We were challenged by hydrology, major unplanned outages, and New Zealand's gas shortage. However, the portfolio showed its resilience with earnings down but defended. We delivered all the Gen35 strategic objectives we said we would in FY '24. Retail reset, Ford OpEx growth arrested, more renewables, HFOs and the Stage 1 battery at Huntly Power Station. What was already clear to us, but became clear to everybody in 2024, was that energy security is essential, even in a high renewables grid. Under current strategy, Genesis can move another 500 megawatts of baseload generation to flexible generation at Huntly Power Station and make it available for energy security by FY '28. Executing our strategy is the fastest and most economic way for New Zealand to deliver greater energy security for winter peaks and dry years with low wind. I will speak more about this later in the presentation. Before we get to our results, I think it's important to discuss the recent market conditions and the steps that Genesis has taken to play our part through a challenging time when Mother Nature failed to show up. New Zealand has always had dry years, but the swing between wet and dry appears to be becoming more frequent. The impact of this dry year has been exacerbated by large swings in wind generation. Natural gas fields are declining faster than forecast and New Zealand is now structurally gas short. The result is more volatile electricity prices, especially at the short and long ends of the range. However, the current market structure meant 99.99% of Genesis customers were on fixed price contracts and were shielded from this winter's volatility. Genesis has been raising energy security as an issue for some time. We all want a high renewables grid. However, the more wind and solar, we put into the grid without also putting in place adequate capacity and energy reserves, the more volatile energy security and prices will become in the future. Electricity volatility indices are rising. And there can't be a free ride for any type of renewables generator when it comes to carrying a fair share of energy security costs. FY '25 was challenging, but we are delivering. So let's look at some of FY '24's highlights. Briefly running through our agenda for today, we'll first look back at our achievements during Horizon 1 of Gen34 in FY '24. We'll then go through our financial performance before looking ahead to Horizon 2 and out to FY '28. We'll finish off with guidance and time for questions. Turning to what we see as the most important achievements of the past 12 months for our impact on people, planet and profit. For people, customers grew 2.7% in the year demonstrating Genesis's strong stable of brands, including Genesis and Frank. It is worth noting that Genesis holds a majority interest in Ecotricity, whose customers are not currently included in these numbers. We delivered on the first stages of moving to a lower cost, lighter touch retail model, focused on value share over volume share. At the same time, we invested in growing our teams across renewables development, trading and fuels to reflect the needs of maintaining strategic delivery. Through the changes, we saw our employee engagement remain strong, 6% above New Zealand's benchmark. Looking now at achievements under our planet pillar. We were pleased to reach financial close for the Lauriston Solar Farm, New Zealand's first project finance solar development, alongside our partners FRV. Construction is well underway, and we expect to have the first megawatt flowing by the end of 2024. We have reached FID on Stage 1 of the Huntly Battery Program, with our first battery now confirmed, supplied by Saft. The Huntly site has many great attributes. Our team ran a detailed procurement process and this will be New Zealand's lowest cost 100 megawatt battery to date. Our progress towards 500 megawatts of solar continued. Last week, we confirmed the acquisition of an advanced stage asset at Edgecumbe in the Bay of Plenty, one of the sunniest parts of New Zealand. The opportunity is expected to provide 127 megawatts of capacity. We plan to have it generating within 24 months. Speaking to our third pillar, profit, we are, of course, comparing our results this year against a year of record hydrology in FY '23. EBITDAF was $407 million, down 22% on FY '23. NPAT was also down to $130 million. Genesis continued to provide market-leading yields with a strong dividend. As previously guided, we paid $0.14 per share over the year. That's the challenging part. Now, for what we delivered on strategically. Looking at our retail and technology business units, we started on our pathway to a low cost, light touch retail model. We moved away from extensive in-house technology development, resulting in a reduction of 130 FTEs in our core retail and technology teams. We remained on track to operate retail with 200 fewer FTE by FY '26. Key to this is our billing platform upgrade. This is on track and we're planning for a late FY '25 go-live across our Frank brand and full implementation across all brands by end of FY '27. We have tooled up and begun delivering strategy outcomes in our wholesale business. We have materially increased our development team, adding experience, battery, solar, wind and project delivery resources. This team has delivered Lauriston and Edgecumbe solar opportunities quickly and reached FID on the Huntly Stage 1 battery while also expanding our pipeline of opportunities for future development. We created a new senior leadership position of GM Fuels to bring a more future focused fuel development and security approach, critical to our Huntly portfolio plans. Being able to store energy from a minute through to a month is an essential element of how Huntly will provide 1,400 megawatts of energy security in a high renewables grid by FY '35. We welcomed a new GM portfolio to lead how we position our overall portfolio to maximize our group gross margin outcomes. I'm pleased to say that Emma will be taking up the role of GM portfolio in November. Emma has deep experience in both the retail and wholesale sides of the business and will bring an energized and aggressively commercial focus to how we deliver more value from our portfolio. We also welcomed a new GM trading who is laser focused on how we will monetize the portfolio plan Emma will drive. Now, onto our retail business in more detail. FY '24 was hard change delivered well. We had a strong year of delivery and retail, adding customers, restructuring the business, fare welling 130 team members, while maintaining staff engagement and growing customer satisfaction. We drove improved net back in all segments across electricity and gas. We delivered high satisfaction scores with increases in both Genesis and Frank's Net Promoter scores, and we're proud that Frank once again won the Consumer People's Choice Award. Turning to our wholesale performance, it was Rankine's to the rescue. FY '24 was a challenging year for our wholesale business, and the contrast to FY '23 could not be greater. We came into the year with wet conditions, lakes full, all the gas we needed and all plant running. We ended the year with dry conditions, lakes low, a short gas market and impactful unplanned outages in Units 5 and 2. Rankine's generated 1.9 terawatt hours, protecting us from the spot market throughout. Despite the conveyor belt of challenges, we were able to back our customer position with our own generation assets throughout FY '24, showing the resilience of the Genesis generation portfolio and our team. The fuel dynamics in the market significantly changed, where gas prices sharply increased and coal prices stabilized. Gas started as the thermal fuel of choice, but coal finished the year as the cheaper generation option. Now looking at generation, where great people and great assets delivered great resilience. It was a busy year for our generation team, with the unplanned repair of Unit 5 requiring a huge commitment of time and energy. The fact the team returned the Unit to service 4 months earlier than expected is a credit to their efforts. Alongside those on the tools, we had a great outcome on the Unit 5 insurance process. It was concluded within the financial year and with a $29 million settlement. In mid-winter, the Huntly team also completed critical unplanned works on the Reserve Rankine Unit 2. They undertook what was essentially an organ transplant to move the intermediate pressure turbine from the retired Unit 3 into Unit 2, when Unit 2's turbine suffered a fault. This was the heaviest crane lift at Huntly since construction and led to Unit 2 now being affectionately known as Rankinestein. We also completed the multi-year program to replace all 3 turbines at the Tuai Power Station in Waikaremoana, increasing their efficiency. Turning now to our people, where great people in a great culture delivered real change. As we indicated earlier, FY '24 was a year of major structural change, and I want to thank all our team for their professionalism in working through this process with us. This was one of the best change processes I have seen in my career, and I want to call out our exec and senior leaders for this. To deliver that level of change, encounter no disputes, and have engagement outcomes remain above the national benchmark is simply outstanding. This year, we made excellent progress towards our safety and wellness objectives. We continue to see a significant reduction in injury severity with the total number of lost and restricted days due to injury reduced by 42% compared to FY '23. Our ongoing LPG injury reduction program, maintained its momentum with a 31% reduction in the LPG injury rate since the program launched in FY '22. Our focus on safety over delivery has helped achieve this outstanding result, and we plan to continue improving safety for our LPG team, ensuring this challenging physical work is done in a way our people come home safe at night. Our people finished FY 2024 with a delivery mindset, confidence and momentum to launch into the next 4-year horizon of Gen35. Moving to Sustainability, where less gas equals more coal, until we have biomass. We said last year it was very wet, that Mother Nature can have effects beyond our control, including the amount of thermal generation required by the system. So we were cautious when our carbon emissions in FY '23 were within our science-based targets. As has proven to be the case, Mother Nature again delivered conditions outside our control in FY '24 and we saw emissions increase as a result. We have always said that, if the bottom line is the lights must stay on, then less gas will mean more coal for some years to come. With coal now producing cheaper electricity than gas and gas being structurally short in New Zealand, we will need to burn more coal for energy security than we planned, and we won't meet our FY '25 science-based targets. We're working as hard as we can to establish competitive domestic biomass supply options that will displace coal. This will bring emissions back on track by FY '28 based on P50 hydro. Delivering Gen35 means we will be net zero by 2040 across all scopes. I will now pass over to Emma to provide further detail on our financial performance. I'll speak to our strategic outlook later.

Thank you, Malcolm, and good morning, everyone. Thank you for joining us. I'll now talk through our FY '24 performance starting on Slide 12. While most metrics are down in comparison to FY '23, we need to remember that FY '23 was a record year. High inflows resulted in 1,000- gigawatt hour more renewable generation and a much lower need for expensive thermal. As Malcolm said earlier, this year's results were impacted by lower hydro, gas market conditions and the Unit 5 outage. Looking at the numbers. Revenue was up 28% driven by higher wholesale prices and momentum across our retail business, especially in C&I. GWAP was up from $95 per megawatt hour to $188 per megawatt hour, reflecting the higher spot prices. Gross margin, however, was down 10% due to significantly higher generation costs relative to the very wet prior year. I'll talk to the details of this, plus gross margin from gas, LPG and Kupe on the next slide. Operating costs were up 10%, which is higher than inflation, but consistent with the plan we set out in November. We're making a concerted effort to focus spend on strategically aligned areas, such as digital projects and wholesale. We announced some significant changes in our retail business earlier this year, which were implemented over the last 6 months. We will see the full year impact of these reduced costs in FY '25. Lower gross margin and higher operating costs resulted in lower EBITDAF, which is 22% down on the prior year. The factors that drove this were mostly beyond our control. But we're mindful that as a business we must play the cards we adapt and adapt our business through changing conditions. This also meant NPAT was lower and I'll go into more details on a later slide. Capital expenditure increased by $63 million, primarily due to expenditure on KS-9 and investment in our Hydro assets at Tuai and Rangipo. And lastly, the Board declared a final dividend in line with guidance of $0.07 per share. This brings our dividends for the year to $0.14 per share. Genesis continues to yield around 9%. Turning to Slide 13, we look at the gross margin drivers in more detail. While we operate the business in segments, looking at product types is a good way to understand the detail. Firstly, let's review electricity, the largest component of gross margin. This was down from a record $670 million to $560 million, driven by the change in generation mix relative to the very wet prior year. Our portfolio generation cost, that is the fuel and carbon cost of generation, divided by total generation volumes was higher at $63 per megawatt hour. That's an 80% increase on the prior year. Lower hydro generation was the key driver of this, down 1,000 gigawatt hours, which is almost 1/3 of our hydro generation. We also had significantly lower generation from Huntly Unit 5 due to the unit's outage in the first half and challenging gas market conditions in the second. On the sales side, retail growth was positive, both in volume and price across all 3 channels. C&I sales price, which is most closely linked to wholesale prices, increased by 16%, while residential and small business were largely insulated from the wholesale market with around a 3% increase in sales price. The final component is derivative settlements, which represents trading activity and other long-term contracts. Derivatives saw a net gain of $20 million in FY '24 versus $41 million in the prior year. There are more details on this on Slide 35. Next, at the top right of the presentation, we show Kupe gross margin. This is down from $91 million to $65 million. However, there is a $6 million price adjustment in the prior year that related to the FY '22 LPG transfer price. Once this has been adjusted for, the year-on-year decrease is $20 million. Production was down 17% as a result of a planned 4-yearly outage, which coincided with the drilling program and ongoing field decline. Having less gas is a key driver of performance in the Kupe segment and wholesale generation costs. Turning to LPG, around half of the year-on-year movement relates to strong pricing momentum across all retail segments. The remaining movement relates to the additional costs in FY '23 from Kupe as discussed. Finally, the bottom right-hand graph shows gas gross margin. We continue to focus on value over volume, maintaining gas in our retail channels with less available for wholesale. We expect to see continued stress in the New Zealand gas market and elevated gas prices in the short to medium term. Not shown in these charts is the insurance settlement from the Unit 5 outage. We're pleased to have concluded this process and all insurers have agreed to the full and final claim. Insurance proceeds of $29 million are included in other revenue, and the net impact is a $7 million reduction in FY '24 EBITDAF. Now, looking at operating expenditure on Slide 14. As we said in November, operating expenditure is a focus for Genesis. We're investing our shareholders' money in areas that drive long-term value and are committed to keeping within our Gen35 operating cost envelope. We've previously signaled higher OpEx in FY '24 and '25 as we invest in digital projects and renewable growth opportunities, and then a decline through to FY '28. Looking at the key drivers. Retail costs increased primarily due to wage inflation, lower capitalization and costs associated with the new target operating model. We have completed the first stage of the organizational changes and expect lower costs in FY '25, which reflect the full year impact of these changes and delivery of the target operating model. Our technology costs increased slightly due to software inflation. Corporate spend was flat year-on-year and we expect this to continue into FY '25. The increase you can see in FY '25 relates to a Gen35 acceleration fund. Wholesale costs increased in line with expectations. As Malcolm has already spoken to, we invested in our asset development, trading and fuels teams, 3 key capabilities to deliver Gen35. This also includes a $3.5 million one-off cost associated with the Unit 5 outage. Momentum increased across our technology investment program. The billing and CRM platform moved into implementation. The general ledger upgrade is at final vendor selection and the trading and risk platform at RFP. This program is a significant investment and will return value through risk management, productivity and training. Digital project costs will be higher in the near term and reduce as the program winds up by FY '28. Turning now to look briefly at NPAT on Slide 15. NPAT is down from a high in FY '23. The key drivers we have already discussed are lower gross margin, higher costs and therefore lower EBITDAF. Elevated wholesale prices resulted in a significant increase in the fair value of our PPAs. An assessment of the Kupe reserves has been completed. P1 and P2 reserves have been revised down by 81.2 petajoules equivalent and a corresponding impairment of $64 million is included in this year's results. With that, we'll move on to capital expenditure on Slide 16. Genesis committed significant capital expenditure in FY '24 and plans to continue this investment in FY '25. Looking first at FY '24, our stay-in-business CapEx was $79 million for investment in our generation assets. Significant scheduled works at Huntly Unit 5 were undertaken during the plant outage. This included the repair of the failed circuit breaker and the purchase of a spare. We completed a 7-year project upgrading our Tuai hydro power station, with the last of the 3 new generators installed and switched on. The upgrade has improved the station's efficiency by 1.7% and will potentially boost Tuai's capacity by 6 megawatts. At Rangipo Power Station and our Tongariro Power Scheme, we completed the refurbishment of 1 of the 2 turbines, its generator and the Rangipo intake gate. Similar work will occur in FY '25 on the remaining generator unit, ensuring the station continues to deliver a high level of reliability. The main growth item was our share in the KS-9 drilling campaign. The outcome was disappointing, but there is always an element of risk in these campaigns. While we are still firmly of the view that the decision to back Beach's intervention was the correct one and the right processes were followed, it's an outcome that is unfortunate for the electricity market and Genesis shareholders alike. There remains some potential for KS-9 and the JV will consider options for the well over the summer period. The KS-9 outcome reinforces the importance of Gen35 and Genesis remains committed to directing our share of Kupe's free cash flow to new renewables. The amount from Kupe may be less than first anticipated, but we will explore more purchase power agreements and joint ventures with PPAs in addition to direct investment to deliver our renewables pipeline. The KS-9 outcome has not changed our dividend policy. In FY '25, we continue with our plan, deploying capital to build flexibility, grow our renewables portfolio and invest in our existing assets. Stage 1 of our Huntly Battery project will commence in FY '25, having just reached FID. Of the total cost of approximately $150 million, around $60 million will be spent in FY '25. We continue to invest in associates to complete the Lauriston solar farm, as well as ongoing investment in forestry. Growth investment also includes costs relating to acquiring this Edgecumbe solar opportunity, which Malcolm will speak to later. Now let's look at net debt and funding on Slide 17. The net debt to EBITDAF ratio increased to 2.7x, which remains below 3x, but is higher than our target of 2.5x. The key driver for the year-on-year movement was the reduction in EBITDAF, which I've already discussed in detail. Debt was $60 million lower. What we can see in this year's numbers is the working capital impact of the declining stockpile. The stockpile started the year at 961 kt and finished at 231 kt. We intend to maintain the stockpile at around 350 kt. The cost of our funding increased to 5.7% due to higher interest rates on variable debt and new fixed debt as it was secured, in line with wholesale market rates over the past year. As we said in November, we intend to invest $1.1 billion in strategically aligned assets. The expected earnings growth of these investments will ensure that our balance sheet remains strong. With Kupe free cash flow reduced, this will put some pressure on these settings, more so from a timing perspective, with investment ahead of cash inflows. In the short to medium-term, the debt-to-EBITDAF metric will remain above 2.5x, and this has been reflected in the FY '28 scorecard. I'll hand you back to Malcolm to discuss our strategic outlook.

Thank you, Emma. Having delivered Horizon 1, we are now moving into Horizon 2 of Gen35. I'd like to introduce you to our 8 by '28 for growth and security, reaching EBITDAF of around mid-$500 million by FY '28 will require us delivering the 8 strategic objectives shown on this slide. This is our 8 by '28. Delivering our 8 by '28 will also move up to 500 megawatts of baseload generation at Huntly into flexible generation, which we can sell into the energy security market. This is the fastest way for New Zealand to deliver energy security options to the market in the next 4 years. 8 by '28 delivers growth and energy security. We are also turning our minds to how we maximize outcomes from our portfolio by focusing on value share over volume share. As I mentioned at the start, we have created a new critical leadership position, GM Portfolio, and Emma will take up this role in November. Emma's focus will be maximizing gross margin growth and earnings resilience within a proactive approach to portfolio strategy. Genesis's portfolio is often seen through an earnings defense lens. We believe there are gross margin growth opportunities available within our existing portfolio by focusing on value share over volume share across both existing and future value pools. We expect to see our mass market position move notionally inside our renewables energy envelope. This will happen alongside the development of a lower cost, lighter touch retail model that will focus on hyper-segmentation using new technology and AI to prioritize value over volume objectives. As that occurs, we will see greater length come into Huntly and we will trade that with more intent. Genesis holds a majority position in Ecotricity. And we have included Ecotricity's demand in this portfolio graph with Genesis and Frank. Ecotricity has quietly built the largest rooftop solar share of any retailer in New Zealand, with around 30% share of market of installed rooftop solar across the country. And about 80 megawatt hours of battery within its customer base. Ecotricity's demand-side flex and VPP capability is building nicely and is now delivering meaningful megawatts of demand-side flex from customer batteries across New Zealand. Along with a more proactive portfolio management approach, we will also accelerate our delivery of new renewables. Our pipeline of opportunities continues to grow as our expanded development team pursues opportunities to partner, purchase and develop. We're focused on deepening and broadening our opportunities across owned assets, JVs with PPAs and pure PPAs, with a focus on converting braggawatts into megawatts. We are delivering proof points on why Genesis is uniquely placed to partner or purchase opportunities and push them through FID to deliver new renewables. Our new Edgecumbe Solar Farm development is a great example of this and of how we're monetizing sunshine. As announced last week, we've signed an agreement with Helios for the purchase on an advanced stage 127 megawatts solar farm in one of the sunniest parts of the country, near Edgecumbe in the Bay of Plenty. This will be one of New Zealand's largest solar projects, and while ambitious, we plan to have it through FID within 12 months. It's a large project of over 200 hectares and we've estimated its capacity at 127 megawatts peak or DC with annual generation of around 230 gigawatt hours. The higher sunshine yields in the area means the capacity factor will be over 20%. The economy of scale supports the economics, and we're estimating a build cost of around $1.7 million per megawatt. A key pillar of our portfolio strategy is flexibility, creating value by time-shifting energy to secure the grid from a minute to a month. The perfect partner to our solar farms will be our battery storage system with Stage 1 at Huntly Power Station. We are pleased to announce today that we have reached FID on Stage 1 of the Huntly Battery, a 100-megawatt unit providing 200-megawatt hours of storage. This is the first stage of a 400-megawatt battery system we plan to develop as part of the Huntly portfolio. As we have said before, Huntly is ideally suited to batteries with available land, direct access to the grid and located close to New Zealand's electricity demand centers. These factors, alongside the work our team did procuring battery equipment at competitive terms, means we've been able to deliver the lowest cost 100-megawatt battery so far in New Zealand. We're partnering with SAFT, who already have on-the-ground experience in this country. We expect the total cost of around $150 million with around $60 million allocated in FY '25. Commercial operations are due to commence from around mid-2026. The revenue we get from batteries is complex, but we've tried to break it down to outline how Genesis will deliver value. Batteries serve the minutes and hours end of the energy security spectrum. Electricity arbitrage through sale and purchase of electricity throughout the day is a key revenue stream. With increased solar development throughout the country, price volatility will grow. So a battery portfolio is an ideal optimization hedge for our solar portfolio. Ancillary services or reserves are also an opportunity for Genesis, where we expect to reduce costs on thermal generation assets as well as earning from the market. The Genesis portfolio will also benefit through reduced starts and lower requirements to operate units at low loads to mitigate potential peak losses. A battery is another tool to optimize the running of thermal units. How these benefits break down and drive value through the years will vary. We expect EBITDAF of around $25 million per annum, but this is likely to be variable year-to-year. We're targeting an internal rate of return of 9% to 10%. This slide is an illustration of what a battery installation might look like at the Huntly site. Gas is now about delivering more from less. I'm stating the obvious, but the gas market is now challenging for New Zealand. This winter, due to the gas shortage, around 500 megawatts of gas generation capacity was idle, due to the lack of fuel. Genesis took some risk making a significant gas purchase from Methanex in a hot market. However, doing so had an immediate beneficial impact on the wholesale market of electricity and on energy security. Neither we nor Methanex can be expected to do this on a regular basis just because New Zealand doesn't have an energy reserve requirement for renewables in its electricity market settings. All renewable generators need to carry their fair share of system risk. No matter what type of renewables generation they operate. We're broadening our supply options for gas and have secured additional gas from NZEC and additional 2 PJ over the next 12 months. But more importantly, we have secured a 12-month exclusive right to explore gas storage for up to 10 PJ of domestic gas or gassed off LNG as part of this agreement. With little upstream development obvious and major operators in a harvest or divest mindset, what replaces gas in the electricity market? In November last year, we saw a pathway for biomass to displace coal. We have since come to see biomass as part of an overall fuel portfolio for energy security at Huntly, alongside domestic gas, coal, LNG, diesel and future fuels. We said we would take 2024 calendar year to investigate biomass, and we are doing that. We have explored fiber supply capacity, production models and biomass economics for electricity. We need 900,000 tonnes of forestry residuals, that's slash and reject wood, to make 300,000 tonnes of black pallet biomass. There are multiple options for manufacture and each option offers different scale and economics. We have also identified marginal land where short cycle biomass crops could be grown for enhanced commercial returns to landowners. Based on this work, we believe there are sufficient resources and technology for a domestic biomass supply chain at the scale we need. The likely electricity price range will be around $140 to $200 a megawatt through the Rankines. We have multiple parties engaging on biomass production options, and we expect to end up with a range of future suppliers. As we put contracts in place, we will provide updates. If I could draw your attention to the graph titled Huntly fuel supply costs, the broader the portfolio of fuels at Huntly, the greater the energy security it can offer New Zealand. We have attempted to lay out the megawatt cost, including carbon at today's prices, of the different fuel types through the different generation assets at Huntly. Domestic natural gas was the cheapest option through Unit 5. However, gas prices now mean coal through Rankines is going to be the cheaper option. It is worth pointing out that the current Rankine units have very specific coal requirements. They cannot run on just any coal. There is currently very limited supply in New Zealand and only 2 mines in Indonesia that can produce to Huntly's specification. It takes some months to accelerate coal imports and following the Ukraine invasion, Indonesian mines have domestic volume minimums, which must be met as a priority over export volumes. Imported coal supply will need long-term supply positions to be secure. Flipping in and out of the market every dry year will carry growing risk for New Zealand. We were lucky this winter that we started with around 800,000 tonnes of coal on the Huntly stockpile. We have said going forward we will maintain an operational solid fuel stockpile at Huntly of around 350,000 tonnes. 350,000 tonnes is operational. It is not an energy reserve. Holding an energy reserve only used in the asymmetric generation profile of New Zealand's dry year cycles is not financially viable for Genesis on its own. Those holding Huntly firming options will now be able to order their own solid fuel stockpiles to back their HFO generation rights. This will be solid fuel held in addition to the operational stockpile. While Genesis will arrange supply, this will allow HFO holders to manage their own generation risk profiles through their own future fuel reserves held at Huntly. Going forward, we will expand HFO volumes and with that the opportunity for HFO holders to hold more energy security at Huntly in the form of solid fuel reserves. LNG may well be helpful in a future portfolio for Huntly, and we are open-minded to that possibility. However, while LNG gives energy security, it isn't cheap electricity at $225 to $300 per megawatt. As we deliver the additional 500 megawatts of generation length to Huntly by FY '28, and we establish gas storage, we will look to expand HFOs to include gas, LNG and solid fuel back generation and fuel storage options. This will enable HFO holders to add LNG to solid fuel energy reserves, improving energy security options. The big question in our energy transition will be whether Kiwi homes and businesses prefer cheaper electricity generation from coal with higher carbon or more expensive electricity generated from LNG at lower carbon. What is not in question is Huntly can and will flex to whichever fuel is favored. That is the enduring strength of Huntly as an energy security option for New Zealand. Finally, we're committing investment in time-limited technology projects now to ensure we move to a lower-cost business in the future while also serving our customers well. We are focused on 3 major value enhancing technology projects, as shown on this slide. Projects are being resourced on a time-limited basis with a focus on implementation risk management. I'll now hand over to Emma for FY '25 guidance. Emma?

Thank you, Malcolm. FY '25 guidance remains unchanged. Genesis Energy advises that FY '25 EBITDAF is expected to be around $460 million. Genesis highlights current volatility across electricity and gas markets and notes that this could result in a wider range of earnings outcomes. Guidance is subject to gas availability, plant availability, hydrology and any material adverse events or circumstances. FY '25 capital expenditure is expected to be around $180 million, including around $60 million investment in the 100-megawatt, 200-megawatt hour battery at Huntly. In line with Gen35 strategy, operating cost expenditure is expected to be around $390 million. That concludes our presentation this morning, and we'll now open the lines for questions.

[Operator Instructions] Your first question comes from Grant Swanepoel with Jarden.

4 questions. First one, the cost -- additional cost of $363 million. Looks like a good outcome relative to the guidance of $380 million and opt to adjust that down for the $8 million of SaaS. Can we assume, based on your November presentation, where you're expecting to take $20 million net off your FY '24 guidance. Does that still holds for FY '26?

Does the SaaS roll over?

The SaaS change of accounting?

Oh, yes, sorry, apologies. Yes, no, the SaaS change in accounting will continue into next year and in relation to getting further advice in terms of how we treat those costs associated with the loyalty program, so there will be a further impact in the FY 2026.

Sorry, let me repeat my question. At the interim results, you were looking for $380 million. You came in at $363 million. $8 million of that was due to the SaaS, so actually $371 million relative to the $380 million. So actually the cost came in $9 million lower. Then, if you take your guidance that you gave in November last year, that FY '26 of the OpEx will be down net $20 million on your FY '24 expectation. Can we now assume that FY '26, after SaaS adjustments, will now be $20 million lower than $363 million, so $343 million as the guidance?

No, that was a one-off. Let me just take that away and I'll come back to you with some more information.

Second question is on the 124 PJs of gas that's left in Kupe, how many years of production does that give you, and how low can that production go to in an annual year to offset the fixed costs associated with that operation?

The advice we have, Grant, is that it doesn't adjust the length of tenure of the well. It will result in lower flows per annum. There is a trigger point at which there's a reconfiguration of the well required to operate at lower pressures. We can get that point and circulate it. I don't have it in my mind right now.

So we're still on track for about a 2032 closure, is that correct?

It'll be somewhere 2032-2034, I think, from memory.

And then on Slide 25, you put in your gas contracts. Is that enough gas to cover what would be a dry period of the next 2 years potentially, or is that just enough to cover your own requirements and commitments in an average hydro year?

At this point, it's just our requirements. We don't think we'd have gas length, no.

And my final question. I see your carbon hedging drops off in FY '27. Is that more to do with, sorry, that carbon hedging was supposed to be 100% all the way to 2030, according to your last presentation on the topic, now falling off in '27. Is that mainly due to the extra coal use in '24, '25 and '26? Or is there some of the credits that you're moving into the trading portfolio?

No, it's directly related to coal use, Grant.

Your next question comes from Andrew Harvey-Green with Forsyth Barr.

A few questions from me. First of all, just in terms of the HFO volumes, and you sort of talked about on the call there just being able to expand those volumes over time, just wanted to understand how -- the way you, I guess, landed it, providing 85 megawatts now, and I think you had bids of up to sort of 270 bid. It seems like there is quite a lot of demand now. So why hasn't that been sold now?

Ultimately, we had a reserve price of $135,000, and the auction closed above that. So that's ultimately what drove those volumes. A critical part going forward is the portfolio management piece and how we set up our portfolio and Huntly for greater volumes of HFOs.

Okay. Next question is just around biomass and the time it's taking. I guess I think when you released the HFO documentation, there was talk in there about potentially getting something done by the end of this calendar year, but it looks like that's being pushed back 6 months. Are there any sort of particular challenges or things that are sort of pushing that time frame out a little bit?

Ultimately, it's a combination of contracting supplier fiber and the different manufacturing options that are in play. There's effectively 3 different manufacturing options. One is you import it, and the second is that you look at some scaled processing facility. And the third option is you actually put small mobile units into forest. And each of those options has different scale and economics to it and ultimately what we're trying to do is establish a contractual position that is long-term and that lands us with an energy or an electricity price that we think is feasible in the next 10 to 15 years. So there's a number of moving parts in it, Andrew, and we're just not at the point where we have a contracted position. We would hope that next year we'll begin to bring some biomass into the mix, but the reality is it's more likely to be '27, '28 before you start to see some real volumes in it.

Great. Okay. And the next question I just had was on the replacement, sort of the strategy, and I think you talked about moving more to PPAs and offtake. Is that -- are you actually replacing new build here or is this kind of in addition to just given the Kupe lower revenues coming from that going forward?

No, I think we're still staying with the mix that we set on Investor Day, which was a mix of owned assets, joint venture with PPA and pure PPAs. And we're judging each proposition on its merits in terms of whether we think it's best as an owned asset, whether we think joint venturing, it gives us some leverage and opportunity. And pure PPAs really comes down to the competitiveness of the proposal.

Okay. And a last question from me was just around the FY '25 guidance and I guess the comment about the wider possible range of outcomes. I guess, would you give us some sort of sense of how wide that range is or perhaps alternatively, how much wider is the range this year versus, I guess, outcome range in the standard year?

You give me the rain forecast for the next 6 months and I'll answer that question, Andrew.

But I guess, hydrology is always, has a fairly standard sort of range of outcomes. So I guess the starting point is key, isn't it?

Yes, the big difference that we're seeing, there's 2 big differences, I think, that are in play at the moment. One is that because of the gas situation, hydro was being dispatched at a much higher price than previous dry years. And that's causing a different dynamic and forecast there's a wider range of possibilities, because of that. So it's not just the rainfall, it's also the market dynamic of what price it will be dispatched at. The second is, the demand side responses, and we don't have clarity on -- on when -- the smelter could be called again for example, so can it be called next winter again, or is there a period of time where it can't be called. And that's going to be quite significant in terms of the generation profile for Genesis.

Yes. Okay, that's great.

Your next question comes from Vignesh Nair with UBS.

Awesome. Just 2 sort of straightforward questions from me. Firstly, just on the battery, the $150 million in CapEx obviously comes in about 10% less than one of your competitors, but the IRR is about the same at 9% to 10%. Can you just give a bit of color on what goes into that? Is it sort of inclusive of reserves, frequency keeping, arbitrage, and gas cost savings?

Yes, that's correct. It's also an asset that we haven't traded before, and so we've taken what we think is an evidence-based but conservative position, both in terms of the cost and the IRR, and we'll update that as the project continues.

Do you have a view on what the OpEx per year on the site will be? Is it sort of in line with your peers at around $5 million-ish per annum?

I think it's, from memory, it's about $4 million. I also think it's in one of the slides in our deck. So that's $3 million, sorry. Yes, is the number.

Okay, that's clear. And sort of secondly, just on solar, I think you're still making a decision on whether to do it on or off balance sheet. I'm just wondering, what goes into that decision. Clearly, you're heading towards the top end of your 2x to 3x gearing range. I just wanted a bit of color on how you guys are thinking about it at the moment.

Yes, I think it'll be a combination of what opportunities we have in play at the time we make final investment decisions and how we optimize capital deployment given where that metric is sitting once we deploy that capital.

Okay. That's all from me.

We are showing no further audio questions? We will move to the webcast questions.

So I'll just read those ones out. So just a couple of questions. This is from Energy News. Okay. And so Transpower last week discussed ordering diesel for Unit 6. Has this arrived and how much diesel do you think might be used in FY '25?

So what we've done during this winter is work this system where we can now switch Unit 6 between diesel or gas almost instantaneously. And we're now carrying diesel on site for, from memory, I think it's up to 5 hours of running, but it's relatively easy to replenish. And so it does give us, it's a short-run marginal cost of around $420 million. It does give us an option of bringing Unit 6 in when all the gas is deployed into Unit 5, so it gives us a bit of length with another fuel package.

And just another question. I'll combine the 2 also from Energy News. How much coal has been used since June? And has more coal been ordered since June? And is Genesis talking with potential domestic suppliers?

So, in our Methanex announcement, we indicated that we have 12 shipments ordered. We have 4 coming in the next month. The coal stockpile rose for the first time in the last couple of weeks, largely as a result of the extra gas from Methanex. We give quarterly updates on the stockpile and will continue to do so. What were the other bits, Tim?

Domestic supply might go first?

Yes, domestic supply absolutely we're talking to domestic suppliers our challenge domestically is volume within the specifications we need in essence, we need a multiple times greater than the domestic market can supply.

All right. We actually do have a couple more audio questions so maybe we'll just pass back to them.

Your next question comes from Stephen Hudson with Macquarie Securities.

Just a few from me. Just a clarification on the HFO. You're obviously acting as an agent there for other generators. Can I just clarify that you're also guaranteeing availability of the ranking units under contract?

The HFOs have a series of options in them that relate to fuel supply suspension and plant outages. So we're not guaranteeing the supply now.

Okay. And then just on the LNG cost range that you've given there, it looks like sort of midpoint of $200 a megawatt hour, but with quite a range. Can you just give us a little bit more detail there? That was interesting data. Just sort of, are you assuming ex-Gladstone or P&G and kind of breaking it down into the FOB contract and shipping contract and the regasification cost, I guess, would be interesting?

Yes. We basically worked off a set of figures that indicated that gas often landed is probably somewhere between $22 to $30 a GJ. So we chose $25 to work it out on. The bottom end of that range is $225 a megawatt. That's $25 a GJ through Unit 5. And the upper range of $300 is $25 a GJ through the Rankines.

So that's just a landed cost?

Yes. We just chose that number. It doesn't have a huge amount of science behind it. It's based on third-party data in terms of what a landed cost might be. And as I said it was kind of in a range of from memory $22 to 30 a GJ we chose $25 and that's the number that we put through Unit 5 and then the Rankines and that gives you that ranges on that graph.

Yes. Okay, it's clear. And just on your mass market electricity book, I just wondered if you can give us a feel for where your relative energy only prices versus the rest of the pack. I know you got a little bit ahead of them a year or 2 ago. Where do you see yourselves now?

I think from the last piece of work that we did, that's around 5%.

5% higher?

5% higher, yes, yes.

And then just last one on dividend that, you obviously cut the dividend, I think by the quantum of the how you assess the free cash flow from Kupe. Obviously, with KS-9 outcome and the transfer price, which I think you're using $7 to $8 a gigajoule, obviously, looking a long way south of current market. Are you ready to reassess the dividend on the basis of those 2 factors?

The dividend decisions always sit with the Board. So yes, it's not for us to comment on that. But as we said in the presentation, there's no current plans to change the dividend policy.

Your next question comes from Nevill Gluyas with Jarden.

I hope you can hear me. Great. Two questions from me, but a little bit multi-part, perhaps. The first one is just on the gas storage option, would show sound very interesting. I guess helps you potentially reconfigure the way you might be able to off your gas plant across seasons and the lead year. Good to come on the slide. So I was wonder if you could give a little more information, sort of, 10 PJs sizing, and you were talking about roughly what kind of PJs are in and out, what would you be thinking?

Off the top of my head, can I come back to you on that one?

Yes, that's fine. And sort of probably the more important questions there are. Would you be looking at Genesis Capital for that? Or is that something that you would be leasing from? And what would be sort of a timing for an FID on that option?

Yes. I haven't made a decision on whether that's third-party capital or our capital. We've kind of indicated that we prefer to use third-party capital and upstream activity. We have a 12-month right from the time that the drilling finishes to explore that option and to negotiate a contract.

Great. Okay. So this would be looking at sort of a serious life kind of asset here, 20 years plus.

Yes.

Great. Okay. That's very helpful. And the second question was just harking back to your Slide 20, talking about portfolio positioning and your ability to sort of use a bit more length. Am I right to be thinking about this? You're saying basically you have sort of extended your leagues a bit in terms of using your -- if you like, the strong degree of insurance policy within the generation side of the portfolio to back longer sales to third parties, I guess to wholesale customers that's the way it's slated on the slide. That's the right interpretation here?

Yes, it is.

Go for slightly more great links. Correct, yes, okay.

So we always believe that HFOs, while we've put out a 2-year HFO at the moment, that was really for us and others to learn and to begin to develop that product. Ultimately, we would like it backed by more generation assets, more fuel types, and a longer tenure for different types of customers. So, the 2, 5, 10-year type tenures.

There are no further questions at this time. I'll now hand back to Malcolm for closing remarks.

Thank you very much, everyone. It's been a pleasure to update you on both FY '24 and the strategic proof points that we're delivering. And we're now very focused on our 8 by '28 and look forward to engaging with you on that. Kia ora.