Genesis Energy Limited

Kia ora and welcome to the FY24 half year results presentation for Genesis Energy. I'm Malcolm Johns, Chief Executive, and I'm joined by James Spence, our CFO. After a year in the job, it has been exciting to learn about the sector and the company as we took stock of our position and looked out into the future, while also delivering on key projects and continuing to serve our customers well. The highlight for me was the launch of our new strategy, Gen35. The executive team, the board, and many people inside and outside Genesis worked hard over many months to drill into the first principles of the sector, the company, and the energy transition opportunity. We looked at where scarcity sat, where value sat, the company's capabilities and assets, and we ultimately developed our strategy to leverage our strong strategic value into financial value across three key value pools. The first is electrification, how we use our strong demand side position of almost 500,000 customers to drive faster organic demand growth through accelerated electrification of homes and businesses. The second is flexibility, how we optimise and develop our diverse generation fleet across both islands to leverage value from growing volatility across an hour, a week and months. The third was renewables, how we utilise our strengths to partner and directly invest to deliver new renewable generation for the future, driving Genesis to 95% renewable generation by 2035. I'll talk more about strategy later in the presentation. There were, of course, challenges during the period, with the forced outage of New Zealand's largest generating unit, Huntly Unit 5, being key among them. We also saw other thermal generation experience unplanned outage, and this only served to remind us that our thermal insurance policy is ageing, and that is a key issue at a system level. New Zealand was fortunate that hydro conditions were supportive and that we have to date maintained Rankin units and fuel reserves to back up such supply disruptions. when, where, or how the next energy disruptions arise is unknown. But with climate change, natural disasters, aging thermal generation, tight gas markets, the current aversion to coal-backed products, the disproportionate application of ESG discounts on thermal generators, and more non-firm renewable generation planned, the system risk under current market settings is only growing. The Rankin unit stepped up to fill the gap created by the outages this time, demonstrating the importance of the entire Huntly portfolio in maintaining New Zealand's, especially the North Island's, security of supply. And our team are very proud of that. Now turning to the highlights of the period. Aligned to our purpose, we're presenting what we see as the most important achievements of the past six months for people, planet, and profit. For people, we saw strong growth in customers, with nearly 9,500 customers gained in the period, an increase of 2%. Customers moving to EV plans reached almost 7,000, a key focus for Genesis. And as we announced in the period, we're deep into a root and branch review of our retail strategy and operating model to focus on fewer, more impactful activities directly linked to customer service and value. As previously indicated, the change in retail strategy may result in up to 200 fewer roles at Genesis over the next two years, with around 70% of those changes occurring in FY24. We're mindful of the effects such change processes have on those involved and are focused on delivering a supportive process and moving through the uncertainty as quickly as we can. Looking now at achievements under our planet pillar, We were pleased to reach financial close at Lauriston Solar Farm, New Zealand's first project finance solar farm, alongside our partners, FRV. We've learned a lot, building our internal team and external relationships and capacity to accelerate toward our next developments in solar. Resource consent applications were lodged for the Tekapo Power Scheme. which would allow for 35 years further operation of that scheme. We were pleased to be supported in this application by three Ngāi Tahu runanga, Aru Whenua, Muraki and Waihau. We also entered into support agreements with the Department of Conservation and Fish and Game. Lower hydro inflows resulted in a 500 gigawatt hour decrease in renewable energy generation compared to the previous very wet half year. Speaking to our third pillar, profit, against a record half year to start FY23, the H1 FY24 was in line with expectations. EBITDAF was $202 million, as expected, however down 32% on prior period. Cash flow was positive, with net debt reducing $19 million during the period. Interim dividend of $0.07 per share has been declared. This is consistent with the guidance at the November Investor Day. I'll now pass over to James to provide further detail on the financial performance, and I'll speak to our operating performance and strategic outlook after that. James.

Thank you, Malcolm, and good morning, everyone. Thanks for joining us today. Now to talk through our H1FY24 performance starting on slide six. While the comparison versus H1FY23 is down, the prior comparable period was exceptionally strong with around 500 gigawatt hours more of hydro inflows enabling flexible thermal generation to step out of the market in that period. As Malcolm said earlier, the Huntley Unit 5 outage also impacted our wholesale performance with the Rankins providing backup, running on gas otherwise used in Unit 5 and providing around 440 gigawatt hours of generation from coal. The Coupe KS9 development and planned November outage also meant lower gas availability and more reliance on higher cost generation and hedging alternatives. So looking at the numbers, revenue was up 19% driven by the higher wholesale prices and momentum across our retail business, especially C&I. GWAP was up from $69 per megawatt hour to $140 per megawatt hour with higher spot prices, resulting in approximately $200 million of additional revenue. Our CNI business performed well retaining volumes while prices lifted $34 per megawatt hour as the forward curve remained elevated. Gross margin, however, was down 16% as the higher wholesale electricity price increased retail purchase costs and portfolio fuel costs were higher due to the change in generation mix. And I'll talk to the details of this plus gross margin from gas, LPG and coupe on the next slide. Operating costs were up 16%, a significant lift, but in line with our plan set out at the November Investor Day and previously. Key drivers of the increase were the costs in relation to Huntley Unit 5, investment in digital projects including our billing, platform upgrade, and inflation across wages, software, and insurance. This will be outlined on slide eight. As Malcolm said earlier, we're making changes to how our retail business operates and moving to a smaller and more focused operation. We're in the middle of this change process right now and expect a modest impact on our operating expenditure this financial year. The gross margin and operating costs resulted in lower EBITDAF, which while down 32% against the strong performance a year ago, is consistent with the expectations we have set for this year. This also meant lower NPAT, and I'll go into more details on a later slide. Capital expenditure was significantly higher, $55 million up, primarily due to the expenditure on the KS9 development at Coupé, as well as ongoing investment in our hydro assets at Tuai and Rangipo. The board declared a dividend of seven cents per share in line with guidance at our investor day. So turning now to slide seven, where we look at the gross margin drivers in more detail. Looking first at electricity, the largest component of our gross margin. As discussed previously, it was down from a record of $358 million to $291 million, largely driven by the change in generation mix. Our portfolio generation costs, i.e. the fuel and carbon costs of generation, divided by total generation volumes, were higher at $56 per megawatt hour, an increase of $28 per megawatt hour. This was driven by the Huntley Unit 5 outage, meaning that less efficient Rankin units were utilized, which resulted in higher running costs as more coal was used and carbon costs were higher. Hydrogeneration was also down approximately 500 gigawatt hours relative to the strong hydro conditions we saw in H1 FY23. On the sales side, we saw more favorable outcomes in H124 with growth in customer volumes and sales prices. CNI rates were up by $34 per megawatt hour as the higher wholesale prices flowed through. And this includes a life-to-date adjustment of $4.9 million due to the accounting treatment of the long-term fixed price contracts. Total volumes were up 4.2%, while sales prices were up an average of 7.8%. Electricity derivative settlement was lower, driven by the expiry of the swaptions at the end of calendar year 22, and lower hedging gains relative to the PCP. Looking now at our coupe gross margin, which is down from $40 million to $29 million, this was expected with the KS9 development ongoing and the longer scheduled maintenance outage in November and declining production volumes pre-KS9. Crude oil prices and volumes were also lower. Turning to LPG, volumes were down slightly across retail, but showed strong margin growth. And this is a trend we expect to continue over the medium term. Although this looks positive at a gross margin level, there continues to be operational cost pressures here due to wage rises and distribution costs. Purchase costs were up slightly with some LPG imports required due to the Coupé outage. Onto gas, we showed steady gains in our gas portfolio despite lower total volumes across both wholesale and retail, as higher value channels were prioritised. Wholesale gas sales were 2.2 PJs lower, while retail volumes were roughly level and prices continued to grow in real terms. Moving to look at OPEX now, we set out our OPEX plan in November and this remains a key focus for the management team as we aim to reduce costs over the long term and attain our FY28 target of reducing operating expenditure to approximately $360 million. You can see on this chart on slide eight, we've highlighted the areas specifically in retail and technology, which are under active review as Malcolm has mentioned. In corporate and coupé, our focus is to contain the cost levels, whereas in wholesale and in digital projects, we're actively investing to achieve our Gen 35 objectives. The digital project investments will be time limited and reducing as we complete our billing, core finance and wholesale technology investments over the next three years or so. So looking at the key drivers, customer and LPG costs increased due primarily to wage inflation and supporting our EV customer proposition. We're in the middle of some key organizational changes in our retail business and expect lower costs to come through in FY25. In wholesale, we saw higher costs in relation to the Huntley Unit 5 outage of $3 million, as well as higher insurance premiums of around $1 million. We're also building our asset development team to prepare Genesis for our renewables build pathway. Based technology, which excludes digital projects, also increased as software support and people costs were impacted by inflation. Digital projects commence with the start of our billing platform upgrade alongside Gentrack and Salesforce. This represents our investment in company productivity and our objective of moving to a low cost operating model. You'll note second half costs will be higher, primarily due to the planned spend on CRM and the billing project. Now turning to look briefly at NPAT on slide nine, NPAT was down considerably from the high level in H1 FY23. The key driver was, of course, the lower gross margin and EBITDAF. We also had a large valuation gain on long-term PPA contracts in the prior period, which was not repeated this year. Finance expenses were roughly level, with higher interest rates offset by a decline in debt levels. So with that, we'll move on to capital expenditure on slide 10. We've made some changes to how we present our capital expenditure by including investment in associates and providing an outline of FY24 expectations. As previously outlined, FY24 is a higher capex year, primarily due to our KS9 investments. On the stay-in-business side, we continue to make several significant investments in our renewables portfolio, including stage three of the 2i generator upgrades and turbine and generator overhauls. These investments will enhance the performance and value of these key assets. There was also a four-yearly outage at Coupé through November. Our investment in associates includes investment in long-term forestry and our solar joint ventures. Looking to the second half of FY24, stay-in-business capex is expected to be higher as we progress the 2i generator upgrades and continue maintenance work at Rangipo. Retail and other stay-in-business capex for the second half will also be higher, driven by investment in depot safety improvements and other essential maintenance. In addition, our investment in associates will be higher as the bulk of the $13 million contribution for Lauriston is invested and further forestry investment is made. Overall, our FY24 capex, excluding associates, will be lower than previously guided, moving from around $165 million to $145 million, with the main changes being reductions in retail capitalization of software, with a knock-on adverse impact on OPEX, reduction in final KS9 costs, and deferral of previously planned maintenance at Huntley Unit 5 due to the outage. Looking now at the balance sheet and cash flow, adjusted net debt is down $19 million to $1.265 billion on the 30th June position, but the lower EBITDAF has meant the net debt to EBITDAF ratio is up from 2.2 to 2.6. This increase reflects the lower profitability compared to the PCP, but it's still comfortably within our target range. Looking at the drivers of the debt position in the chart on the bottom right, the strong performance last year meant higher tax payments. Inventory change was driven by the drawdown of the coal stockpile, which reduced by 231,000 tonnes to 731,000 tonnes, while other working capital relates mainly to lower receivables, reflecting seasonal change. The investment of cash flows of $80 million, which includes KS9 and the higher stay in business capex in the period, while interest payments of $40 million were similar to the PCP. Our cost of funding was up as the cost of debt was unsurprisingly higher, an average of 5.7%, while our hedge position remains at 66%. With that, I'll hand you back to Malcolm to discuss our operational performance and strategic outlook.

Thank you, James. Now turning to our operational performance, starting with our customers and the strong growth we've seen during this period. The period continued to see strong customer growth across both brands, an increase of nearly 9,500 customers in the period. Retail sales were also higher, up 4.2% across residential, small business, and C&I. Our Frank brand delivered the highest customer growth of any retailer in the period. While over the long term we have seen residential electricity consumption per person decline, EVs are a strong growth opportunity, with the average EV customer consuming 40% more kilowatt hours per year than other customers. We continue to focus on EVs, adding over 2,600 customers during the period. One of the drivers during the period as we went through material change processes was both customer growth and quality of service. We have seen improvement in both service and satisfaction metrics. Moving to slide 15, the resilient portfolio. Hydro conditions return to more normal settings during the period, and the graph at the top right of this slide shows the corresponding 500 gigawatt hour decline in renewable generation. The unplanned outage of unit five and other thermal plant can be seen in the changes in gas and rank and use for demand from both Genesis and other retailers. What also stands out is coal was once again the fuel of last resort to back this up during the period. As we indicated at Invest Today, we are accelerating our efforts to displace coal with biomass where we can. However, gas availability and flexibility is unlikely to be sufficient to displace much coal. And while biomass may displace a good amount of coal in a P50 year, it may not be sufficient to fully displace coal in dry years, or dry years with unplanned outages, or dry years, unplanned outages, and major natural disasters. especially if that disaster disrupts South North Flows. The graph on the bottom left shows the current North Island energy storage available to the electricity system. With the coal stockpile, Huntly is 60% of North Island energy options. With uncertainty over new generation development timelines, ageing thermal plant and a tight gas market, there are now a number of potential scenarios in play that could see the current coal stockpile being materially depleted within the next 12 months. We are committed to putting new market security products into the market over the next year to ensure the market determines what level of energy storage and system security should be represented in any future coal stockpiles at Huntly. Turning to slide 15, a further update on Huntly Unit 5. Firstly, it's great to have New Zealand's largest and most efficient gas generation power plant back operating. Up until the outage, the plant ran at over 98% reliability since its commissioning in 2006. The Huntly team worked hard to return the unit to service and bring a complex repair job to completion four months earlier than originally anticipated. The overall cost of the outage, net of insurance, is expected to be between $20 and $25 million EBITDAF. As we've said previously, the outage was caused by a failure in one of the three generation circuit breakers, also known as GCBs, a highly unusual event and potentially the first in the world. This is part of the reason why the manufacturer did not recommend holding these parts on site as spares. There have been multiple investigations into the root cause, but no consensus among experts at this stage. What we do know is the outage was not caused by maintenance or by material design defects in the GCB. Despite this being a rare event, we're taking sensible precautions to prevent or limit the impact of this happening again. All three phases of the GCB have been replaced and spare units have been purchased and will be stored on site. Turning to slide 17, our carbon emissions and our health and safety performance. Consistent with the theme of this presentation, H1FY24 contrasted with the prior period. Market conditions and the Unit 5 outage meant that our generation mix changed and coal was used as a fuel of last resort to back the system up. We want to be open and transparent about our emissions. So six months ago, we reported record low emissions. We were careful to say that there were factors beyond our control that drove them down. Likewise, this emissions profile in this period were higher due to factors also out of our control. Although the path to emissions decline will be bumpy, we are committed to it. Gen 35 is a plan to get to 95% renewable generation, and our Lauriston Solar project is a great example of a first step in this process. Touching briefly on health and safety, It's pleasing to see a sustained reduction in lost time injuries as we focused on early intervention and supporting recovery. Now turning to our strategic outlook. I'd like to reiterate the main points of Gen 35 and provide an update on progress since we launched the strategy to the market a few months ago in November. Slide 18, New Zealand is world class in terms of the level of renewables in our system. However, whether you live in remote Northland, in the centre of a city, or in rural South Island, the reality is every customer and every retailer and every generator on the grid relies on thermal generation for security of supply at some point, regardless of whether that is Genesis or another thermal generator. While developing Gen35, we tested deeply what is the most impactful thing to focus on for NZ Inc. to get to net zero 2050. Regardless of whether our electricity system is 90%, 95%, or 100% renewable, Moving the country from 40% electrification to 70% by 2050 was the single most important objective for all of us to focus on delivering. Anything else is simply a distraction. As the graph shows, Genesis customer need for the Rankin units has been trending down for the past five years, while demand from third-party retailers has been fairly consistent. Around 60% of rank and running over this period has been to service customer demand from third party retailers. Genesis has had to account for and report 100% of these emissions and as such has had 100% of the ESG discount and 100% of the responsibility for those emissions attributed to it. 70% electrification is the sector and the country's impact zone for net zero 2050. Solar and wind will need to do the heavy lifting to get us there, but they can't do it securely without some thermal firming and peaking, and every home and business in New Zealand will benefit from that, no matter where you live and work across the country. We are committed to putting new firming and peaking products into the market over coming years to ensure the Huntly portfolio can support more solar and wind across hours, days and weeks and support the hydro system across months. Genesis capabilities on slide 19. Demand is the scarce resource in the net zero 2050 transition, meaning strategic value accrues to the demand side, while financial value accrues to the supply side. With half a million customers, Genesis has a strategically strong demand side position with large diversified long-term customer revenues. This opens optionality and de-risks future upstream investment in new renewables. With plenty of new intermittent renewable options waiting to be developed across the grid, our strong customer position is further supported by our strong flexibility position. We confirm solar and wind at scale across days, weeks and months. Genesis has the future revenues and flexible assets to be a most desirable investment partner to bring those new renewables to life. The third leg to our strong strategic position is our BBB Plus credit rating. When it comes to deploying future capital, Genesis has the most optionality of any generator across a portfolio of investment structures, including pure PPAs, joint ventures with PPAs, or fully owned on our own balance sheet. Turning to slide 18, the horizons of our transition. While we are taking a long-term view, we have set out several steps along the road to 2035. The first, which is underway right now, is sweeping our own front yard and building the team and capability for the future. This means ensuring our people and investments are aligned to our long-term goals. The second horizon takes us out to FY28. We've set 11 goals to transform Genesis, as well as making investments that will accelerate the company towards our Gen 35 targets. Beyond this is our future state, Horizon 3, when we will look to make significant but rational investments in new renewables to see us reach our goal of producing 95% renewable generation by 2035. Turning to slide 19, our future fit changes. As I said earlier, we are implementing operating model changes to our retail business. The changes we set out in November are well underway and in line with our expectations of an approximate reduction of 200 FTEs across retail and technology. 70% of these reductions have now been confirmed to occur in FY24. We have now completed consultation and we are focused on closing out the restructuring process and supporting those impacted from our team. We are also busy implementing the upgrade of our billing and CRM platform with Gentrack and Salesforce. This is key to the next phase of productivity gains. The first phased release will occur for Frank Energy in FY25, with subsequent releases for the Genesis brand through to the end of FY26. As outlined at Investor Day, there will be time-limited operating costs invested in this project, but the new system will enable further simplification of our retail business, driving us to lower cost to serve and facilitating participation into new income areas of energy retailing. Turning to renewables development, we were pleased to reach FID on Lauriston. We continue to target mid-year for FID on a 100 megawatt battery system, stage one of a 400 megawatt battery program at Huntly. We are adding capacity to deliver our planned solar pipeline and options for wind. Turning to slide 22, our FY28 scorecard. As we outlined in November, we've set 11 goals across retail, Huntly Renewables, and financial performance for Horizon 2. We will show you progress on each of these, each reporting period, to provide the market with transparency as we deliver and activate Gen 35. At this stage, just a few weeks after we launch these goals, naturally they are all on track. We were mindful to set ambitious yet achievable goals. There will no doubt be challenges along the way and a full set of green lights will not be normal, especially in areas that are new to Genesis or New Zealand. We've also included now in our scorecard our net zero by 2040 ambition to demonstrate our commitment to this important target. Turning to slide 23, Genesis as an investment. So as a reminder from our strategy day, we see Genesis changing as an investment. We're creating shareholder value from the transition within the transition. We're moving from a model with a low growth outlook and a high dividend and ESG discount to a balanced growth, yield and diminishing ESG discount profile. We're transitioning Huntly from being Rankin's burning coal to a portfolio of grid scale firming and peaking services with products across hours, weeks, seasons and disruptions. We're growing from 60% renewable generation with a pure PPA-focused displacement strategy to being 95% renewable, driven by a portfolio of new generation delivered on balance sheet and through partnerships. We're changing our in-house technology-centred retail strategy to a low-cost, light-touch retail strategy that prioritises customer electrification and value through deep partnerships. I'll now hand back to James to discuss Coupé and the outlook for FY24. James.

Thank you, Malcolm. As many of you know, Genesis and our joint venture partners invested in the KS9 development at Coupe. The work was completed in December and we were pleased to have the well drilled on time and within budget. Right now, the operator is continuing commissioning activities, including well cleanup and full system performance testing. This will take some time, and we're in a period of uncertainty on the final outcomes related to KS9. The new drilling will provide additional information on reserves, and we expect to have more details by the end of the financial year. Turning to slide 25, FY24 EBITDAF is expected to be around $430 million subject to hydrological conditions, gas availability, and any material adverse events or unforeseeable circumstances. As previously announced, Huntley Unit 5 has returned to service. The financial impact of this event is estimated to be in the range of $20 to $25 million EBITDAF net of expected insurance proceeds, and this is included in the EBITDAF guidance. Operating expenditure for FY24 is expected to be around $380 million, and capital expenditure for FY24 is expected to be around $145 million. And as noted at Investor Day on 30th of November, 2023, FY25 EBITDAF outlook remains around $500 million. This is subject to hydrological conditions, gas availability, and any material adverse events or unforeseeable circumstances. So with that, we'll now hand over to the call operator.

Just before we do, James, just one final thing from me. We announced that James has made the personal decision to return to Australia with his family. And on behalf of the company, I'd like to acknowledge James's input and effort in Genesys over the time that he's been with us, particularly his input into developing Gen 35. We're naturally disappointed to see him return to Australia, but we certainly acknowledge the rationale that he's gone through in terms of making that decision. So we wish him and his family well. The board and myself have commenced a recruitment process for a replacement for James, and we'll keep you informed as we move through that process. Thank you, James.

Thank you very much, Malcolm. So with that, we'll hand over to the call operator for questions.

Thank you. Ladies and gentlemen, if you'd like to ask a question, please press star 11 on your telephone. Again, to ask a question, please press star 11. One moment for our first question. Our first question comes from the line of Grant Swanepoel of Jordan. Your line is open.

Hi, can you hear me? We can, Grant. Yep.

Thank you. First question on coupe. Beach had set out to expect an uplift from 50 TJs a day to about 77 TJs a day. That slide you put up looks like under 60 TJs a day. Are you guys concerned that you might have to put in a second drill and that this resource isn't what it's made out to be?

Thanks Grant, I'll take that one. We have no plans at this stage for any further drilling. Let me just be very clear about that. We are running through a process of commissioning and well clean up, that takes some time. and we will analyze the results of the new data that we get with the access to KS9 and that's going to take some time and until then we are going to remain silent and wait until we've got substantive analysis that enables us to make a comment. The process does take some time. We expect that to take several months. Certainly we would expect to report further by the end of this financial year.

Thanks. To follow up from that, the extra $70 million from this year to next year's soft guidance, can you talk through where that's coming from, from coupe, uplift from having 30% off this year, Unit 5 return, some sort of OPEX reduction, and what you're expecting from Lauriston and the change in supply from a bit of PPA from the geothermal from contact?

Yep, I'll take that one, Shai, okay. Yep, thanks for the question. Again, look, we set out in November at the Investor Day an outlook for FY25. The drivers of the increase were set out at that time and remained the same. So the key drivers will be the expectation that Tohara is that the PPA will be on stream from the 1st of January, 2025. We expect Lauriston, obviously confidence increased now that we expect Lauriston to come on stream. By the end of this financial year, we have a PPA connected with that. OPEX, if you look at the numbers we provided at Gen 35, will not be a driver of an improvement. We actually expect to spend a higher number on OPEX in FY25, and that's driven primarily by the increase on digital projects. And then we have margin expectations elsewhere in our business that we expect to feed through to that overall increase. Obviously, we've got a detailed operating plan to go through over the coming months in April, May, and we'll provide further information, I would expect, at around August time in terms of FY25. Thanks.

And just one quick one on how much of lost constraint rentals and income did you guys get this year relative to zero in the past?

Sorry. Constrained income.

Grant, we don't publish that number. And I wouldn't have that right off the top of my head.

And the last question, it's more around, you've often indicated that you're not getting rewarded for capacity to the market. But with Unified Art, you can see in your first half you've dropped almost $50 million because of that excluding the insurance. Does that not point to that actually you are getting rewarded for keeping these big machines around?

I don't think that we would see it that way. There are multiple ways we could have covered that, and for us, running the Rankins was the optimal way, particularly given the gas that we had. forward casting. Our view is that the market is not adequately supporting those rank and assets and the fuel to run them for us to assume any contribution to profit beyond FY27. Thanks.

That's it for me. Thank you.

Thank you. One moment, please. Our next question comes from the line of Cameron Parker of Craig Investment Partners. Your line is open.

Hi, guys. Thanks for the presentation. Just going back to Cooper, I was just wondering if you could talk to your decision process around around an unfavourable outcome for the reserve assessment. So if reserves are down, what does that mean for your portfolio and decision-making going forward through to later on this decade and early in 2030?

Do you want to take it? Look, I'm happy to speak first. Thanks for the question, Cam. When we announced the Gen 35 programme in December, we were very clear that we had set up the balance sheet structure. We had planned, in terms of our capital structure, to have a very strong... investment grade rating. And we saw then that we planned for our debt to EBITDA to be in the 2 to 2.5 range, which is comfortably inside the BBB plus range. And the reason for that is to give us a robust position to execute on the strategy in a wide variety of scenarios. I'm not going to make any further comment on KS9 until we have a greater level of information and data on it. But the purpose of setting up our balance sheet structure in the way we did is to enable us to be able to execute on the strategy and have the funding available to finance the significant investment program we have. you know, withstanding a number of different scenarios that might occur.

Okay, Greg, please come forward with the flexibility you've got looking out there. We are at this stage, Cam, yeah, absolutely.

Okay, thanks, guys. Just on Unit 5, I just wanted to clarify whether there was or was no link between Unit 5's failure and the change of operating regime that's been employed over the last couple of years.

There's no evidence that has brought that, no. So we've ruled that out as a causal factor.

Okay, great. And just the last one from me, you've gained some great yield uplift in terms of your C&I pricing. Where do you think that heads over the next couple of years? Do you think it's peaking now and potentially comes back in the near term or medium term? Where's your view on that C&I pricing going?

Cam, I'll take that one. Look, I wouldn't want to give any forward guidance on pricing, but what I will say to address the question is that CNI pricing does correlate with wholesale prices and forward prices, as you know. So I think the direction of the forward curve will be a key determinant on what happens to CNI pricing in the medium term. Obviously, we've got visibility on the forward curve over the next three or so years. But equally, obviously, that can change. But I would say that will be a key determinant.

Okay. All right. Thanks, guys. That's all from me. Thanks, Kim.

Thank you. One moment, please. Our next question comes from the line of Ganesh Nair of UBS. Your line is open.

Hi. Good morning, team. Just two questions for me today. First, on solar, I suppose you've got 500 megawatts as your target, excluding Lauriston at sort of 460. I think, you know, from the CapEx program updated at the end of last year, you're sort of talking to most of the spend coming through in 26 and 27. But are you sort of able to talk to any progress you've made on sort of acquiring new sites, especially with the partner FRV? What's the sort of latest update been with building out that solar pipeline?

What we've indicated, and it's reflective in the OpEx commentary that James gave, is we are investing heavily in building that development team. That development team is exceptionally active. There's a number of activities happening across that pipeline, but we don't have anything further to announce at this point in time.

Can we expect something this calendar year on a new solar side, or is that slightly ambitious for delivery in 27, 28?

I wouldn't put a timeline on it. What I would say is the potential changes in the consenting regime may ultimately be quite influential to the answer of that question.

Okay, that's clear. And the second one was just around OPEX, obviously a fairly healthy lift. And I suppose the guidance into the full year kind of implies $199 million into the second half. And I think James earlier was talking to, I suppose, a sequential increase into FY25. Is it appropriate to take that $199 number and double it into 25? Or would you expect to see some kind of buffer provided sort of employee costs go down into 25?

Look, I think the best way to look at our OPEX for next year, and obviously we'll work through an operating plan over the next little bit of time, but if you recall at the November investor day, we gave really quite specific outlook on OPEX by year. And the best thing you can use is what we said in November. I would highlight that there is significant one-off expenditure, or when I say one-off, significant digital spend related to the major digital projects that we are that are ongoing that will be time limited so it's you know it's It's important to view our OPEX in the context of how that expenditure will change over time. The specific number that we put in the investor day materials for FY25 for OPEX was $393 million, and we don't have any further update on that at the moment.

Okay, that's fair. Thanks, guys. That's all. Thank you.

Thank you. One moment, please. Our next question comes in the line of Steven Hudson of Macquarie Securities. Your line is open.

Steven Hudson of Macquarie Securities Good morning, Malcolm and James. I've got a couple of questions, mainly for James, I think. Just in terms of the 430 guidance, could you give us an indication of whether or not you provided for an insurance receivable in that guidance in terms of business interruption on the Unit 5 outage?

Yes, the 430 million includes our expected proceeds for insurance. There is no insurance receivable booked at December 2023. because the rules are we have to have virtual certainty and we did not have that at December 2023. I would draw your attention though to the comments that we made on slide 15 of the investor pack. Specifically, we said that discussions with insurance have been positive and we expect confirmation of indemnity from all insurers. The stage we're at at the moment is around verification of the claim amount. We're actively involved in that at the moment. Obviously, there are some complexities in verification of the amount, so that happens after return to service, and we expect settlement within 2024.

That's useful, James. And what sort of $40 or $50 million would that be ballpark?

Look, we haven't actually said that number, said what it is. So I think the best way to think about it, Stephen, is that the 430 is after the expected proceeds and recording the loss on... We do have deductibles, so obviously there is a retained element to that. And that's where the estimate of 20 to 25 million for the overall impact of the Unit 5 outage comes from.

Okay. And then just on the retail and IT restructuring projects, the restructuring costs associated with Vant, are they expected to be in FY24 and taken above or below the EBITDA line?

Yes, that's a good question. We expect them to be in FY24 and they are within the OPEX guidance that we've given of approximately $380 million for FY24. We're not going to try and call them out as separate. We may tell you what they are when we've completed the exercise, but you can assume that they will just sit in our underlying OPEX.

Thanks, James. Sorry, just a couple of quick ones. You've revalued your generation assets. It's a bit of an old chestnut, but $143 million, and it sounds like it's largely due to your wholesale price view. Can you share with us any... feel for where you think long-term wholesale prices are going? It's a topic du jour at the moment.

Yeah, I'll speak to that. I won't give an update on wholesale prices. I mean, we gave some information at the Investor Day. What I will speak to is the revaluation and a key... driver there was the changes in the date on the expectation of when Unit 5 returns because if you recall we originally said that we expected Unit 5 to return in May and obviously as we moved between reporting periods that assumption changed to an earlier date and that was part of that. So I wouldn't read too much into that being a significant change in view on the wholesale prices, which we provided back in November.

Okay, point taken. And then just, I suppose, a personal question. We've watched with interest the changes that the government or the old government have made on the Crown Minerals Act and sort of fairly draconian provisions around director liability, trailing criminal director liability for oil and gas permit holders. You sit on the Coupé Venture board. Can you give us a feel for just out of step some of these moves have been versus international best practice.

Look, I think that that would be difficult to speak to at the moment. Obviously, as a director, I'm conscious of obligations, but I don't really compare them to international other jurisdictions. We are obviously very focused on meeting and exceeding the obligations that we have as directors.

Okay. Best of luck, James. Thanks very much. Thanks very much.

Thank you. One moment, please. Our next question comes from the line of Nabil Goliath of Georgia.