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Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
Ladies and gentlemen, thank you for standing by. Welcome to the Methanex Corporation Q3 2020 Earnings Call. I would now like to turn the conference call over to Ms. Kim Campbell. Please go ahead.
Good morning, everyone. Welcome to our third quarter 2020 results conference call. Our 2020 third quarter news release, management's discussion and analysis and financial statements can be accessed from the reports tab of the Investor Relations page on our website at methanex.com. I would like to remind our listeners that our comments and answers to your questions today may contain forward-looking information. This information, by its nature, is subject to risks and uncertainties that may cause the stated outcomes to differ materially from the actual outcome. Certain material factors or assumptions were applied in drawing a conclusion or making the forecast or projections, which are included in the forward-looking information. Please refer to our third quarter 2020 MD&A and to our 2019 annual report for more information. I would also like to caution our listeners that any projections provided today regarding Methanex's future financial performance are effective as of today's date. It is our policy not to comment on or update this guidance between quarters. For clarification, any references to revenue, EBITDA, cash flow or income made in today's remarks reflects our 63.1% economic interest in the Atlas facility and our 50% economic interest in the Egypt facility. In addition, we report our adjusted EBITDA and adjusted net income to exclude the mark-to-market impact on share-based compensation and the impact of certain items associated with specific identified events. We report these non-GAAP measures in this way to make them a better measure of underlying operating performance, and we encourage analysts covering the company to report their estimates in this manner. I would now like to turn the call over to Methanex's President and CEO, Mr. John Floren, for his comments and a question-and-answer period.
Good morning. We hope that everyone is continuing to stay safe and healthy. In the third quarter, we continued to demonstrate the resilience of our business through this difficult time. Our manufacturing operations and global supply chain have run safely and effectively throughout the pandemic, which has enabled us to deliver on our commitment of secure and reliable supply to our customers around the world. We'd like to express our appreciation to our team members across the globe who have demonstrated their ongoing commitment and agility this year. This morning, we will comment on our Q3 results, provide an overview of what we're seeing in the methanol markets and discuss how we continue to manage our business in this challenging environment, including additional steps that we've recently taken to increase liquidity and preserve financial flexibility through this uncertain time and emerge stronger when market conditions further improve. Now I'll turn to the third quarter results. We recorded adjusted EBITDA of $40 million, which was higher than the second quarter as a result of higher average realized price, which was partially offset by lower sales of Methanex-produced product and higher costs. We recorded an adjusted net loss of $79 million or $1.03 per share in the third quarter, higher compared to the second quarter, primarily due to the onetime finance charge of $15.4 million related to the early repayment of our $250 million unsecured notes that were due in March 2022. Excluding this onetime finance charge, we would have recorded an adjusted net loss of $68 million or $0.88 per share. Now turning to the methanol market. We estimate that global methanol demand increased by approximately 9% in the third quarter of 2020 compared to the second quarter as economic activity rebounded around the world, and methanol demand recovered across all regions and end-use markets. Globally, demand for traditional chemical applications improved as manufacturing activity recovered, particularly in the automotive and construction industries. Demand for energy-related applications, including MTBE, biodiesel and other fuel applications, improved as ground transportation and fuel demand saw some recovery. Methanol to olefin demand has remained strong throughout 2020. While demand has recovered in the third quarter of 2020, global demand -- global methanol demand in the year through Q3 2020 remains 3% lower than the comparable year-to-date period in 2019 and below pre-COVID expectations for 3% to 4% growth. On an annual basis, we estimated the forecast demand in 2020 will be lower than the 2019 by 3 million tonnes versus pre-COVID expectations for 3 million tonnes of growth. As a result, we estimate that 2020 global demand will be 6 million tonnes lower than pre-COVID forecast, reflecting the demand destruction resulting from the pandemic. Global methanol industry supply declined in the third quarter of 2020 compared to the second quarter due to various plans and unplanned outages and plant shutdowns to respond to lower methanol demand. Our Titan plant in Trinidad remains idle, while our Chile IV plant, which has been idle since April 1, is in the process of restarting. Overall, the combination of increased methanol demand and lower industry supply has tightened global inventory levels and moved methanol prices higher. We estimate that the industry cost curve, which continues to be set in China, is approximately $200 to $240 per tonne. Spot prices in China are above this range today. As a result of the tighter market conditions, our posted prices for October and November increased. We recently posted our November North American price, which increased by 13% to $379 per tonne, and our Asia Pacific price, which increased to $310 per tonne. Our European contract price is set quarterly, and our fourth quarter posted price is EUR 275 or $320 per tonne. Now turning to our operations. Our production levels were lower in the third quarter as we undertook planned maintenance activities at our Medicine Hat facility and our Atlas facility in Trinidad. In New Zealand, our production levels were lower in the third quarter, a result of received lower gas deliveries as previously forecasted. We expect to receive higher gas deliveries in the fourth quarter. In Geismar, both of our plants ran at full operating rates during the third quarter. We completed our low capital cost Geismar 1 debottlenecking project to increase our production capacity by approximately 10% or 100,000 metric tonnes per year and expect to ramp up to our new full production capability for Geismar 1 over the coming weeks. In Trinidad, we commenced the planned turnaround at our Atlas facility towards the end of the quarter and expect to resume production in early November. Our Titan facility remains idle and negotiations with the National Gas Company of Trinidad and Tobago for a long-term gas agreement continue. In Chile, our production levels were lower in the third quarter as we received lower natural gas deliveries during the Southern Hemisphere winter months when the natural gas supplies are needed for residential heating. As global methanol demand is improving, we are in the process of restarting our Chile IV plant. In Egypt, our plant ran at nearly full operating rates. In Medicine Hat, our production levels were lower as we commenced the planned turnaround in August 2020 and subsequently completed at the end of October. Now we'll turn to our balance sheet. In the current unprecedented environment impacted by both COVID-19 and challenging commodity prices, the path and pace for global economic recovery and the methanol demand remain uncertain. We believe that it's prudent to plan for a wide range of scenarios, including the possibility of a prolonged period of lower methanol demand and lower ethanol prices. We have taken a series of actions in 2020 to preserve liquidity and improve financial flexibility during this uncertain time, including deferring approximately $500 million in capital spending on our Geismar 3 project, reducing our dividend by approximately $100 million on an annual basis, suspending share buybacks, reducing maintenance capital and operating costs and updating covenant relief on our credit facilities. In addition, in mid-September, we issued $700 million in 2027 notes to repay existing debt and increase our liquidity and financial flexibility with limited impact on our leverage metrics. We have repaid the $200 million drawn on our revolving credit facility. And in late September, we issued an early redemption notice to repay our existing $250 million bond that was originally due in March 2022. The cash flow impact of early bond repayment will be reflected in our fourth quarter results. The remaining $250 million is available to provide additional liquidity. We have no other debt maturities until late 2024. During the third quarter, we also secured additional flexibility under our revolving credit and Geismar 3 construction facilities related to the minimum EBITDA to interest coverage ratio covenant through to December 31, 2021. A prior waiver had provided covenant relief until June 30, 2021. The steps that we have taken in 2020 to increase liquidity and improve our financial flexibility position us well to navigate through this uncertain time and generate significant long-term value when market conditions further improve. We are pleased to see recent early signs of economic recovery, including improvement in methanol demand and prices. Nevertheless, we continue to evaluate all options to preserve liquidity and improve financial flexibility as necessary. Now I'd like to turn briefly to our Geismar 3 project. As we've noted before, our Geismar 3 project is a high-quality project with substantial capital and operating cost advantages and has been significantly derisked. In April 2020, we placed the project on temporary care and maintenance for up to 18 months, given the significant uncertainty regarding the global economy due to COVID-19. The project was in excellent shape and progress had been safe, on time and on budget, and the head project had been significantly derisked. We deferred approximately $500 million of capital expenditures with the expected spending during the temporary care and maintenance period reduced to only the costs that we were already committed and the completion of activities that preserve the flexibility to complete the future -- the project in the future, such as certain key engineering activities and procurement of critical path equipment. Construction on the Geismar 3 project remains on hold, and the various factors today do not currently support restarting construction. We want to be clear that we have a robust decision-making process for evaluating the project, and there are many factors that management and our Board will need to consider carefully before restarting construction, including the global economic recovery and the methanol demand outlook, the methanol industry's needs for new capacity, the methanol price forecast, the ability to fund the project and our suppliers' ability to complete construction and deliver material and equipment on time and on budget in light of any COVID-19 restrictions. We will continue to review and monitor these factors as we continue to evaluate G3. We continue to explore partnership arrangements for the project. Now turning to our outlook for the fourth quarter. We expect that the outlook over the coming months to continue to be uncertain. We cannot predict the full impact of COVID-19 pandemic on the methanol market. Based on our posted prices so far, we expect average realized prices in the fourth quarter to be higher than the third quarter. We expect that our production levels in the fourth quarter will be higher compared to the third quarter as we've completed our planned maintenance activities in Medicine Hat and Trinidad. We are in the process of restarting our Chile IV plant, and we expect to receive higher gas deliveries in New Zealand compared to Q3. We expect adjusted EBITDA to be higher in the fourth quarter compared to the third quarter. As we look forward towards next year, we are updating our guidance on a couple of items starting in 2021. We expect our selling, general and administrative costs to be flat in 2021 compared to 2020 as we continue to focus on our low-cost strategy. And we expect our maintenance capital guidance in 2021 to be approximately $120 million, which is consistent with our revised maintenance capital guidance for 2020. Before we pause for questions, we'd like to highlight a couple of points about the resiliency of our business. While the near-term outlook is uncertain, we continue to believe that the long-term methanol industry supply and demand fundamentals are strong. Methanol is a key chemical building block that is used to produce a variety of everyday consumer and industrial items. Methanol is also used in a growing number of clean-burning and economic alternative energy applications. We expect that demand for methanol rebound and grow as global economic activity recovers. As a global methanol industry leader with a network of production facilities around the world, an integrated global supply chain and low-cost structure, our competitive advantage of delivering secure and reliable supply to our customers around the world remains intact. We have strong cash flow potential with significant leverage to methanol prices. We estimate that every $10 increase in our average realized price translates into approximately $60 million increase in adjusted EBITDA on an annual basis. We remain focused on operating our plants safely and reliably, delivering secure, reliable supply to our customers and strengthening our business by preserving liquidity and improving financial flexibility. We are well positioned to navigate through this uncertain time and emerge stronger when market conditions improve. We would now be happy to answer any questions.
[Operator Instructions] The first question is from Ben Isaacson of Scotiabank.
John, I just wanted to understand, first of all, the dynamics that you're seeing between Q3 and Q4. So obviously, in Q3, we had strong demand recovery. MTO rates were high. We had limited supply because of outages, the turnarounds, Hurricane Laura, et cetera. But now as we kind of go -- get halfway to Q4, we're starting to see lockdown increase, MTO economics are starting to move a little bit lower. We're seeing seasonal slowdown in construction, and supply is coming back. So do you think that Q4 could be a little bit weaker than Q3 in terms of supply and demand?
I don't predict the future. I can tell you what we see is that supply continues to be constrained. There is a plant that's being commissioned in Trinidad that has not really delivered a lot of product into the market yet. We understand there's another new plant in the United States that'll be commissioned sometime over the next few quarters. And we expect to continue to see demand recovery in Q4 based on where we are in our forecast for the quarter. But that could be impacted by further shutdowns, as you've mentioned. So I can't predict our competitors' plans if they're going to have unplanned outages or not. What I would say is that these plants need ongoing maintenance. And in the COVID-19 environment, it's very difficult to do regular maintenance, never mind turnarounds, as we've just experienced ourselves doing a couple of them. So I think it's hard to predict. But I think Q2, what we see is the bottom now, but that's really depending on demand recovery and what you see for demand. When we talk to our European customers today, even with lockdowns, their demand still seems to be okay, but that could change very quickly. So in this environment, I'm really not going to predict what might happen in 1 or 2 quarters to come.
And John, my follow-up question is on the dividend. Obviously, liquidity is vastly improved. You're now prepaying debt a couple of years out. When you think about the dividend, is it your hope that you will reinstate the dividend back to what it originally was? Or you'll kind of assess it at the time? How are you thinking about that?
Well, hope is not a strategy. I think as we generate excess cash, our first use for that cash will be to repair our balance sheet and to get our debt leverage metrics back to investment-grade kind of ratings. Beyond that, our capital allocation strategy hasn't changed. Three pillars: To take excess cash to grow the company in line with the market if we have projects that meet or exceed our hurdle rate of 13% return on capital employed; have a meaningful, sustainable, growing dividend; and return excess cash beyond that to shareholders through share repurchases. So nothing's changed in our strategy, and we'll see how our cash generation develops here in the global pandemic. And you should expect us to follow that strategy going forward.
The next question is from Joel Jackson of BMO Capital Markets.
This is Robin on for Joel. So my first is on G3. So for it to be restarted, would you need confidence that free cash flow would be positive, including the G3 CapEx during the remaining construction period?
Well, I think what I've said is we have to have the ability to finance that project. And without a partner, there's still quite a -- about $900 million after what we'll spend in the care and maintenance period that we'll have to figure out how to finance. So there's a lot of different options on how we do that, and we haven't made any decisions.
Okay. For my follow-up, what production level at New Zealand can be supported by the higher gas deliveries in Q4? And will the upstream gas projects that's going on in the country right now allow for more normalized production in 2021?
Yes. So I guided this time last year that we were expecting gas curtailments in New Zealand during 2020, and that's what we've seen, COVID or no COVID. So we had guided to 1.8 million tonnes for 2020, and we're going to be a little lower than that, probably 1.7 as there was a bit more activity than we had been told early -- or this time last year, so about 100,000 less for the year in New Zealand. And next year, we should get back to that 1.8. But the ongoing activity that we see gives us pretty good certainty that we'll continue to see better gas deliveries in the future from New Zealand. But next year, I think I'll guide to about 1.8.
The next question is from Jacob Bout of CIBC.
How far can you defer G3 without further financial penalties?
We're looking at all options regarding G3, and we don't have any decisions in front of us today. We've put it on care and maintenance for up to 18 months. So our team are working hard to negotiate all the various contracts that we have related to G3 to give us the maximum flexibility that we could hope for in this very uncertain environment. So we're continuing to talk to our various partners where we've made commitments, and everybody is experiencing similar that we are with all this uncertainty. And I think our partners are being flexible, but I really don't have any numbers to share. And we're focused on the 18-month care and maintenance and see how markets develop between now and then.
But to be clear, after 18 months, or if you continue to delay this project, there will be some financial penalties?
I wouldn't commit to that today. We're negotiating with our suppliers. We may -- we have different options to consider. So I don't -- I think there'll be some commitments that we'll have to pay for, but it's too early to tell how much that might be.
Okay. And then just in regards to Chile IV. What methanol price do you need to break even there?
What methanol price do we use? Well, I don't give breakeven prices plant by plant basis, Jacob, for competitive reasons, obviously. I would say the gas prices that we're seeing in that southern part of the world are very similar to what we're seeing in the United States. And most of the products that we'd be making if Chile IV would be going to Asia. So whatever assumptions you have for conversion in freight, you can figure it out.
The next question is from Steve Hansen of Raymond James.
Just a follow-up one on Chile, if I may. Was curious, John, I think in the past, you had guided towards Chile being in a position to do roughly 75% utilization on 2 plants. That was prior to Chile IV shutdown, obviously. Are we to assume that that's going to be a similar type range now going forward once Chile IV is up and running? Or how should we think about that cadence?
Yes. Assuming that the world needs the product, the guidance hasn't changed. I mean, the only 2 plants we had flexibility on take-or-pay gas was Chile IV and Titan, and that's why we decided to shut those plants down. Our guidance was 75% on an annualized basis for a 2-plant operation and how that was structured was, think of Chile IV running 6 to 8 months a year and shut down during their winter period, which we're just coming out of, and Chile I running at full rates, except for their winter period. And on average, that should get us to about 75%. We haven't run both plants at full rates for any extended period. So we're not really sure the total nameplate capacity once they're integrated. So we have a bit of discovery still to do. But we still believe, based on our current gas contracts, current gas availability throughout the year, that guidance is still good. But it won't be smooth 75% throughout the year. During their winter period, our summer period, you should expect Chile I to run at lower than full rates and Chile IV to be down.
Understood. That's helpful. And if I may then, just as a follow-up on the operational side. The Atlas turnaround strikes me as being quite extended this period, that I think you suggested in the release that it was started in September and it will be back up and running in November. But if you look at the utilization rates that it ran at during the third quarter, it was also quite low. So is there anything to read into that? Or is it just the turnaround took longer than expected? Or how should we think about that process?
Yes, there's lots to read into that. We had scheduled a turnaround in Atlas and Medicine Hat early in the year and due to COVID-19, we couldn't do it. I think you know, Steve, that you've been at these plants, the catalyst degradates over time and especially in an oxygen-based plant. So every month that goes by that you don't change out that catalyst, your operating rate is impacted, and that's what we've seen in Atlas. And we're kind of crawling along to try and get this turnaround done. The oxygen-based plants need catalyst change a little bit more frequently than a regular steam reforming plant. So we are lucky that we had a window to complete the turnaround. It's about 45 days, give or take, and we're pretty well complete, and we'll be starting it up in the coming days. So I'm really proud of our team down there and our team in Medicine Hat for really getting these turnarounds done in very difficult environments, especially with the COVID-19 protocol. So I'm glad we're not having any more this year to do in this environment or even constructing in G3, I think, would be a challenge that we've seen in that part of the world, plants that are under construction are delayed and cost overrun because of the COVID-19 protocols, et cetera. So yes, I'm pretty happy with what we've done in Medicine Hat in Atlas.
The next question is from Cherilyn Radbourne of TD Securities.
Maybe just picking up on that discussion about the difficulty undertaking turnarounds in this environment. Maybe you can give us some color on some of the major challenges and your perspective on the extent to which you think the industry may be behind on maintenance as a result?
Well, I think everybody is behind on maintenance. I mean, when you are down to minimum staffing levels at plants, instead of 150 on site, you might have 55. So you're just doing the stuff that you absolutely have to do to keep the plant running safely. When you do a turnaround, you're bringing between 1,000 to 1,800 people on to a site in a 6 to 10-week period. So you can imagine in a COVID-19 environment with all the protocols of distancing, testing, masks, a lot of these jobs are in confined space environments, really collaborative, a lot of teamwork and a lot of focus on safety. So you're having people looking at safety all the time, and all of this has to be done at a distance. And then manpower availability. We don't talk about that, but you have contractors that you sign up for that guarantee or in their contracts, say, we're going to have x number of bodies available for this particular job, and then you get half that amount for a job. So that leads to lots of complications. As at any time, COVID or no COVID, our focus is on safety. And in a COVID environment, it's a lot more complicated, it takes longer. And in Medicine Hat, we had an outbreak. So that further complicated things. This disease, I don't think, is still well understood, and it seems to spread a lot quicker than we first thought. So we are always overly cautious about keeping our team and our contractors safe. So it adds to cost in the fact that you have longer time to do the same amount of jobs, you have less available contractors, so that adds time. And just the protocol that's time and people. So it's a really difficult environment if you do it properly and you really follow the safety protocols and guidelines that are put out by the various governments to get any significant maintenance, never mind construction work done.
Okay. That's very helpful color. Separately and with regard to MTO demand, as I'm sure you're aware, there's been some talk about potential MTP restarts. And I was just hoping you could give us Methanex's perspective on that.
Well, I'm not as bullish in this one as Argus is, and that's usually I'm more bullish than Argus, so it's interesting. But it'd be a nice surprise if it happens. Our team there is looking at it and following it very closely. But hasn't happened yet, lots of talk. But it would be a nice little demand driver if it does happen. I personally don't think it's sustainable based on the economics of just making propylene from methanol, but that's my personal view and we'll continue to follow that market.
The next question is from John Roberts of UBS.
John, back to your maintenance comments there. Do you have a gut feel for how much of the industry supply is perhaps reduced by lower catalyst activity broadly in longer downtimes when people are doing maintenance? Does it take 1%, 2% out of the total global supply availability?
I'd be guessing, John. I don't like to guess. I can tell you with Atlas, as you get to end of life of catalyst, it goes down pretty fast. I think our operating rates before we took the turnaround were 80% versus 100%. So doesn't take long as the catalyst degradates to reduce operations quite significantly. Anecdotally, I think some of the outages we've seen in Q3, planned or unplanned, have been related to maintenance, but that's normal. And I guess every different country has different protocols on how they do COVID-19 contract -- or sorry, social distancing and masks. So I think every country is a little difficult. But in general, I think maintenance has been deferred. And I think as you do planned turnarounds or unplanned maintenance, it's going to take longer and probably a little bit more expensive. But I don't really have a number I can share with you off the top of my head.
Okay. And do you have any thoughts on North American natural gas prices over the next several quarters? The financial markets were obviously preparing for higher gas prices.
Yes. I'm not an expert on gas, but what I know is there's lots of gas. And I'd say $4 and below, there's probably lots of gas for a long time. So I've seen it being very volatile. And I don't know if that's a factor of deliveries or system issues, I'm not sure, John. So it's a bit out of my area of expertise.
The next question is from Jonas Oxgaard of Bernstein.
Just one quick clarification. The $100 million you mentioned over the next 12 months. Some of that, I'm assuming, is onetime to finish up stuff. But how should I think about that long term, if this ends up being in care maintenance for more than 12 months?
Again, we've given 18-month period of care maintenance. We've given guidance around how much we would spend, including the commitments we've already made. And then we're looking at if we have to further delay or on a like a year or longer basis, what that might entail. We don't have any numbers to share with you today because we're in negotiations with all of our partners on that project, and it's too early to make that call. So we have 18 months of care and maintenance for the prices that we've -- about $100 million more to go for a total around $300 million to $400 million and -- or $400 million, and then we'll have another $900 million to go to finish the project. And that $900 million could change depending on what timing we're looking at to complete that project, if we have to put it on longer hold or temporary further hold or go forward. And we haven't made any decisions around that yet. And we want to see how methanol markets evolve given the 5 conditions we're looking at to restart that project.
Okay. The other question's in your compare quarter-over-quarter, your discount to -- so your realized price improved whereas your benchmark price declined. So the discount clearly was reduced. Can you talk about what sets the factors of this discount? And is that something that is sort of forecastable? Or is it just based on what you're doing in the quarter?
Our guidance is 15% discount on average. And what we've said is when prices are increasing rapidly, that discount tends to narrow. And when prices are decreasing rapidly, it tends to expand. And you would have seen that in our results since 2018 when we've had both of those events occur. And in the quarter, we probably had fairly stable at a very low price -- pricing, which led to that 15%. We're looking at right now renewing our contracts for next year for a good chunk of our business. I would say there's a lot more intense rivalry out there today in placing volume because of the environment we are, and that could impact discounts. And when we have something to update, we'll do so and probably we'll look to update our guidance on discounts in the January call.
The next question is from Eric Petrie of Citi.
A fertilizer company this morning announced a goal they have 1/3 of its ammonia production will be low carbon. Are your customers demanding greener methanol, especially into the fuels market? And then could you address the long-term enthusiasm from methanol into maritime transportation demand?
Yes. So some of our customers are asking us for green methanol, as we call it, and obviously, want to pay the same as what we call regular methanol from natural gas, which the economics are quite different. When you make methanol from a non-carbon natural gas, like we're doing in Iceland, I'll remind you, we have a project in Iceland that we've invested in that takes CO2 off of a power plant, takes water through electrolysis, makes hydrogen and oxygen. The oxygen goes in the air, we use the hydrogen to make methanol and that's so-called green methanol, which has no carbon. So it's possible, very expensive and hard to scale. These plants would be in the order of magnitude of -- 25,000 to 50,000 would be a big one and a big methanol plant from gas is 1.8. So you'd have to make a lot of these all over the world, a lot of capital involved and probably the price you'd need is $800, $900 a tonne to make a goal of it. Well, our customers -- some of our customers would like to see non-carbon or green methanol, but they're not prepared to pay $800 to $900 a tonne today on -- for a lot of volume. Maybe there's some niche applications that could work where they want to take advantage of some of the government subsidies around credits, et cetera. But that's not a way to build a business, on government subsidies and credits. So we've been looking at this for a long time, and we've been looking at the various technologies, and it does work. Does it work at scale? I think that's a question mark. And are -- is the market prepared to pay today for what the price we'd need it to have significant volume, and I would say no. So we'll continue to look at it, and we're -- there's lots of other things we can do. And including in Louisiana using natural gas that's made from a 0-carbon source and using that through our plant, we can then have zero carbon methanol. So -- but these are, I'd say, very small volumes today. But who knows how far this could go in the future and what the willingness of customers to pay for the green methanol is. I think it's early days. As far as onboard ships, yes, we're seeing a lot of interest in onboard ships. Our competitor has ordered a couple of ships that will be able to run on methanol or ultra-low sulfur diesel. And we continue to see a lot of interest. But I'd say, I've always said methanol to run ships, although we've proven out the technology, from a significant demand driver, it's probably a mid-decade issue, not tomorrow, not 2022. But I'd say the positives there is the technology works. We've proven that the efficiencies are there. The emissions reductions are there. No impact on the engines and the fact that it's flexible, that you can switch from ultra-low sulfur diesel to methanol, all of that's been proven. So I think that's exciting and groundbreaking and could be a significant demand driver as we get into the second half of the decade, but still early days.
Appreciate that color. And then for my follow-up question. You noted that COVID and the pandemic had eliminated 6 million tonnes of methanol demand. So how quickly do you see that ramping back up into the next few years? And then could you just give a breakdown of where you see industry utilization by region?
Yes, I'll have to get back to you on industry utilization by region. I keep a lot in my brain, but I don't keep that. So Kim will get back to you on that one. As far as methanol demand recovery, I mean, if you can tell me, country by country, what governments are going to do to deal with a global pandemic, I could give you a number. But governments have been very inconsistent with their approach, and in my opinion, have been somewhat reactionary. So I don't know what governments are doing. Certainly, France is now shutting down and Germany is shutting down, and other governments are letting things be wide open. So I think this pandemic or this COVID-19 virus is going to be with us for a long time. A vaccine will eventually be developed and it will take some time to inoculate everybody, and we'll maybe get back to somewhat of a new normal. But I think this is going to be with us for a long time, and that's why we've tried to build in as much liquidity and financial flexibility as we can to be ready for all possible scenarios, including reduced demand again and whatever we might be seeing from a COVID-19 pandemic.
The next question is from Nelson Ng of RBC Capital Markets.
Just a quick question. You mentioned that Titan and Chile IV were the plants with the most flexible, I guess, gas supply arrangements. And now you're restarting Chile IV. But I guess when we look at various scenarios, like if there's another drop or material drop in the methanol price, like is there a lot of flexibility to, I guess, wind down Chile IV sometime over the next, like, 2 quarters? And if methanol prices continue to move higher, are we really looking at Titan? Or are there other facilities where you can -- where you'll look to try to squeeze out more production?
We try to run our plants at full rates all the time. So if they're not running at full rates, it's usually as a result of gas not being fully available, like we're seeing in New Zealand. But our goal is to run our plants at full rates. So Chile IV, again, we have total flexibility there. So based on our current look for supply/demand, we're not bringing it up for a couple of months. We're bringing it up -- we think we'll be able to run it right through until the next time we need to shut it down, which is as they come into their wintertime, which is the spring -- our spring next year. So we expect to run that plant for a good 6 months. So we're not thinking of bringing it up to shutting it down. But we would have the flexibility to do so if things got really dire again, but that's not our current view. So you should expect us to run Chile IV right up till their wintertime next year is our current thinking. As far as Titan, I think we took it down. We don't have a gas contract that allows us to be cash positive through the cycle. There's a lot of uncertainty out there with methanol demand and supply. So I would say, I never wanted to make black and white statements, but it would be difficult for us to restart that plant without some certainty around a gas contract for the foreseeable future. Once you take the plant down for a significant amount of time like we have, there's quite a bit of cost involved in restarting it. So unless we have some certainty around gas because we're not that certain around methanol markets and pricing, it would be difficult for us to start it up. But if we were to start it up, I think we'd get a lot of comfort in higher methanol prices for a longer time, which means to me a demand recovery and some sort of stabilization as a result of COVID-19. But I don't see that in the next 1 or 2 quarters in our current year.
I see. So just sort of Titan, if you were to restart it, obviously, there's a bunch of start-up costs. And from your perspective, would you -- would Titan have to run for like at least a year or 2 to kind of make that -- in order for that to make sense?
Yes, I'm not going to put any lines in the sand. I think we don't want to go back to a month-to-month pricing arrangement is what I would say, which is what we had from -- in January to April when we shut it -- or March to when we shut it down. So we're negotiating, and we're still optimistic we'll get something done with the government. But until we do, I think in our planning, it'd be very optimistic to bring Titan up in this environment.
Okay. And then just on a follow-up. Can I just talk about the cash on the balance sheet? Obviously, there's about $1.2 billion of cash. And you're due to repay the 2022 debt, I guess, soon. But how should we think of the cash on the balance sheet? Is this something you're looking to kind of hold on to? Or are you kind of in the process of making some decisions on what to do with that cash in terms of whether you like repay the construction facility or, I guess, any other potential uses?
Preserving liquidity and financial flexibility are our top priority right now. So we'll continue to look at how markets develop. I think the good news, based on our current forecast pricing for Q4, we'll be cash positive again after maintenance and dividend and all the things. So we won't be eating into cash. So I think that's really good news. But is that sustainable? I'm not prepared to put my hand up and say that yet. But I think we'll leave that cash there to allow us flexibility and depending on how markets develop, we'll be good stewards of cash, like we always have. We're not going to hoard it. And if we get to a place where we see things where we can generate a lot of cash -- and just remind you, at $300 a tonne, which is not too far from where we are today on a realized basis, we generate a nice amount of free cash. So too early to be making decisions around that, and our goal is to preserve liquidity and financial flexibility.
The next question is from Hassan Ahmed of Alembic Global Advisors.
John, wanted to revisit a comment you made earlier around Argus and Argus sort of talking about certain MTP facilities coming online. I mean I, too, was quite surprised by that, particularly keeping in mind some of these propane dehydrogenation facilities that are coming online in China. So again, on the MTP side, I mean, do you really think any of those facilities are going to come online? And then parlaying onto that, what are your views about the MTO operating rates as you look into 2021? I completely understand demand is uncertain right now because of the pandemic. But just on the supply side, I mean, there's just so much ethylene capacity that seems to be coming online in China, it came online this year, continues to come online regardless of what the demand picture looks like. So how are you thinking about the MTP restart and MTO operating rates in 2021?
Yes. Our view on MTO hasn't changed. I mean we said the first wave was going to get built and run, and that's what's happened. I mean, they've been running throughout the pandemic under less than $400 ethylene at 90% rates, unless there's been a technical issue. Nobody that we know has been taken down for so-called economic reasons that I read about in Argus all the time. And through the pandemic, it was probably the one demand source that was steady. So that's pretty interesting. And that has always been our view based on talking to them, is once these get built, they're integrated, and they'll probably run. They may take maintenance at different times of the year. These are fully integrated projects. But they need the ethylene and the propylene to make all their derivatives and that they're selling every day in the market. And some of these sites make 10 products, some make 4, really depends on the site. So the economics of running or not running are different for each and every site. And that's what we look at. We don't just look at methanol price and then what is propylene and ethylene trading at. I think that's a very simple model that doesn't really capture the full economic value of the site on any given MTO project. So we've said that consistently. And I think history has proven us right up to now. That doesn't mean we'll be right in the future. I don't predict the future. But we talk to them, we look at their operating rates. And 90%, we think, is full rate just because they're always going to be in a turnaround or some sort of technical. And these are large demand users of methanol. An average plant might use 1.8 million tonnes. So to have a 30 or 60-day outage, that really impacts the overall operating rates. I think there are 13 sites or something like that. So they're big. And when they go down, they have an impact on methanol demand. So around 85% to 90% is what we would guide to. And I think that's what we'll see. If they ran at that rate at less than $400 ethylene, then why wouldn't they in the future, but we'll see how it turns out. MTP, that, to me, is really economic methanol to propylene, and then you're competing with PDH and crackers and ethane crackers and naphtha crackers. And maybe short term, it could make sense to make some short-term cash, but I really don't see it sustainable. That's what we were told back in 2016 when the 4 plants went down because of the oil collapse last time and PDH and propylene prices collapsing, that's what we were told. Is there some conditions today that may make sense to make a bit of cash for some time? I don't know. I just don't see it sustainable. But in this one, I hope I'm wrong. I hope they come up, all 4 of them, they run forever. That would be great. But I'm not counting on that in my forecast.
Very fair. Very clear. And as a follow-up, John. Medium to longer term, I guess, it's a struggle to even think about anything beyond the pandemic. But medium to longer term, with the volatility that we've seen in methanol prices, I mean, what are you guys seeing in terms of some of these sort of greenfield capacity addition announcements that had been made? Are you seeing sort of delays, cancellations? I mean, sort of longer term, let's say, 4, 5 years out, how are you guys thinking about, call it, a supply growth CAGR or however you may think about supply growth?
No, I think it's a great point. In this environment, it's very difficult to be running plants today, never mind building new ones. So our current view is the Trinidad plant will get running well and providing product at some point here in the coming quarters. The Yuhuang coal plant will get finished and will run and provide methanol. Beyond that, there's no shovels in the ground. So there's a few projects, I think, in Russia and some new supply in China that will displace existing production. And then the big wild card is Iran. I think there's been plants under construction in Iran for a long time. And plants that have, according to Argus, been running, which we haven't -- we watched the shipments out of Iran. That's how we know how much they're producing because there's not a lot of demand within Iran, and it hasn't changed all that much. So that, to me, is the big wildcard, how much production do we get out of Iran in the next 3 to 5 years. And I don't have an answer for that, but we'll continue to watch it. But beyond that, there's not going to be, in my view, a lot of willingness to lend a bunch of money to this industry to build more methanol plants in this environment, especially since '16, we've seen tremendous volatility. And since '09, we've had now, in just over 10 years, 3 very volatile cycles. And it's not a lot of fun at $214 a tonne even if you are the low-cost producer. So I can't imagine others looking to invest in this industry in the medium term.
The next question is from Mike Leithead of Barclays.
I wanted to go back to, I think, in your prepared remarks, you made a comment about 4Q production being higher. I was hoping just given the restart of Chile IV, G1, some of the turnarounds coming back online, if you could give us just a little bit more color around the order of magnitude we should expect in terms of the 4Q step-up, which I assume should also help some of your product mix as well.
Yes, I don't really guide to plant by plant operating rates. I think I've given enough guidance that you can come to the right number. We're not having any turnarounds. I've given the number for New Zealand, so you can look at the capacity for other plants and kind of figure it out. But I'd rather not give a plant by plant guidance.
Fair enough. And then I did want to go back to Titan and a potential restart there. Kind of parsing between your words a bit, is it fair to say that getting Titan eventually back up and running is more dependent on getting the right natural gas contract structure in place versus kind of demand coming back? Or how should we think about what would need to happen in order to get Titan back online?
Yes. So a little bit of history is probably helpful. We had a 5-year contract that ran out at the end of December, and we were always clear with the NGC that we wouldn't continue to run unless we had a gas contract. Methanol market conditions were different then, and we came to a short-term arrangement as we were negotiating to keep the plant running on a day-by-day basis on a fixed price gas as we're negotiating. But our goal was never to run the plant without a medium-term 5-year gas contract. But in good faith, we worked to do that with the government. But as soon as COVID hit and the demand destruction happened and pricing cratered, it made no longer sense to follow that strategy. And we were very open with the NGC that we would be taking the plant down, but we would still be negotiating in good faith a contract that allowed us to generate EBITDA throughout the cycle. And that's where we are today. So again, I never say never about anything, but would be unlikely for us to restart the plant in this environment without some sort of firm gas price arrangement with the NGC that takes us out 3 to 5 years. So we're still optimistic we can get there. But until we're there, we're not going to be running.
The next question is from Matthew Blair of Tudor, Pickering, Holt.
I just wanted to circle back. You mentioned some costs associated with restarting Titan. With the Chile IV restart, do we need to factor in any incremental cost into our Q4 modeling for that?
Well, again, I'll remind you on my guidance for Chile IV. Our plan was always to take it down during their winter months, COVID or no COVID, because gas is not available in that part of the region to run 2 plants during their wintertime. So that would have been baked into our plans for 2020 and 2021. That's our operating model. So any associated costs with that would have been baked into our plans. Titan is different. We weren't planning on shutting it down. We were optimistic we would get a gas contract. And so there would be some additional cost. I'm not prepared to say how much or -- but when we take Chile IV down, we take it down in a way that we're going to start it up in 3 months. And Titan was taken down with the intent of starting it up, but there'll be some additional costs. The order of magnitude, not really prepared to say until we have more detail.
Okay. Sounds good. And then you had a pretty big inventory draw in Q2 and now again in Q3. Are you happy with current inventories? Or do you feel a need to build those back up in the coming quarters?
Yes. Lots of help there. When we saw what happened in the markets, liquidity was our #1 focus, working capital release was our #1 focus. I think our marketing team and our supply chain did an outstanding job in reducing our working capital. We're still keeping every single customer and their demand 100% satisfied even though it was very volatile. So again, we demonstrated our value to our customers about being flexible, agile and meeting their needs, whether they're up or down or the same. So I'll leave that to our supply chain people to decide. And they try to optimize working capital while keeping our customers satisfied, and that's what they'll continue to do. And there'll be some fluctuations, but our guidance there is still the same. And some quarters will be a little higher, some quarters will be a little lower. But when you think about it, we're selling over 10 million tonnes of methanol, our average inventory is around 1 million to 1.1 million. 1/3 of that is at the plant, 1/3 of that's on the water. So only 1/3 of that is servicing customers. So 300,000 to 400,000 tonnes servicing 10 million tonnes of sales. Our team does an outstanding job each and every day in keeping working capital low and servicing our customers.
The last question is from Laurence Alexander of Jefferies.
Just one quick one then. Given the benchmarks you gave for the green hydrogen, what would be the equivalent price of merchant -- of methanol plus offsets, either carbon credits or other offsets? So just so people can think if a customer wants to have a green methanol pipeline as part of their claim, what is the transition cost until the green methanol technology is sorted out?
I'm not sure I understand your question. The cost for producing green methanol, like we do at CRI, is approximately 2x what it would be for natural gas-based methanol, if that's your question.
No, what I was going to -- if the customer would like to have -- be able to claim that they are using carbon-neutral methanol, and they went out into the market to buy a carbon offset or funded renewable electricity or some other kind of program to offset, do you have any sense for what that cost would be relative to the cost of just doing green methanol with the CRI technology?
I guess it depends on the price of the carbon offsets, which I understand, trade on the market, and that's pretty volatile as well. So you're probably above my pay grade there, Laurence, on that question. Okay. Thank you. And we are encouraged by recent early signs of economic recovery, including improvement in methanol demand and an increase in methanol prices. Thanks to the dedication and agility of our team members worldwide, we continue to operate our plants safely and reliably and deliver secure reliable supply to our customers worldwide. In this uncertain environment, we remain focused on strengthening our business by preserving liquidity and improving financial flexibility to enhance our ability to navigate potential near-term challenges and execute on our strategies to deliver value to our shareholders over the medium to long term. Thank you for joining us today, and we'll speak with you in January. And thank you for the ongoing interest in our company.
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