Channel Infrastructure NZ Limited (CHI) Earnings Call Transcript & Summary

Thank you for standing by and welcome to the Refining New Zealand 2020 Full Year Results Conference Call. [Operator Instructions] I would now like to hand the conference over to Refining New Zealand Chief Executive Officer, Naomi James. Please go ahead.

Good morning, everyone, and welcome to Refining NZ's 2020 Financial Results Briefing. I'm Naomi James, the CEO of Refining NZ, and I am joined by our CFO, Denise Jensen. Before getting started, I draw your attention to the disclaimer upfront in the presentation on Slide 2. The briefing today will effectively be divided into 2 parts: the first, a briefing on our 2020 performance, and then moving to an update on our strategic review process and the potential import terminal conversion. Please turn to Slide 4. Starting first with 2020, where we have delivered what we set out to achieve in a very challenging environment. We will go through the detail as we walk through the pack. But in summary, despite having had our most challenging year as a business, we have also had our safest year on record. We quickly changed how we operated our facilities to respond to unprecedented drops in demand from COVID. We reset the cost base of the business to operate cash neutral at the fee floor through the year. We increased our liquidity and extended our debt. We undertook a strategic review. And coming out of that review, we have now implemented the near-term plan of a simplified refinery while we continue to negotiate with customers on the long-term plan for a potential conversion to an import terminal. So we have kept the refinery operating safely, strengthened the resilience of the business to a low-margin environment, and we are working hard to reach a conclusion on long-term plans, which will lead us back to delivering returns to shareholders. Please turn to Slide 5. This shows a snapshot of some of our key metrics. Our safety performance was strong. We delivered to customer plans, which were significantly impacted by COVID. And we reset our cost -- cash cost base to fee floor levels through reduced OpEx and CapEx and finished the year with lower net debt than the prior year. Now to run through the details of our 2020 performance. Turning to Slide 6 and starting with safety, as we always do, we had no recordable cases and no process safety incidents in 2020. This was a significant achievement, given we operated the plant in cyclic mode for 3 months, effectively turning units on and off in rotating cycles to reduce production and then put the full plant on hot standby for 6 weeks, bringing all units back up to help balance fuel supply across the country. From these changes and the simplification changes we made at the end of the year, we have had a very strong focus on risk management and management of change in our operations. I want to recognize all of the team on-site for these results. They are a real demonstration of the capability we have. We were very proud to have our employee-led E Tu Tangata safety culture program recognized at the 2020 New Zealand Workplace Health and Safety Awards. This program is key to our strong involvement of employees on-site in ensuring we have safe operations. And we have made good progress in relation to renewal of our resource consent for the Marsden Point site. Please turn to Slide 7. Refinery and RAP throughput were both impacted by the COVID-19 travel restrictions and we're around 30% lower than 2019. You will see from the chart on the bottom left-hand side the impact that the lockdowns have had. Prior to this week's lockdown, petrol and diesel demand had recovered to pre-COVID levels while jet has remained low at 30% to 40% of pre-COVID levels. Through that first nationwide lockdown, we needed to find a way to reduce our production to half of normal rates almost overnight, and we were able to do this. This required us to change how we operated the refinery to align production with reduced demand and to minimize jet production. Jet would in normal times be around 1/4 of what we make. We have been able to wind that all the way back to close to 10%, which has importantly avoided the need for our customers to export jet fuel for much lower prices. These results have been an outstanding achievement by our dedicated and capable workforce, many of whom agreed to take leave while the refinery was on hot standby. Please turn to Slide 8. The story on refining margins hasn't really changed through the year. We have had negative Asian margins due to excess refining capacity and COVID-19 impacts on demand, with the Singapore complex margin averaging the year at negative USD 1.65 per barrels, and a lower than historic uplift on the Singapore complex margin due to volatility in shipping, impacting freight benefits, and cyclic mode and hot park impacting yields. This has resulted in the refinery earning an average GRM for the year of USD 1.63 per barrel, which is the second lowest GRM in the 25-year history of the processing agreements. The fee floor has increased the realized GRM to an amount equivalent to USD 4.40 per barrel, reflecting both the low margins and lower throughput during the year. I will now hand over to Denise to take us through the financials.

Thank you, Naomi, and good morning, everybody. Let's pick up on Slide 9 of the presentation and start with a snapshot of the financial results. As Naomi mentioned, refinery and RAP throughputs for the year were down around 30% on the prior year, and refining margins were down more than 70%. In the refinery revenue, you can see the protection the fee floor has provided against those impacts, with refinery revenue down by only 36%. Our infrastructure revenue was down 5%. This was less than the drop we saw in RAP throughput because of the higher per barrel rates being charged on pipeline volumes and terminalling income earned during the year. Pipeline charges are expected to increase again in 2021 due to an increase in the notional freight rates. While total revenue was down around $103 million on the prior year, adjusted EBITDA, which really means EBITDA adjusted for noncash items, was down by $63 million, reflecting the cost reductions we made and partly offsetting the decline in revenue. A net loss after tax of $198.3 million as reported, including the previously reported impairment of around $158 million. I'll come back to CapEx, but before we leave this slide, I want to highlight free cash flow and net debt. Free cash flow was an inflow of $11 million, which allowed the company to reduce net debt to $231 million at the end of the year. This reflected cash-neutral operations from April 2020 onwards, and optimization of the balance sheet through $13 million worth of asset sales, the proceeds of which were used to fund restructuring costs in relation to the refinery simplification. Please turn to Slide 10. This slide provides a waterfall between EBITDA for the year ended 31 December 2019 to full year 2020. You can see the split between the margin and volume impacts on refining revenue, both have been significant. And then the additional protection we have had through the fee floor, with fee floor payments from our customers amounting to around $90 million. The fee floor payments increased the gross refining margin by around USD 2.77 per barrel. Although pipeline volumes were down by 29%, infrastructure earnings were only down 5% due to an increase in the fee per barrel charged on throughput and the impact of terminal fees charged amounting to $5 million additional revenue in the year. We also see the benefit of our cost reduction program, which I'll talk to further on the next slide. So let's turn to Page 11. I wanted to now focus on the action we took in response to the significant reduction in both throughput and margin. We acted quickly and decisively to reset our cost base to operate within the fee floor, reducing our year-on-year expenditure by around $80 million. The recession 2020 cash breakeven to fee floor levels required a whole of business response and strong financial discipline. This was achieved through a combination of both short-term measures by stopping and deferring all nonessential work and reduce the variable costs due to the lower throughput. And through longer-term structural changes, including a reset of our turnaround philosophy. Operating costs were down by $35 million or $24 million net after allowing for about $11 million of one-off costs. Savings were achieved in electricity and chemical costs due to the, as Naomi explained, the cyclic operations and through the hot standby and the deferral of nonessential work and renegotiation of a number of contracts. Capital expenditure was reduced by around $44 million, following changes to asset management strategies and the deferral of the platform and crude destination turnaround into the current year. Please turn to Slide 12. You'll see the impact of the action we took on our net debt position, which was down $10 million to close at $231 million as at 31 December 2020. We've once again provided further detail on our covenant position, and you will see that our 3 financial covenants on this slide, despite being at the fee floor for the full year, we had significant headroom on both gearing, which is shown after the impact of the impairment, and interest cover. Now to Slide 13. The company took early action to strengthen the balance sheet by increasing and extending bank lines, providing significant debt headroom with no material near-term maturities. The company's net position at the end of the year was $231 million, and we have around $125 million of liquidity, excluding the debt maturing within the next 12 months. In December, the remaining $100 million worth of interest rate swaps that we had in place dating back to the Te Mahi Hou project rolled off. This is expected to provide us with further covenant headroom next year as we benefit from the current lower floating interest rates. The average interest rate in 2020 was 5.3%, down from 6.1% in the prior year. I'll now hand back to Naomi.

Thanks, Denise. We now move into the second part of today's presentation, which provides an update on our strategic review and on slide -- starting on Slide 15 of the presentation. You will remember in the first phase of our strategic review process last year, we looked at all the options for operating a refinery in New Zealand, and we looked at the alternative of converting to an import terminal. We also engaged our stakeholders for their views, including our customers and the New Zealand government. At the end of June, we announced we were taking 2 options forward. In the short term, a simplification of the refinery to enable us to operate cash neutral at the fee floor based on an expectation that we were in an extended period of low margins as has proven to be the case. The simplified refinery has now been implemented and operating from the start of this year. The second option that we took forward in parallel was a potential future conversion to an import terminal. And today, we can give you an update on what has come out of our assessment of that option to date. To overview the key points we will talk to, we now have an understanding of what an import terminal would look like in terms of cost and time and have initiated feed and detailed planning works to confirm our initial cost and time estimates and develop detailed plans for how we would transition from refinery operations to import terminal operations. We have been negotiating with our customers what a commercial framework would look like for an import terminal. And we have been engaging with our lenders on what such a transition would involve from a funding perspective. Our current expectation is that no additional equity funding would be required. Today, we will also touch on the impact that conversion to an import terminal would have to our emissions, which could be a significant contributor to New Zealand's emission reduction targets. I am pleased to announce today that we have reached in principle agreement with one of our customers, BP, on the commercial terms for an import terminal, including price. And we continue to actively negotiate with Z and Mobil to reach agreement with them as well. It's important to note that the decision to move to an import terminal would be a decision for shareholders and that our noncustomer shareholders would need to approve the new commercial arrangements with customers. We will also take you through the indicative time line for a conversion and the steps involved, which has the earliest possible date for conversion in 2022 if we were to reach agreement with all customers by the end of Q1. Turning to Slide 16 and starting first with our refinery simplification plans. This slide gives you a snapshot of what has been involved in simplifying our operations, which has been a significant exercise. We have ceased operation of the smaller of our crude distillation units, reducing crude intake capacity by just under 20%, and we have ceased bitumen production. We have changed our asset maintenance strategy, moving to a campaign approach and a 2-yearly turnaround cycle, which has us undertaking smaller, shorter, more regular turnarounds, which we can fund within the fee floor as we are doing this year. Through these changes, we have applied a very disciplined approach to both risk management and management of change. Simplification delivers a significant reduction in both OpEx and CapEx compared with previous levels. We have also undertaken an organization-wide restructure with headcount reducing by around 25%. This has involved significant change for our people and how we work, and we have put a lot of focus and effort into supporting all of our people who are impacted by those changes, with great results coming from that so far in terms of helping people transition into new jobs. Turning now to the import terminal in Slide 17. This slide shows our current thinking on what an import terminal would involve. In summary, 3 billion liters of annual throughput capacity supplying the Auckland and Northland market, which make up around 40% of total New Zealand fuel demand. This would primarily use existing tanks and facilities with conversion of some tanks and upgrades to piping, tank bunds and fire protection systems. It would not require all of our site or all of our tanks. In fact, about 80% of the existing tanks and about 65% of the usable land at Marsden Point would not be required. And we think there is great potential for repurposing. It's a large industrial site with deep harbor and jetty access, large electricity and gas connections and proximity to the largest population base in New Zealand. These opportunities include increased fuel storage that is likely to be native in New Zealand from a security of supplies perspective if we no longer have a local refinery and the crude oil stocks that it holds. Moving to Slide 18. Decarbonization and carbon budgets are a key priority today in New Zealand. And we want to make sure the business we have coming out of the strategic review is one that is sustainable today and into the future. Starting with our direct Scope 1 and 2 emissions from Marsden Point operations, they would reduce by more than 1 million tonnes per annum to a minimal amount with the potential to move to net-zero emissions if we were to develop the Maranga Ra solar project. Importantly, the import terminal system would be the lowest emission option for fuel delivery into the Auckland market compared with road transport of fuel coming in through Mount Maunganui. We have also thought about how our infrastructure can support future changes in fuel demand. And the Climate Change Commission's recent draft advice to government gives some helpful direction on this. Jet fuel and diesel would make up around 70% of throughput, assuming a return to more normal pre-COVID demand. Those are the fuels that will take a longer period of time to develop viable alternatives for like biofuels and sustainable aviation fuels. And we think our infrastructure can play a role in the future as those alternate liquid fuels become viable at scale. I have touched on already the potential we see in the Marsden Point site, and we have listed here just some examples, ranging from the production or import of biofuels and sustainable aviation fuels, LNG imports if needed in the future for electricity security of supply, hydrogen imports and electricity storage in batteries. In the next stage of our work, we want to start looking at what are all the opportunities for repurposing and then narrowing our view around what are the best of those options. Turning to Slide 19 and touching on our current estimates of both costs involved in a conversion as well as ongoing costs of operating as a terminal. Our current estimates are that a conversion would cost around $200 million, and those costs would be phased over 4 to 5 years with about 50% spent before conversion and 50% spent after. Those costs include the cost of decommissioning the refinery, workforce changes and upgrades to our terminal facilities. Our current estimate of ongoing OpEx and CapEx costs post-conversion is $35 million to $40 million per annum. In addition, we have estimated future refinery demolition costs in the order of $50 million to $60 million. We would consider the right timing for that work as we work through repurposing options for the site. One important thing to note is that a conversion would generate significant tax losses, which we currently estimate could be in the order of $350 million, adding to around $50 million of tax losses we have today, so of significant value to that potential future business. Our work is continuing to refine and verify all of those estimates. Turning to Slide 20 and the commercial arrangements for an import terminal. On the left-hand side of this page, we've given an overview of what we operate under today, the processing agreements that have been in operation for the last 25 years. And then on the right-hand side, the matters we are working through in negotiating a new commercial structure with customers for an import terminal. To move from the left to the right, we need 2 things. We need the parties to the existing processing agreements to agree to new terminal services agreements, and we need our shareholders to approve those terms, with that decision being informed by an independent expert report opining on the fairness of the arrangements to noncustomer shareholders. We know from our engagement with customers through the strategic review process that it is their preference to move to the import terminal model, that the refinery model exposes them to the volatility of refining margins, they have significant working capital tied up in crude inventories and they have costs that importers they compete with don't have like the people obligations and coastal shipping costs. So there are benefits for customers in making this change. Price is unsurprisingly one of the key areas of negotiation. We have done significant work preparing for these negotiations, and that includes looking at the alternative fuel delivery costs into Auckland and return-based analysis. The terms we have been working to negotiate are a long-term initial agreement that can underwrite the investment RNZ shareholders are making in the cost of conversion and in walking away from a refinery business model, a combination of fixed and variable fees, targeting total estimated fees of circa $100 million per annum across the initial term and provision for third-party access to unutilized RAP capacity. I'm pleased to announce today that we have reached in principle agreement with BP on the key commercial terms, including price. And those terms are in line with what we are targeting. Negotiations are continuing with other customers, and we are focused on agreeing terms that are both fair to our noncustomer shareholders and acceptable to customers. Turning to Slide 21. We have put together an indicative time line based on the work we have done so far, showing the key steps and timing involved in the transition. You will see there are 3 phases to the process. The first phase where we are right now is focused on determining whether or not we can reach agreement with customers regarding the commercial framework for an import terminal. The second phase is focused on approvals, lender approvals, shareholder approvals and preparation of the independent expert report in support of the shareholder approval and negotiation of detailed legal agreements with customers, all of which are needed before a final investment decision is made. We have also started and will continue through the approval stage our feed and detailed planning, which we would need to have completed before any final decision is made. We've estimated the timing for that approval stage to be in the order of 4 to 6 months. Once the final investment decision is made, the next phase is then focused on running a refinery through to closure and processing and cleaning out the product on-site. Undertaking the work we need to have done for the commencement of terminal operations and preparing our organization and workforce to operate as a terminal. And we have estimated the timing for that stage of work to be in the order of 9 to 12 months. And then after the point of commencement of import terminal operations, there is further work to be done in terms of refinery decommissioning and decontamination and works on the import terminal facilities. Based on this time line, the earliest possible date for terminal conversion would be sometime in 2022 if we reach agreement with customers in the next couple of months. You will see from the line at the bottom, as we talked about earlier, that we are wanting to start now looking at opportunities to repurpose the Marsden Point site and also looking at broader growth opportunities for the company beyond the Marsden Point site. Turning now to Slide '22. So the next steps for us on the strategic review. We are right now focused on embedding our simplified refinery plans and undertaking the turnaround, which will set us up to run the refinery through 2021. On the import terminal, we are focused on concluding commercial negotiations with customers, with the aim of reaching term-shared agreement with all 3 by the end of Q1. And we are continuing our FEED and detailed planning work. We are working closely with local and national government and agencies and making sure we are planning well in advance for future changes to ensure we can have a smooth plan transition where we support our people through that transition and minimize the impacts for the Northland region. There is still a significant amount of work to be done before any final decision can be made. The earliest date for a transition to an import terminal is 2022. And while customer negotiations are ongoing, we continue to do everything we need to do to operate the refinery safely, including preparing for the 2022 turnaround of the hydrocracker. So moving on to the outlook for FY '21 and wrapping up today's presentation, please turn to Slide 24. Starting with refining margins, we see refining markets remaining challenged in the near term. While we have improved off the lows we saw through the middle of last year, demand continues to be impacted by COVID-19, particularly jet. And we continue to see an oversupply position in refining capacity in Asia, with significant closures required to return utilization to more normal levels and a recovery in margins. For these reasons, we expect to see margins to remain low through 2021, and we are working on the basis that we continue to operate at fee floor levels. In terms of demand, we have seen land fuel demand return to normal levels, subject to the duration of the current lockdown, but jet demand continues to be significantly impacted by the border restrictions, and we don't see that recovering until border restrictions are relaxed. We are commencing next week our turnaround for the platformer, and crude distillation unit 1. And we will have all facilities temporarily shut down through to the end of March. So that is our focus right now on-site. We have COVID management plans in place to ensure we can undertake that work during a period of lockdown. Turning now to Slide 25 and wrapping up with our key priorities for the year. First and foremost, we are running a refinery until we are not running a refinery, and that is our main focus on-site. Last year, as we worked through a major reset for our organization, we focused our team around getting the 3 basics right: operating safely, meeting our customer commitments and operating within the fee floor. We did that through 2020, and we have a plan to do that again as we run the refinery through 2021. That starts with our turnaround starting next week and executing that safely, on time and on budget. And continuing the financial discipline through the year that we now have in the business to operate within the fee floor. At the same time, we are continuing to negotiate with customers on the import terminal option and are targeting concluding those negotiations with all customers by the end of Q1 and progressing the required approvals and detailed planning we would need before being in a position to make a final decision. That concludes our formal presentation for today. And I will now hand back to the operator for questions.

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

Obviously, a few questions, I guess, to follow up on. First question I just had from me is just in terms of, I guess, like, the government, and they are all on board with the change to terminal. If there's -- you don't see any particular issues there?

Andrew, look, we've worked very closely with government over the last year through our strategic review process. So we have a good understanding of their position and views, and that's factored into, obviously, what we're taking forward. So that's an ongoing process as we get further progress around the import terminal planning work. And certainly, one of the areas that we are continuing to talk to them about, as an example, is security of supply policy in New Zealand and what that might need to look like if we no longer have a local refinery.

Yes. And sort of, I guess, that's what you -- I think, you alluded to in terms of potentially needing to hold more, I guess, refined product at the refinery for that security of supply. I assume that's all outside of the customer negotiations, and that's just a government thing that you're working through?

Yes, that's right. That's a matter that the government's working through, and we're closely involved with them on that.

Yes. Yes. Okay. Next question I had was just around assumptions on, I guess, jet volumes and the $100 million revenue number that you talked about there. Does that assume jet volumes return, I guess, close to where we have seen historically?

Yes, it does, Andrew. So it's -- we're obviously factoring what that recovery profile might look like in how we're thinking about our sort of contracting structure, particularly through the period that we're funding our conversion costs, but that's sort of an average target figure over a 10-year period and assuming you get back to more normal levels of jet demand in the coming years.

Yes. Yes. Sure. Okay. And our next question is just around, I guess, we've seen a number of the Australian refineries announce that they're looking to convert to terminals as well. I mean how much has that been factored into your thinking? And has it changed anything at all over the last few months?

Look, we certainly watch what's happening in Australia with interest. I don't think there's a direct connection. There's clearly been a different position taken by the Australian government in relation to refineries from a security of supply perspective. And we think that reflects the difference in terms of domestic crude production. So Australia has quite significant levels of crude production. So there's some natural security of supply -- of fuel supply by retaining refinery capacity, which I think is behind why the Australian government has taken the steps it has taken in terms of putting some incentives in place. But we don't have that same crude production here in New Zealand. So that might be part of the explanation for the difference you're seeing between the 2 countries.

Sure. Okay. And last question for me, for now at least, you talk about a system, which is around about 3 billion barrels. I think what we saw in 2019, going through the pipeline that was -- we're excited around about, I think, 3-point -- sorry, 3 billion liters, about 3.3 billion liters. So in terms of the new structure going forward, assuming the pipeline capacity is not changing, but it also implies that there isn't any or much additional storage capacity going into the terminal, I'm just sort of thinking about meeting Northland demand versus what goes down the pipeline.

Yes, I might need to check and get back to you, Andrew, just on the 2019 figures. They don't quite ring a bell with me. We clearly had much higher RAP utilization in 2019, but we're not at full capacity. We were, at that time, looking at some of the opportunities that exist to increase capacity. So there are those options available. And I think with our outlook at the moment in terms of fuel demand, both the combination of potentially petrol coming off a bit over the next 15 years and a recovery in jet, I think our expectation would be that we would maintain sufficient RAP capacity to meet the Auckland market in the way we supply today.

Your next question comes from Nevill Gluyas with Jarden.

Congratulations on a very, very busy year. I have many questions. I'll try and ask a few and perhaps circle back to bring on what others want to ask afterwards. I guess just to start off in no particular order. The $100 million sort of hope or guideline for revenue, can you give us a rough split of how much of that will be fixed versus variable?

Not at this point, Nevill, reasonable question, but just because it's an ongoing negotiation, we don't want to -- we're not in a position right now to sort of talk to the specifics of those negotiations. But clearly, we want to make sure that the fixed component is covering our costs and the variable structure incentivizes utilization of our infrastructure and is competitive with alternatives.

Great. Yes, that's helpful. Like -- because at least there's a starting guide. The -- where next to go? The current disputes with the customers, you make a note in there that they're sort of put aside while you have the discussions with customers. To your knowledge, and I guess this hasn't yet been tested, will the customers be making fee floor payments for the January, February period?

So I think what we say in our account is that we understand that they will be making fee floor payments in February. We -- just to remind everyone, it was only Z that announced that they were proposing to withhold payment of fee floor amounts towards the end of December, and that's obviously something we've continued to talk to them about because we don't believe they're entitled to do that. So I think the latest is per what's in the accounts, and we obviously continue to work closely with them to reach an agreement.

That's great. Next question, returning back to that revenue stream, 2 aspects to that. Would -- should we expect that to be PPI or CPI escalated? And the second part of that question is, what provision is there for the rollover period after the first 10 years? How will the pricing work beyond that first 10-year period?

So in terms of those matters, they're certainly part of the negotiation. And obviously, we have an understanding of what that looks like with BP at this point, but it's an ongoing discussion with the others. So both of the things that you're talking about are certainly being contemplated as part of those terms. And we -- as we work through and get to a more final position, we should be able to share some more specific details with you on that.

All right. I'll ask one more and will circle back, depending on whether or not there are any -- sort of any following questions ask these questions. Just during the transition period, how -- if you did proceed with import terminal, how would your revenue and costs look? Is that included in your $200 million cost estimate for the transition? How should we think about the financials of the business during that transition period?

So I guess one reference point for that, Nevill, is what operation of the refinery looks like through that period. And you do run it pretty full really to the final months and final weeks, in fact. So our expectation is that we operate under the processing agreement while we're running a refinery. There's clearly got to be some things to be worked through with customers because they have a lot of products on-site that needs to be worked through to avoid the cost of removing that. So that's all part of ongoing discussions around that.

Great. So if I can paraphrase that, I guess, from our modeling perspectives, we should regard that as looking very much like the run rate you were looking at for the '21 period?

Yes. I don't think there would be a change to the simplified model and then, it's a scheduling matter as to how you sort of run through and down. But yes, I think that's right.

Your next question comes from James Wallace with Craigs Investment Partners.

My question was just on -- would you just provide some color on those estimated $350 million tax losses from Slide 19, just in terms of those potential obstacles to those tax losses being realized in the future?

James, Denise here. So look, the tax losses would be realized upon the write-down of the current text book value of the refining assets. At the moment, given the existing legislation that's in place, the continuity of maintaining those losses would be subject to continuity of shareholding of around 49%. So that's the current sort of legislation from the time that those are recognized. So there are some potential changes in the future, which may -- different continuity rules, which actually may help secure that position, but that's kind of based on the current legislation.

Great. And yes, just my second question, just on that self-funding expectation for the $200 million of conversion costs. Given net debt levels are at $250 million, what's your expectation there in terms of divestment options on the balance sheet and quantum? What's your thinking there?

So yes, net debt was $230 million in end of last year. If you look at our current facilities, James, and sort of the timing and spread of that spend, our expectation is that we would be able to fund certainly within those levels of facilities that we have today. So the focus in our discussions with lenders is on how much of those facilities we would need for conversion and having that in place for a period of time, which comfortably gets us through a conversion period and well placed for refinancing of the debt structure on the other side.

[Operator Instructions] Your next question comes from Lance Reynolds with Aspiring Asset Management.

Can you hear me?