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

Welcome to Refining NZ's results presentation for the full year 2019. I'm, Paul Zealand, Managing Director. And with me today is Jarek Dobrowolski, our Finance Controller; Denise Jensen, who would normally be here, our CFO, sends her apologies, she became a grandmother yesterday and is busy supporting her daughter and a brand-new granddaughter. Before we embark on the presentation proper, please take note of the company's disclaimer. This morning, we begin with the company's performance for the 12 months ending 31st of December 2019. We touch on expert forecast for the margin and look ahead. We look at how the company is responding in that market environment and how we are positioning Refining NZ to exploit an eventual upturn in the market and while contributing to New Zealand's fuel resilience for the foreseeable future. Let's start with a recap of our performance of 2019. We had an outstanding health and safety performance. Operationally, we had an excellent year with high levels of unit availability. This has led to a number of records, including the highest ever annual crude and condensate intake and highest production. At the half year, we talked about the impact of China exports. This has continued to be compounded by the coronavirus and the responses to the 2020 MARPOL regulations. This means that NZ is operating in a lower-than-expected margin environment at the moment. We're successfully managing our cost in the face of further pressures and increases in electricity and gas prices in 2019. So let's start to pick apart some of those highlights. I mentioned before, our outstanding safety performance with just 1 lost time injury all year. We had no Tier 1 or Tier 2 safety process instance for the year. Our process safety performance is top quartile when we benchmark that against our oil industry peers. Our safety performance has been underpinned by the E Tu Tangata safety program, which we discussed at a prior half year presentation. The series of regular walks, Hikoi, and regular talks, Korero, by our staffing contractors has really underpinned this world-class performance. As I said, the reliability of our plants have been excellent with our availability at 99.7%. We should note that that this was a nonturnaround year. And in the prior year, we did actually have a maintenance turnaround. Our EBITDA was down [ $38 million ] on the prior year on the back of a weaker-than-expected margin environment. As I said, we had a record crude and condensate throughput of 42.7 million barrels, and that's up 6% on the prior year. Our gross refining margin, our GRM, averaged USD 5.34 per barrel. Unfortunately, that's nearly $1 a barrel lower than it was in 2018. And this really reflected the Singapore complex margin also being down, but we did manage to increase our uplift on the back of excellent plant availability and optimized product make. We also benefited from about a 5% improvement in the exchange rate with the average for the year being USD 0.66. I'd like to now hand over to Jarek to talk about the financials in more detail.

Thanks, Paul. Honestly, you've done very well pronouncing my quite difficult name. And again, my name is Jarek Dobrowolski, and it's a pleasure to be here in the absence of Denise today. I just propose, we do a quick run through the EBITDA waterfall and focus on the main movements year-on-year. First of all, looking at our EBITDA, and this year, it becomes quite apparent that the main factor influencing our financial performance is the processing fee, which overall has dropped in the third -- in this year by $13 million (sic) [ $17 million ]. As Paul mentioned earlier, this drop represents weaker margins this year, which resulted in a decrease in the processing fee by [ $42 million ] . This effect was partly offset with more favorable U.S. dollar exchange rate as well as high production volumes, which altogether added $29 million to our revenue line. The end of November Transpower outage impacted us primarily with lost production volumes. The $3.8 million impact on the EBITDA represents lost processing fees this year against our production plan. In 2018, we also earned $6.7 million in terminaling revenue in relation to the import of finished products in order to manage supply during the total refinable shutdown. This obviously did not recur in 2019 being nonshutdown year. In terms of electricity, overall, the cost has increased significantly as a combination of higher volumes this year as well as higher-than-historical average pricing as the wholesale market remained volatile during the financial year. Maintenance costs include nearly $3 million of costs associated with the maintenance program, being specific projects targeted at addressing some more pressing maintenance works on the plant, such as heat exchanger cleaning. As a reminder, when we were publishing our profit metrics earlier in 2019, we indicated that additional funds were allowed to carry those maintenance works throughout the year. What we also communicated was that we allowed for some one-off costs in 2019, which will not recur in the following years. One of the largest of those is close to $1.6 million spent on legal and advisory services in connection with the government in pipeline inquiry, more on this later today. What we also included as one-off is the insurance recovery, relating to the final settlement under the material damage and business interruption cover in relation to the 2017 pipeline incident. In 2019, we have recognized an income of $2 million on top of $2.9 million in 2018. Moving on to cost reductions. Those reflect a range of cost-saving actions and initiatives this year, and including not making our short-term employee incentive payment based on the company's financial performance in 2019. So all of these factors resulted in an EBITDA of $118 million. Obviously, after allowing for financing costs, depreciation and tax, our net profit after tax landed at $4.2 million, which compared to a $3.5 million loss reported at half year means that the second half of the year returned a profit of $7.7 million despite low-margin environment at the back of the year and cost pressures. And speaking of costs, and I would like to make it as a key takeaway today, we have managed the operating costs tightly and have been able to identify a number of cost initiatives, allowing us to offset those cost pressures and noting that some of those will extend to the following years. Secondly, what I would like to highlight is that while our profit is down year-on-year, the net profit after tax is in line with the profit metrics that we published to the market back in February 2019 and held as a guidance of our financial results at half year.

Thank you. It's Paul, again. I'd like to just, again, stand back and look at -- help you understand our performance based on some of the factors impacting on our industry. Because despite an excellent operational safety performance, the second half of 2019 was really impacted markedly by disruption, volatility for the refining sector. It's not just our refinery, it's refineries globally that are feeling the same pressures. Around Asia, this is reported on by refinery capacity additions, increasing Chinese exports and slowing global economy impacting then the demand for those products. Put that in perspective, China has been exporting the equivalent of about 10 Refining NZ refineries worth product into the region. That's a big uplift. When we look at MARPOL and those impacts, all the forecasters expected the high sulfur fuel oil price to drop as it did, but the forecasters also predicted that diesel prices would increase because that would be used to offset some of that high sulfur fuel oil. In fact, that didn't materialize. It would have been the extra capacity additions plus the lower demand that has then depressed the diesel prices. So contrary to all market expectations, the impact of MARPOL has been to reduce refining margins overall. Another impact on us has been the U.S. sanctions on China, which -- that impacted crude shipping, particularly from September onwards. And because what happened is that there were sanctions against crude oil shippers who were shipping Iranian crude. That took a number of crude ships out of the market and increased our freight rates in the back end of the year by over $1 a barrel. This had a direct impact on our margins. And as I said, we're now operating in that sort of slowing global economy, which is impacting us all. In this environment, though, what you can see is that our uplift over the Singapore complex margin, which is really a key measure of our competitiveness, has improved slightly. And that's mainly as a result of our excellent plant availability and uptime where we can just get more out of our refinery, and 99.7% uptime really is world-class. You can see our crude cost and yield continues to increase as we work to widen the range of cruise we process and we implement our many small projects to increase our yield. It's worth noting that product quality has depressed slightly as we see a higher availability of higher-quality products now being available on the market. But overall, our uplift is up compared to the year before, and we continue to focus how we can remain competitive. We've made a big point in previous presentations of the various regulatory and other reviews that have been going on, on key assets and key elements of our business. And it's been really pleasing to note that in the 2 key ones for us, which was the pipeline, RAP disruption inquiry and the retail fuel market study. Both of these recognized the criticality of our Refinery to Auckland pipeline, how important that is as part of the fuel supply infrastructure for New Zealand. And I'll say a little bit of more about that later on the presentation. These studies are now behind us. They did cause us to spend more money than we would have otherwise liked to have done, but they have recognized our importance in the supply chain. The other point I'd like to make as we just consider our business in total is how we're contributing to a low emissions economy. We've invested more than $750 million in projects over the last decade or so. And with those projects, there has been a real focus on improving our carbon dioxide or CO2 intensity. And over that period of time, we've reduced our intensity by more than 20%. And we believe that Te Mahi Hou made the largest carbon dioxide reduction of a single investment by any intensive trade-exposed company in New Zealand. So we're really focused on how we can reduce our carbon footprint and contribute to a lower emissions future. We're still pursuing further energy initiatives, whether they be cleaning programs, energy-efficient tankage, even LED lighting. We've got a whole suite of improvements that we're pursuing. And those improvements, together with those that we do with energy conservation, EECA, together, we're expecting a further 7,700 tonnes of CO2 reduction looking forward. Our solar project also has the potential to remove another 18,000 tonnes of CO2. So this is a key focus for the company. It's a key focus for the Board to ensure we keep ourselves moving on an ever-improved emissions performance. So looking ahead, we rely a lot on FGE, Facts Global Energy, forecasts as we look to what might be the impact of coronavirus on the demand and supply in 2020, how we're responding to that issue. We do expect margins to recover as we look forward. And we expect Asian demand growth to outstrip capacity additions from 2021, looking forward. All of which, together with our own actions, means we ensure we'll be well positioned to benefit from the market recovery when it comes and contribute to a resilient fuel supply to New Zealand. So let's look a little bit at that supply and demand outlook. This picture you have seen before or something similar. This is the very latest as of February 2020. And what you can see, if you look historically, the blue bars indicate the capacity additions, and the orange bars indicate the demand additions or reductions over the previous decade or so. And what you can see in the last few years is the increase in capacity has outstripped the increase in demand. And that's one of the key contributors to our current margin environment. We can see that this year we're expecting reduction in demand across Asia. But as we look forward, FGE expect that that demand will increase quite markedly as it bounces back in 2021 and continues to grow thereafter. And the capacity additions will be much less than that. Now these are all based on FGE's assumptions about what new refineries will come on and what might not make the current future. But even looking at that, what we can see is, the supply-demand will tighten as we look forward. That should contribute to a margin uplift. That then flows through to how FGE look at the, what we call the cracks on particularly the refining margins, and we can see how in 2019, those have reduced. But in 2020, we expect the diesel margin to be supported and petrol to improve as demand recovers. You can see on the bottom graph, which is the high sulfur fuel oil, we call that crack or margin to Dubai. We -- FGE have forecast that that would increase, and actually that's been borne out what we've seen in reality. So since December, that crack dropped as low as minus $27 a barrel, that's the difference between high sulphur fuel oil and crude, that has recovered significantly to just minus $10 a barrel today. So we are seeing some of this forecast playing out in our current environment. However, the impact of coronavirus is still yet to be played out. What we do know in China is there are between 20% and 50% of refinery shutdown. We know that they've got various levels of product and crude in tanks, and there is ships currently waiting to unload and to be loaded. So a lot of that infrastructure in China is currently suspended. We're just not sure yet how that will play out over the next quarter as China gets moving again, transportation gets going, refineries come back online. So we are expecting an increased volatility in the quarter ahead. But then when we stand back and actually look at that volatility in that cycle, we've operated successfully in an industry which is inherently cyclical and inherently volatile, as year-by-year, the industry responds to new demand and new supply coming on stream. We're currently in that cycle, that cycle has turned down. There's no ignoring that, and we're responding to that. What we're very, very focused on those to make sure that our safety critical maintenance has progressed to plan, we will not compromise that. But we have made significant reduction in our cash costs for this coming year, with about 30% reduction in our capital program and our operating costs also pared back with all discretionary -- all discretionary operating costs being examined and cut back. Significantly, we're looking at how we can get even more value out of our refinery, and we're doing that by broadening our crude slate. That means looking at crudes we haven't processed before, so that we can process cheaper crudes and add more value for our customers. We continue to optimize our refinery yields. We have just improved the performance of our main units, our platformer, by about 0.5% of yield by lowering its pressure. And we're also implementing projects at the upcoming shutdown, which will further increase our ability to handle cheaper crudes. We're also looking at how often we do shutdowns and when we do shutdowns and what sort of shutdowns they are or turnarounds. That will over cycle -- that will further improve our GRM, and I'll talk a little bit more about that in a minute. We also should just reflect on gas. Gas is a key component for us. It reduces our emissions, and there's a fuel supply for us. We're really worried about gas supply. What we saw in the last few years with the disruption in the gas supply system and not a lot of new supplies coming on stream, we're worried about access to that gas going forward. So we now have secured a 3-year gas supply contract from a customer who's got a diverse source of supply. But as we look forward, we really need to focus on that because it's a key input to our refinery, helping us to reduce our emissions. So let me hand over to Jarek, and we'll talk more about some of these issues later.

So now let's have a bit of a dive into our costs, especially in the context of how we have tracked over the past few years and what we're looking at in terms of sustainable cost base going forward. And firstly, as a reminder, nonenergy costs that you can see on the right-hand side include costs related to processing, such as chemicals and utilities as well as maintenance costs, people costs and corporate or overhead expenses. And I would like to repeat what Paul said earlier today that in response to the weaker margin environment, we have implemented a number of cost-reduction initiatives that are expected to take our nonenergy costs back to around 2016 and 2017 levels, which is well below our previous guidance to the market. Obviously, we might be making decisions around operating costs. We are aware of the fact that we have to maintain our personnel and process safety performance, and I would like to assure everyone that any cost reductions will not compromise our focus on safety. In terms of energy costs that have increased in the last 12 months, especially, I would like to highlight that the solar farm, which the Board has yet to give final notice to proceed has the potential to alleviate some of the cost pressures there, shaving as much as $3 million of our electricity bill. And finally, natural gas being the main contributor to pass-through costs that Paul alluded to, is the main driver for the increase in that area. Paul?

Okay. Thank you. We mentioned before about our turnarounds, or we used to call them shutdowns, and how optimizing those can really add value for our customers. It keeps us upstream and online for longer if we can reduce costs if we can get these optimized. So this year, we've got a number of shutdowns. We're about to shut down our hydrocracker. That's a relatively short shutdown. It will take 2 to 3 weeks, and we call that a Top Bed Skim. So that will renew the catalyst at the top of the hydrocracker, and it will actually give us some more information. Because if you look down to 2022, we have taken the hydrocracker Top Bed Skim out of that, and what we're looking to do then is move the hydrocracker to a 3-year cycle starting 2021. So in 2021, we have a big shutdown, the hydrocracker unit and the crude distiller unit, and that will then be the first of our new 3-year cycles beginning from then. It's worth noting that in 2020, we are shutting down our distiller to sulphuriser. And first time we will have shut down our CCR Platformer, our Te Mahi Hou project that we talked before, that's after 4 years of continuous operating. We're hoping that the information we then get from that inspection cycle will then allow us to set a longer inspection cycle as we go forward. We can only do those things based on a good thorough inspection of the current condition of the unit. I would like to add that we will be doing some extra inspection work in hydrocracker in 2020, which will allow us then to look at whether that shutdown that's currently planned for 2021 could be delayed into 2020. We won't know that until we've got some more inspection information. But again, we're actively looking at how do we continue to phase out and to optimize our shutdown schedules. So looking again at our long-term plan. We've put a lot of work into our long-term asset management maintenance plan. This really allows us to look at all the activities we need to do in a 10- and 15-year window. And from that, we can cost those, optimize when we do them and try and reduce and flatten out our CapEx profiles. What you see before you is our latest plan. The thing -- it hasn't significantly changed from last time you saw it, apart from the fact that we really have now reduced our 2020 program down to what we consider to be a minimum, which is 30% lower than we were intending. But our average over a 10-year cycle remains the same, and our average over a 15-year cycle is now down to $65 million per year, which is in line with our previous guidance. And this is all done on the back of some excellent engineering work that will give us confidence that this really is our plan looking forward. We will continue to come back to this, I think, at every year to continue to give the market confidence that we really do understand the capital requirements and our assets looking forward. [And to] pause again on the Refinery to Auckland Pipeline or the RAP. And the purpose of this pipeline is to keep trucks off the road. Without it, we would need more than 61,000 trucks per year or truck journeys per year to move that product into Auckland. And that would emit at least 15,000 more tonnes of CO2 than is currently required. So it really is the safest, most environmental and cost-effective distribution method for putting transportation fuels into Auckland. It's a really important asset for us, and it's a really important asset for New Zealand. And its future will go beyond the transportation fuels we use today. As the world looks for lower carbon fuels, we expect this pipeline will continue to have a life to transport those lower carbon fuels into Auckland. We can see there are changes as -- with the transportation fuels, we see more electric cars on the road. We're not seeing a demand reduction yet for gasoline. And we know from forecasts provided by Auckland Airport, we do see aircraft jet fuel growth extending long into the future. So really, what is the purpose of the refinery and how are we responding to the environment? We will continue to deliver safely on time and on specification our products for our customers. We're minimizing our cash costs in response to the market challenges, and we continue to add value to our customers by broadening our crudes, optimizing our refinery yields and stretching out our turnaround cycles. We're planning for successful turnarounds this year in March and May, and we're really focused on delivering those safely, on time, on budget with the right quality. And a key issue for us, as we've talked before, is submitting our resource -- refined resource consents in this year. We're on time to do that. We've got all our work underway, and we expect to be able to make our final submissions this year. But this environment is incumbent on us to look at every bit of tactical action and strategic option we can because we're determined to stay core to New Zealand's fuel supply out into the future.

In terms of our funding position and balance sheet, in 2019, we have done some work around our facilities that were due to expire early 2020. And one of our main bank facilities has now been extended for 5 years, which allowed us to achieve longer tenure of the senior debt. And including the subnotes that make up for approximately 21% of our total available facilities, now our overall debt tenure is longer than 7 years. And another thing I wanted to draw your attention to is the fact that with our $100 million interest rate swaps rolling off at the end of this financial year and assuming obviously that the market interest rates remain at the current levels, our headroom on interest cover has the potential to be even greater than the one reported at the end of 2019. In terms of our financial results guidance, we published as every year the profit matrix, which indicates our expected 2020 profit after income tax and the year-end borrowings for given margin and foreign exchange scenarios. Why we do that? Well, that reflects the fact that these variables are largely outside our control and can be, as we all know, quite significantly volatile. The key assumptions underpinning this year's matrix is the production volumes based on an intake of close to 42 million barrels. And secondly, nonprocessing fee revenue of $65 million, which exclude pass-through income, such as carbon income and natural gas. And finally, the depreciation charge of $107 million, which is slightly higher year-on-year, but it's reflective of the cyclical nature of our shutdown and tank maintenance programs. And the matrix looks overall similar to 2019, but it capitalizes on cash cost savings identified during the 2019 year that will extend into the future years.

Thank you, it's Paul, again. Look, I'd like to just really reflect on the team we have at Marsden Point. I'm really proud of them. We've got a group of incredibly talented people who've responded magnificently to the challenges that we currently face. What we're also excited about is now being able to strengthen the leadership and bring some exciting new talent in to help take us forward. We've announced previously that Naomi James has joined us. She will be on seat in April; and Andrew Brewer, a deeply experienced refinery leader from Australia, joins us in March. Both of these help underpin our confidence in the ability of our team and the leadership at Marsden Point to respond to the current environment we're in and to help lead this business in the future. Thank you. That's our presentation complete. Thank you very much for listening or logging in this morning. On that note, I'd like to welcome those who are on the audio conference. But before we open up the call to questions, please note that you need to be logged into the audio conference to do so and the webcast is on a listen-only presentation. There is an operator on the audio conference who will guide you on how to join the queue. The operator will now take over to introduce questions from the audio conference.

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

A couple of -- a few questions from me, actually. First question, just around the outage and understanding what sort of impact that will actually have and I'm assuming -- you will expect it have some sort of impact on refining margins, but also throughput what you probably -- already guided to. But are you able to give us a sense of what refining margin impact do you expect the outage to have this year?

Okay. Thanks, Andrew. I mean I can't put a number on that right now. What I can tell you, preparations for the shutdown have been going on for quite a while. So we've been processing crudes, for example, and generating excess residue that will then be able to process during the crude distiller outages. So there's a number of factors that we've been doing to mitigate the margin that we lose as a result of the outages itself. I think the key thing for us is to really focus on bringing the projects in on time. All our supply chain is planned around it. As I said, I think we've got a 2-week outage on the hydrocracker in March and the outage of the crude distiller, I think, is 4 weeks, starting at the end of April. So both of these are well planned with our customers, and we have our stocks and our intermediates in good shape, ready to handle those.

Okay. And second, refining margin-related question is just around the new crude slate that you're looking to bring in from the second quarter. What sort of GRM impact that are you expecting it to have just on a bit of a broad sense for that?

That's a thousand-dollar question that one, because the crudes vary in price all the time. So what we're seeing is some of these crudes are $1, $2 or $3 a barrel cheaper than their equivalent crudes. At the time, we're investigating them. What we've been doing is to be able to do test runs on these crudes, so that what we can offer to our customers is the ability to bring those into the slate at the point they make the decision. We don't know what the price will be at the time, all we do know is that right now, we're able to broaden that slate and give the customers the option to bring in cheaper crudes. So I can't give you a definitive answer to that, Andrew, but they are $1, $2, $3, $4 a barrel cheaper, but that varies on a day-to-day basis.

Yes, sure, sure. Okay. And the next question, I just had was around the CapEx and long-term CapEx outlook, which I think you had on Slide '17. Those 10-year numbers, does that include inflation in there? Or is that calculated on a real basis?

Andrew, so Jarek here. So those CapEx profiles are on a nominal terms.

In nominal terms, okay.

Yes.

Okay. Because you do seem to have a bit of a decline going through the back end of the decade. So I just wanted to, I guess, confirm that you are expecting that on a nominal basis?

Well, the decline is driven primarily by the cycle of our tank maintenance program, which drops -- tails off at the back of the decade. So...

Yes. Look, I think it's fair to say, Andrew, that in the past 2 or 3 years and in the 1 or 2 years ahead, we really have been focusing on a lot of that sort of cyclical infrastructure investment, whether that be our jetties or our tanks and some obsolescence replacing some systems. When you've gone through that cycle, you can then really focus on those smaller projects to improve your reliability and value-add and not necessarily the big infrastructure spend. So I do believe in this long-term forecast, and there's a lot of effort and thought gone into it. And we will continue to try and optimize it year after year.

Okay. Next question was just around the dredging project? Are you able to give us a bit of an update on where that's -- what the status of it is?

I think at the moment, we're still in discussions with our customers how best to -- the best path forward on that. At the moment, we still -- we're bringing nearly laden bigger ships. And that's -- we're looking to see how we can actually further optimize that. So at the moment, I have no new news. We're still in conversation with our customers about the project.

Okay. And I did hear correctly that the solar project hasn't reached FID yet. What sort of time frame you're looking for the FID decision?

Well, we're still working with various stakeholders on just finalizing that project. We're still examining the risks in the light of the current situation. And -- but we still haven't made that very final decision. So I can't give you a time frame on that, Andrew, but it's still on our books. The Board is still keen to progress it if we can make it work.

Right, okay. And very last question for me. Could you just please update us around the debt covenant situation? And I guess the risk being if you were in the fee floor for the next 6 months, 12 months, would that cause any problems from a debt covenant perspective?

No, Andrew, we don't believe that would cause any problems. What would we have in terms of our covenants is a Mulligan clause, which essentially requires us to be hitting covenants, say, over 2 consecutive 6 monthly periods. So even though we were staying at floor for an extended period of time, we don't see the risk of that materializing.

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

Just a couple of questions from me. Just the first one. So Contact and Genesis recently secured gas at nearly $8 a gigajoule. I was just wondering what price you secured your 3-year contract debt? And also if you could just provide some color on the electricity costs year-on-year? And how much you're hedged versus on spot? My second question is just on the freight cost, the cost, which -- you released in January. You showed that it had come back a bit, and I know there's a couple of months lag on that and so we're still expecting some relief as these still track down now.