Genesis Energy Limited (GNE) Earnings Call Transcript & Summary

Thank you for standing by, and welcome to the Genesis Energy H1 FY '25 Results Briefing. [Operator Instructions] I would now like to hand the conference over to Mr. Malcolm Johns, Chief Executive. Please go ahead.

Kia ora, and welcome to the half year FY '25 results presentation for Genesis Energy. I'm Malcolm Johns, Chief Executive, and I'm pleased to introduce Julie Amey, our new CFO, who joined us in October last year. Briefly running through the agenda for the presentation, I'll first talk through the highlights of the half year and touch on what we have delivered strategically. Julie will then speak to the financials and business performance in the period. And I will wrap up with an outlook of the remainder of FY '25. Reflecting on last 6 months, it was a dynamic period that demonstrated the value and flexibility of Genesis' portfolio. The market conditions were volatile, but the value of our strong, well-priced customer books, the resilience of our lakes and the value of our flexible generation assets with deep energy storage and capacity drove a credible result of $217 million EBITDAF, up 7% on the prior period. The first thing I want to do is acknowledge our people, who have worked 24/7 for many months to react to the events of winter '24. Across winter '24, we produced around 30% more electricity than we planned to cover the renewable and gas shortfall in the system. To achieve this, we had to put in place fuel supply at scale we were not expecting to have to do. The result was we honored all our customer obligations and protected shareholders through an incredibly volatile market. Genesis was able to back its customer books on its own generation during winter '24, protecting both customers and earnings from the elevated spot market. We continued the migration of our retail operating model to a lower cost, lighter touch approach while maintaining customer satisfaction and market-leading brand positions. We have now reached a reduction of approximately 200 full-time roles in our retail business. Our interaction Net Promoter Score, based on surveys undertaken with customers, also improved in the period, reflecting the benefits of simplification and delivering an improved customer experience. Our renewable project pipeline had some excellent progress in the period. Lauriston solar farm, currently the largest solar farm in New Zealand at 63 megawatts, is now generating. In August, we secured an advanced stage, consented site for a 127-megawatt solar farm near Edgecumbe in the Bay of Plenty and this month, secured another advanced stage 67-megawatt solar project near Leeston in Canterbury. In addition, our 200-megawatt solar site near Foxton in Manawatu-Whanganui was accepted for inclusion in the Fast Track Approvals Act. The 62.5 megawatt PPA we had earlier secured for generation from the Tauhara geothermal plant near Taupo came into effect on 1 January. Our hydro power stations continue to form the core of our renewable generation portfolio, producing an average 2.8 terawatt hours per annum, lifting to as high as 3.3 during winter periods. Huntly Power Station's assets and fuel flexibility played and will continue to play an important role in our portfolio. The first stage of our battery project, a 100-megawatt -- 200-megawatt hour battery energy storage system continue to advance in the period and is on track to be operating in winter '26. We have advanced our support of a domestic supply chain for biomass, executing a nonbinding term sheet with Foresta as the first step in commercial discussions. We expect this to be the first of a number of term sheets as current discussions with multiple parties progress to commercial contract engagements. Our balance sheet remains well managed, and our investment-grade credit rating was reaffirmed at BBB+ and stable by Standard & Poor's. Working capital required to replenish the coal stockpile has been a big draw on cash during the first half of the financial year, and Julie will talk more about this later. The Board declared an FY '25 interim dividend of $0.0713 per share, imputed to 100%. In addition, the dividend reinvestment plan is available to shareholders with a discount of 2.5%. Let me now turn to what I think is one of the most important slides for investors today, our integrated portfolio and how it will drive earnings growth over the next 4 years and beyond. Gen35 delivered shareholder value by growing 2 value streams within the integrated portfolio. The core value stream includes long-dated and reliable earnings driven from our well-priced customer books, backed primarily by our renewable generation. The new value stream reflects new value driven from our flexible generation at Huntly and storage in our lakes, being monetized through new products and services in an emerging firming and peaking market for renewable generation where demand currently outweighs supply. Looking at our core value stream, these earnings are already established and enduring. They are ready to deliver growth. This is the primary focus of our 8 by ’'28, optimizing, growing and making core cash flows more valuable and less volatile. Over the next 4 years, we see demand in our customer books being stable at around 6 terawatt hours per annum made up of a diversified mix of homes and businesses spread across New Zealand. Our brands are market leaders. Our customer service ratings are high, and our customers are loyal. By focusing on selling our customers the services and products they value while adding new future value pools and relentlessly simplifying our retail model, our customer business will deliver growing margins over the coming years. Renewable generation is currently focused on supporting our large, well-priced customer books, driving reliable long-term core cash flows. The foundation of our renewable generation is our hydro schemes, 2 North Island and 1 South Island. Our lakes generate around 2.8 terawatt hours a year, rising to 3.3 during weak periods. Despite being well placed geographically and with good storage, the market currently applies a lower earnings multiple to Genesis' lakes than those of other generators, which seems hard to justify. New renewable generation will primarily displace baseload gas generation out to around FY '28. Today, we have around 2 terawatt hours a year of baseload gas generation. Around 1 terawatt hour of this is supplied by Genesis' share of gas from Kupe, and the rest is purchased from third parties. With limited confidence that new supply will come to market in the foreseeable future, we have begun focusing on displacing baseload gas generation with new renewables. We expect to have displaced around 1 terawatt hour by FY '28 and 2 terawatt hours by FY '30. As we displace baseload gas, our remaining gas generation will move across to the flexible generation part of the portfolio to drive new cash flows from peaking and firming products and tolling arrangements. In the event we experience further short-term unexpected declines in gas supply or the cost of gas rises above the cost of coal, we will use Rankines and coal as a bridge to new renewable generation. Our portfolio is well placed to manage further disruption in the gas market. We have now moved Frank Energy to an electricity-only brand. And while Genesis will continue to offer LPG to new customers, it will no longer be accepting new reticulated gas customers unless more gas supply comes to market. Our focus will be on supporting our existing gas customers as a priority. In addition to our strong core value stream, we see a rapidly developing flexible generation market where demand is currently running ahead of supply. We know hydro needs backing up over years, but we are learning that wind and solar need backing up over hours, days and weeks and at a growing scale. Winter '24 was a stark example of this. With around 1,200 megawatts of flexible generation today and a 200-megawatt hour battery on the way, Huntly will provide around 75% of New Zealand's flexible thermal generation supply from 2026. Our lakes also offer future flexibility opportunities, which we are currently exploring. To recap, Genesis offers investors growth from 2 value streams in its portfolio: growing core value from large, well-priced customer books backed by well-located hydro generation and growing new renewables; plus new value from 1,200 megawatts of flexible generation with deep energy storage options. Over the next few slides, I will give an update on our 8 by '28 initiatives before exploring how each of the 3 cogs in our portfolio support growth of existing core cash flows and will unlock new value streams and cash flows in the future. Now turning to the 8 by '28. As you all know, these are our big 8 deliverables by FY '28 that provide multiple pathways to EBITDAF in the mid-$500 million. The 3 cogs of our long-term strategy remain the same: firstly, customers, where our focus is on margin growth while maintaining a large, well-priced customer mix appropriate to our portfolio, strong brands and strong customer service; renewables, adding new renewables to the portfolio to displace baseload gas generation; and flexibility, increasing our ability to monetize our flexible generation assets as firming and peaking demand continues to grow faster than supply. We have now included some additional financial parameters for the initiatives, both potential EBITDAF uplift and the associated growth capital for each cog. The greatest potential earnings uplift is expected to come from renewables in our core value stream and building new value from our flexible generation. Naturally, these will attract the largest portion of growth capital and will provide greater stability and predictability of our earnings going forward. Customer is about margin growth. We will focus on delivering services and products our customers value while maintaining strong brands and high customer service as we relentlessly simplify our retail model to grow our margin. We are moving away from legacy in-house technology solutions and are working with Gentrack and Salesforce to step change our billing and CRM platform. The new platform will enable us to leverage meaningful data insights and improve our customer billing capabilities. Our Frank brand is on track to transition to the new billing platform this year and the Genesis brand by FY '27. We are committed to continuing to care for our customers through our award-winning Manaaki Kenehi program. And we are focused on introducing 2 new value pools to the retail business, demand-side flex at scale and EVs. A real-time hot water cylinder management trial began in September 2024. It now has 5,500 Genesis customers signed up and is providing 17 megawatts of verified peak demand-side flex. We have now moved into designing how we will scale this to support our 8 by '28 objective of 150 megawatts of demand-side flex by FY '28. We are able to secure an investment in ChargeNet when they sought capital in 2024, enabling us to purchase a controlling share. The rationale for acquiring a controlling stake in ChargeNet is that it secures us an end-to-end value pool for the electrification of New Zealand's road transport, private and commercial fleets. ChargeNet will play a central role in our strategy to gain 30% of this growing EV value pool. We have been building our position in the EV market for some years. One of our key partners has been ChargeNet, and they are central to our successful EV EVerywhere product. We know EV customers are high value. They're sticky and they use around 40% more electricity per year than non-EV customers do. The second portfolio cog is renewables. Here, we're focused on how we'll displace baseload gas generation to support our large, well-priced customer books. We are well into building a pathway to deliver 500 megawatts of new solar generation by FY '28. Lauriston solar farm is now generating. We have purchased an advanced stage 67-megawatt option at Leeston. We expect FID on Edgecumbe and Leeston in mid-FY '26. And our 200-megawatt solar farm near Foxton has been accepted for fast track consenting. Our 62.5 megawatt geothermal PPA commenced on 1 January '25. These projects, together with our existing hydro schemes and PPAs, will see our renewable generation capacity increase 17% by the end of FY '25. We are engaged in a number of discussions around our Horizon 3 objective of 300 megawatts of wind generation. We remain open to multiple funding structures for our renewable growth projects and will ensure we obtain an appropriate return above our own cost of capital while maintaining our investment-grade BBB+ credit rating. So from growing renewables to building flexibility. Our battery development, potential gas storage and biomass projects support the increasing demand for flexible generation as intermittent renewable energy increases. Stage 1 of the Huntly battery project will deliver 100 megawatts for 2 hours. Installation is expected to commence by the end of FY '25 with operations on target for Q1 FY '27. We are reviewing opportunities to increase our gas flexibility, which includes storage options. Industry and government have been investigating the potential for an LNG import facility, and we are of the current view that it is uneconomic for New Zealand. The outlook for the gas market remains uncertain, and the long-term cost of nonequity gas on a coal equivalent basis may come to exceed that of coal. Our biomass project has received strong interest from potential partners, and we recently signed a term sheet with Foresta to explore a torrefied biomass supply solution for Huntly. We are working with the ministerial bioenergy task force, led by Minister Simon Watts, to ensure there are no unnecessary barriers to establishing a biomass industry at pace. On that note, I would now like to pass over to Julie, who will go through our financial and operational results in more detail.

[Foreign Language], Malcolm, and kia ora to everyone listening in. It's great to be part of the Genesis team and be back in the energy sector and importantly, to be an enabler of the shareholder value proposition from our Gen35 strategy. So over to the Genesis results now for the first half of financial year 2025. You will see on Slide 11 that Genesis delivered an EBITDAF of $216.5 million and a net profit of $70.3 million. Pleasingly, both were up on pcp. The business delivered this meaningful financial outcome through a couple of very challenging quarters in which the operating and market conditions required the portfolio to flex and also required some quick action from our teams across the whole organization to ensure no impact on our customers and to minimize the impact on our bottom line. Of note in our financial performance, there was a 27% increase in revenue against pcp. This largely reflects the increase from the uplift in thermal generation and wholesale spot prices coupled with an increase in wholesale gas volumes and also higher average retail prices against pcp. I will speak in a bit more detail soon about gross margin and operating costs. But before I do, let me first touch on some of the movements between our EBITDAF and our NPAT, namely the revaluations of our derivatives and our generation assets that we undertake every reporting period. These movements are largely driven by changes in the price paths, and you will find further details on these and the main sensitivities around them in our financial statements. Moving on to Slide 12. You will see that we have provided more detail on the movements in our gross margin and OpEx against pcp. This is to bring more transparency around how the half played out for us. You will note from the gross margin bridge that the dry winter had a significant impact on our first half performance, and we have called this out separately as one of the most significant drivers of the variance to pcp. We contracted expensive gas to address the low hydrology and the winter wind drought. This resulted in a significant cost for thermal generation during the period that we could not pass on fully after it began raining. However, as you will see from the graph, we were able to realize upside from our portfolio flex as we exited that gas contract and rain filled the lakes. Lines and metering costs increased by around 10% against pcp, and these have been passed on to our retail customers as per obligation, although there is a timing difference in the half. We intend to pass on all of the Commerce Commission-approved lines charges increases as they are applied to us. My final callout on gross margin is the uplift against pcp that we realized from our asset availability. We continue to invest in our assets to ensure a strong level of reliability across our portfolio with around $23 million of stay-in-business CapEx spent on generation assets during the half. Moving across to operating costs. Over 40% of our $192 million of OpEx in the half was in relation to our people. While the $79 million of people costs were marginally up on pcp, this includes a reduction in core FTEs from a reset of business operating models while noting that many of the exits were later in the half. Also of note in the people spend, this does include one-off restructuring costs and an average wage and salary inflation rate of around 4% to 5% against pcp. We've also had a ramp-up in our technology projects, which is a temporary cost but a critical activity to unlock future value. Our largest technology project is the retail billing and CRM replatform, and you will recall that this is one of our key initiatives under our 8 by '28 program. We have spent around $16 million in the half, of which $15 million is in OpEx. As an organization, we remain focused on the delivery of like-for-like cost reductions across the business. Moving now to capital management. You will see on Slides 13 and 14 that we have provided insights into our free cash flow, our source and use of funds and our debt metrics. As we work through our capital management strategy over the couple of months -- the next couple of months, we are closely managing and monitoring our financial resilience, our affordability and our financial settings. During the first half of the financial year, we directed a significant amount of our operational free cash flow to replenishing our coal stockpile and securing our energy reserve. We entered the half with a low level of coal stockpile, and we utilized over 300,000 tonnes to address the difficult winter conditions and the flex requirements. Given the current long lead time for coal, it was important for us to ensure we replenish this as quickly as possible to provide the security that the industry needs. At the end of the half, we had around 570,000 tonnes of coal stockpile for operational and HFO requirements, and we have a further 500,000 tonnes targeted for delivery between February and September. The coal stockpile represents a material draw on our free cash flow, and it is not sustainable for Genesis to continue to fund this on our own. We welcomed the support offered in the heads of agreement with other gentailers to help manage this energy reserve for the whole system. Moving on to capital spend. You will note that our stay-in-business CapEx spend of $33 million is in line with pcp and is largely directed to maintaining our assets to an acceptable level of reliability. Also, we utilized funds during the half for growth investments over $100 million as we work towards our Gen35 strategic objectives and outcomes that Malcolm has updated you on earlier. From a debt, liquidity headroom and leverage perspective, we are comfortable with our financial resilience and the pathways available to us to ensure we will have the right capital structure in place to enable Gen35. We have a borrowing maturation profile that enables us to both renew and increase our access to liquidity to ensure the right structure and the right level of diversification for our future portfolio. This is currently being worked as part of our capital management strategy refresh, which you will hear more about later in the calendar year. We continue to be well supported by our financiers, who have a good understanding of our business and our strategic direction. And finally, as Malcolm has mentioned, we have maintained our investment-grade credit rating, and we're very pleased to have this reaffirmed by S&P at BBB+ in December 2024. So I'm now going to move us on to our business performance. And I have the pleasure to be representing our Chief Retail Officer, Stephen England-Hall; and our Chief Wholesale Officer, Tracey Hickman; and of course, the great teams of people that sit around them both. I refer to Slide 16, which is a high-level overview of our retail business performance for the half, which is hard to do justice to in one page. What I want to call out is the impressive growth that we achieved in both brand equity, which is up 6% against pcp, and customer satisfaction scores that are up 8 points against pcp. And what makes this more remarkable is that this has been achieved while delivering a significant transformation of the retail operating model, which has removed around 200 FTEs, enabling annualized like-for-like cost saving of around $20 million. There continues to be a strong focus across the teams to access future value pools with examples including the ChargeNet investment to connect the customer EV value chain and the launch of our demand flex trial, which has already secured 17 megawatts of flexibility across over 5,000 customers, to prove up that we can bring both lower energy bills to customers and improve our gross margin. My final callout on retail on the half is that we have also successfully met key delivery milestones of the billing and CRM replatform that I referred to earlier, ensuring this critical project remains on track. Overall, we are really pleased with the enhanced focus that retail brings to ensure we secure more value from our volumes in an energy-constrained market. And now moving to our wholesale business on Slide 17 and another impressive performance from our portfolio in a challenging period that is difficult to do justice to in one slide. We've previously spoken about the generation flexibility in our portfolio that allows us to perform well in both wet and dry conditions. This enables us to run our thermal assets hard in dry conditions to gain length in a high-priced market and turning them off to go short in a wet and low-priced market. This portfolio flexibility featured heavily in the first half of the financial year, and we have prepared the illustration on the slide that shows 1 trading period from 2 distinct days to demonstrate the range of thermal running achieved under different market conditions. And not only did we see the seasonal volatility across the half, but we had days within our generation portfolio where we flexed across a range of 1,000 megawatts. This flexibility was supported at different times during the half by additional gas purchases or sales, which was challenged at times by having too much or too little gas. Another strong feature within the half was the reliability of our generation assets, including the team returning a third Rankine to service, meaning that all 3 Rankines were running together 24/7 over a prolonged period. All of this demonstrates the resilience of our generation and fuels portfolio even in a constrained energy market. The purchase of additional coal and gas and the investment in our third Rankine came out of cost to Genesis. And we now have the opportunity to work through this from a sector perspective in order to realize more value from the significant flexibility that Genesis can uniquely offer. I'm now going to hand back to you, Malcolm, who will speak to the market and our earnings outlook for financial year 2025. Over to you, Malcolm.

Thank you, Julie. There are 3 emerging trends that we see shaping our thinking currently. Firstly, as we are all well aware, the gas market has structurally deteriorated in the past year. Currently, it is very difficult to have confidence the market will improve or to continue to see gas as a transition fuel for New Zealand. As a result of this and as New Zealand's second largest gas customer, we have made the decision to pivot our strategy and dedicate our new renewable generation development to displacing our 2 terawatt hours of baseload gas generation as a priority. We do see gas playing a role in flexible generation, subject to future supply, flexibility and price. Secondly, we are clearly not the only ones who have pivoted. Coal is once again acceptable as a firming and peaking fuel and coal-backed generation is back in demand. Thirdly, demand for flexible generation is now exceeding supply. We see a real growth opportunity to monetize our large capacity of flexible generation across Huntly and our hydro schemes. As we look out to the remainder of the financial year, we expect the market will continue to be dynamic with a range of opportunities and challenges for us to navigate. However, we continue to see a pathway to EBITDAF for FY '25 of around $460 million with our P50 hydro and gas availability assumptions and no major unplanned outages or materially adverse events coming to bear. We will maintain focus on progressing our Gen35 strategy with initiatives that strengthen the foundation of our transition to displace thermals and monetize the significant flexibility of our portfolio -- that our portfolio offers. I want to reiterate again that Genesis cannot be expected to continue to underwrite system insurance for our sector. On the back of our successful HFO auction in 2024, we are both encouraged and grateful to have recently entered into a heads of agreement with Meridian, Mercury and Contact to explore long-dated commercial contracts to support the Rankine units at Huntly. We are very positive about the opportunity to ensure all 3 Huntly Rankine units remain in service for another decade to provide the necessary support to New Zealand's energy security. Thermal generation will become more asymmetric over the coming decades. Forecasting demand on averages can prove to be a false reality as winter '24 showed us. When thermal is needed, it will be needed at scale as evidenced by Genesis depleting the majority of its coal inventory in one winter season during 2024. Backup generation for wind is now of a similar scale as hydro. As industry develops more wind and solar, the frequency of backup may decline, but the scale needed will increase. KPMG's recent white paper developed in conjunction with Genesis shows that the demand for Rankine units in the 2030s will likely exceed that of the 2020s. Their estimates also showed that if Huntly was retired and renewables were overbuilt to compensate, consumer power bills would be around 7% higher long term. The challenge for thermal generation is the current market is not well suited to providing an investment-grade return because future generation profiles for thermal will continue to become ever more asymmetric, yet losing that generation brings increased volatility and more cost for Kiwi homes and businesses. Our focus with products such as HFOs and whatever comes out of the heads of agreement process is to find commercial structures that can provide some metric cash flow to the asymmetric generation profiles of future thermal generation. Going forward, it will be important that as policymakers look to encourage new wind and solar to be developed, regulators do not give those developers a free ride in properly covering upfront the real volatility costs their generation will bring to the grid. Thermal generation is essential to electricity security and lower future customer bills. But the viability of thermal generation needs to be equally as secure. Regulators are making it harder and harder to achieve a commercial return on thermal generation. Increases in market obligations and disclosure requirements further increase the risk of accelerating the retirement of the very generation that is currently in short supply and not being invested in. There can be no free riders or there will be blackouts. We will continue to keep the market abreast of where we -- where we can on negotiations under the heads of agreement. I look forward to sharing more details and insights on our strategy later this year at our Investor Day and site tour. Further details and save the dates will follow in the coming month. Thank you all for listening to our presentation this morning, and we will now open the lines for questions.

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

My question is around the $105 million to $160 million uplift in EBITDA. Can you give some sort of idea, of the bottom in $105 million, what proportion of that would have been banked in FY '25, so at least we can do some sort of numbers on that? Linked to that is in FY '24, you're looking at $500 million for FY '25. While your guidance is $460 million, is $500 million still about a mid-cycle, mid-market type number for FY '25? And then just still around your guidance, the CapEx that you've got until 2030, is that still around $1.1 billion? And then my second question is -- well, the last, is the gas cost that Contact is picking up for the longer-term contract of $15 a gigajoule. Is that something that you see playing out over the next few years, particularly in your transfer pricing with Kupe?

Grant, it's Malcolm here. Thank you for that. Can I just ask you to ask the first part of that question again? We didn't quite understand it, sorry.

Sure. I apologize. So your guidance for FY '28 is an uplift of $105 million to $160 million. So that $105 million uplift, what is the starting point? So what I'm trying to do is say, okay, $105 million of what? Is it of $440 million or $420 million? Or what is your starting point? But an easier way for you to tell us is to say that of that $105 million bottom end, x million is going to be achieved in FY '25. So we can see what's left to come thereafter.

Yes. So thanks for that, Grant. So it's all incremental on full year '28, and it is a ramp-up. So for some of those areas, it is a quicker ramp-up than others. And if I was to give you an example, for wind, we would expect that we would have some of the spend and investments coming through by '28, but you won't see the revenue upside come through. So it does vary by initiative. But it's all incremental.

I'm sorry -- so I know I'm taking up too much time here. So you're giving guidance that your EBITDA is going to lift from $105 million to $160 million. What is the starting point that it's lifting from? Is it from last year's number? Is it from a normalized FY '24? So all we want to do is be able to say, okay, so $440 million starting point, so it's somewhere between $440 million plus $105 million to $160 million. Give us some sort of idea of where your starting point...

Yes. $460 million is the starting point. So the guidance for this year.

Fabulous. And then the CapEx to 2030 that you got a percentage of?

So the CapEx -- you referred to the $1.1 billion that we put out there for growth. So I think that number still holds, but it is all subject to the financial settings. So we've -- what we've given you on the slide is where we think the amount will be allocated through based on financial settings. But whether that is -- how that plays out, we're still working through.

So it is a $1.1 billion envelope, Grant. But if we look at the FID decisions we've got coming up, we will be looking at what are the different capital structures we can deliver that through and what is the optimal balance between managing earnings uplift and capital deployment, so joint venture with PPA, pure PPA or direct investment, and we'll make those decisions at FID.

And then the gas question?

The gas question? Remind me of that again. You said Contact's $15 per GJ. Look, our view -- the clarity we've given on gas is we've got 2 terawatt hours of baseload at the moment. 1 terawatt hour comes from our equity gas from Kupe. The other 1 terawatt hour comes from the market. And we would expect the cost of that to reflect the way the market plays out going forward.

Your next question comes from Vignesh Nair from UBS.

Just a first question on a clarification from the prior one. Is it fair to say then that you're guiding to effectively FY '28 EBITDAF midpoint of $593 million versus current consensus at $520 million?

No, we haven't provided guidance out to FY '28. We have provided guidance for FY '25, and we're saying we're targeting mid-500s as a midpoint for the impact of the 8 by '28 strategic initiatives. You'll see that we've put a range around each bucket, each cog, and we would expect the actual outcomes to be a variance within that range. And so we haven't provided a hard number out to FY '28.

Right. But hitting those midpoints kind of gets you to $590 million from a base of $460 million off of Grant's question.

Yes. It does, if you add up the midpoints. What we can't guide you on at the moment is what the variation around those midpoints will be, and so we're saying mid-500s.

Right. Okay. I mean, like, the thing is even the bottom end of that gets you to, I suppose, $570 million, right, or $565 million, I suppose. I mean it's already towards the top end of mid-500s, I suppose, but okay. That's fair enough. And the second point, just your question just on biomass. It was a bit light on the details. I just was wondering if I could get a bit more color on any updates on what your view is on costs and economics to run biomass through the Rankines.

We're driving towards parity with coal as a cost. Internationally at the moment, the largest biomass facility in the world is currently producing around 70,000 tonnes a year. Its source feed is corn stalks and rice char. And it is producing a cost that is above the cost of coal production at the moment. And so what we'd say is when we look at this project, there is a range of emerging technologies for producing torrefied pellets. The sweet spot seems to be something around 50,000 to 60,000 tonnes a year in terms of the best input/output cost ratio. But this is an emerging technology area. And so the best way to answer that is we are targeting parity with coal. And the best assumption to use is the coal price at the moment.

And sorry, Malcolm, is that coal through the Rankines with carbon or without?

Yes. With carbon, yes.

Your next question comes from Stephen Hudson from Macquarie Research.

Just on the comments that you made on hydro flexibility, Malcolm, could you just talk us through what you're reviewing there as options?

Yes, sure. We don't have anything concrete other than we have flexibility in our hydro assets, particularly the Tongariro Power Scheme. And what we're doing is we're working through a process of evaluating whether that is -- or how much of our hydro flexibility is best applied to flexibility products going forward versus baseload generation. So what we're saying is that we have some really good flexibility options in our hydro system. And we're just working out what the highest and best use of that going forward is. We don't have a position on that at the moment. So we're not offering any numbers around that. We're just simply flagging that as we look at how we optimize our portfolio, that Huntly is not the only flexible generation options we have in our fleet.

Anything on the South Island hydro assets you've got?

In terms of flexibility?

Yes.

Obviously, Tekapo is our largest storage lake at the moment. And so we have flexibility options around that as well. We don't have any firm plans in terms of what that flexibility looks like in the hydro system. So all 3 lakes have flexibility options that provide some interesting work to do for us at different times of the year.

Okay. That's useful. And then just on the capital structure review, is the review of the dividend policy in scope?

Yes. So thanks for that question, Stephen. So the capital management refresh is looking at everything, our capital allocation framework, the financial settings, the dividend, so everything that will really lead into the source and use of our funds. And we've sort of shared a bit of that thinking in the slides, you'll see. [ So it's bridging ] to that.

Understand. I might be cheeky and ask a third. Everybody else has asked sort of 4 or 5 sort of subgroup questions. Just on the lines charge increases this year, have you got tariff changes in place? Or are you planning on out-of-cycle increases?

No, we'll stay -- any increases will be passed through in our normal pricing cycles. And that will result in some timing differences as they move through. And you can see last year and this year, you've got timing differences in the half year. We would consider -- we don't want to shock customers. And so we will stick to our normal retail pricing cycles.

Okay. And then just one final one. Your transfer price for Kupe, again, is at $8.33. When are you going to sort of look to recalibrate that to sort of closer to the contracted gas prices that we're seeing coming through of $15, back to an earlier question. It seems to be sort of giving rise to a bit of an accounting fiction within the company.

Sure. Don't have anything specific to say on that, Stephen. I don't have any information to hand. But there's normal review cycles that we're required to go through for NZP&M and the likes, et cetera. And so those cycles will continue to be normal. But I can't recall right now what those cycles are, sorry.

But you'd agree that the $8 transfer price is a fiction.

I don't have anything to add to that, Stephen. I'm not an expert in the gas market, sorry. I don't have the details of how the transfer pricing works to hand. So I'd be making stuff up commenting on it, sorry.

[Operator Instructions] Your next question comes from Andrew Harvey-Green from Forsyth Barr.

First question is just around the FY '25 CapEx guidance, which has come down quite a bit. I assume the bulk of that is timing related, but you also made a comment here about managing affordability. Does that sort of indicate we have a little bit of CapEx increases on the existing projects that we need to think about?

No, it's -- to your first point, it is around timing, so mainly the battery projects, and that's just giving the right timing there. If we don't need to spend now -- we're not spending now, but that doesn't mean that there's no spend. So that movement you're seeing is largely timing.

And the timing, Andrew, is around balance of plant. So it's just way the lead times fall that's driven the CapEx. And that's just moved the time line across the 18-month delivery period, and that's what's changing the FY '25 CapEx.

Yes. Okay. So there's no underlying increase in project CapEx we're seeing here.

No, it's just -- it's to do with -- balance of plant has a number of items that have long lead times on it, and it really is just the manufacturing schedule that drives when you've got to pay for it.

Yes. And the second question is just, I guess, around the gas storage and the project, I guess, at Tariki. Maybe a bit more of an update on how that's tracking and whether you're thinking if you're going to be dropping baseload so significantly, whether that sort of impacts on the economics and your thinking around that?

Yes. As we said, all 8 by '28 initiatives have a degree of probability of stacking up and a range of outcomes, and that's why we've given that range of EBITDAF and capital deployment. And so the reality is if gas storage doesn't stack up, then we won't be investing in it. What we have been doing is gas storage is just one option around gas flexibility. We have a number of discussions and a number of activities in play around gas swaps and different ways that we can manage flexibility into the system. Gas storage is the most effective way of doing that. But whatever ultimate flexibility regime we come to, it has to be a return above our cost of capital. Otherwise, we won't do it. And gas storage at Tariki specifically, the initial subsurface tech work shows that it's very well suited to gas storage. But there's a lot more technical work to do before we understand what the investment profile would look like to bring that to life.

Your next question comes from Cameron Parker from Craigs Investment Partners.

Just 2 from me. Kupe seems to be declining at quite a rapid rate. It's now at sort of 41 TJs a day out of the 77 max capacity. So what's the plan around that in terms of investment or idling? Or what's going on with that in the near term?

The joint venture hasn't made any decisions around that at the moment, Cam. But clearly, it's something that they're focusing on. And we can't speak -- although we're part of it, we can't speak on behalf of the joint venture. All we can say is that it's something that they're focused on at the moment.

Do you think you'll be in a position by Investor Day to give us an update on that?

We would hope so, but it's really in the hands of the joint venture. We're a minority party. So we've got to work at the pace that they do.

Great. Okay. And also, Kaiwaikawe, was wondering if you have anything you can say on negotiations there in terms of timing of maybe that being completed.

Look, we're really happy that Mercury have proceeded through FID and are into construction. And obviously, engagement continues in terms of how we come to an agreement on the pathway forward for that.

That does conclude our time for questions. I'll now hand back to Mr. Johns for closing remarks.

Thanks very much, everybody. Appreciate you listening in. Appreciate your questions and appreciate your interest. Look forward to talking to you all soon. Thank you.

That does conclude our conference for today. Thank you for participating. You may now disconnect.