Methanex Corp Q2 FY2023 Earnings Call

Good morning. My name is Chris, and I will be your conference operator today. At this time, I’d like to welcome everyone to the Methanex Corporation 2023 Second Quarter Results Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session. I’d now like to turn the conference call over to the Director of Investor Relations at Methanex, Ms. Sarah Herriott. Please go ahead, Ms. Herriott.

Good morning, everyone. Welcome to our second quarter 2023 results conference call. Our 2023 second 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 outcome to differ materially from the actual outcome. Certain material factors or assumptions were applied in drawing the conclusions or making the forecasts or projections, which are included in the forward-looking information. Please refer to our second quarter 2023 MD&A and our 2022 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, average realized price, EBITDA, adjusted EBITDA, cash flow, adjusted income or adjusted earnings per share made in today’s remarks reflects our 63.1% economic interest in the Atlas facility, our 50% economic interest in the Egypt facility and our 60% interest in Waterfront Shipping. 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. These items are non-GAAP measures and ratios that do not have any standardized meaning prescribed by GAAP, and therefore, unlikely to be comparable to similar measures presented by other companies. We report these non-GAAP measures in this way because we believe that they are 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. Rich Sumner for his comments and a question-and-answer period.

Thank you, Sarah, and good morning, everyone. We appreciate you joining us today as we discuss our second quarter 2023 results. For the second quarter, our average realized price of $338 per ton and produced sales of approximately 1.62 million tons generated adjusted EBITDA of $160 million and adjusted net income of $0.60 per share. Adjusted EBITDA was lower in the second quarter compared to the first quarter, primarily due to a lower average realized price. The declines in the average realized price were driven by global methanol supply outpacing demand growth and lower global energy prices, leading to a decrease in the methanol cost curve and methanol-to-olefins affordability. Methanol demand in the second quarter increased modestly compared to the first quarter of 2023, and we continue to monitor demand closely given ongoing macroeconomic headwinds. Demand for traditional chemical applications, which represents 50% of global demand, increased slightly compared to the first quarter but remains at or slightly below 2022 demand. This is mainly due to the slower-than-anticipated pace of economic recovery in China and the impact of inflation and resulting monetary policy actions on the rate of global industrial activity. Demand from energy-related applications such as MTBE and fuel blending increased during the second quarter driven by improved mobility in China, as well as continued cost competitiveness in methanol. MTO operating rates also improved slightly compared to the first quarter when a number of units underwent outages. Although MTO affordability remains under meaningful pressure as a result of continued low olefins pricing. On the supply side, methanol production from China and Iran faced natural gas restrictions in the first quarter, increased steadily throughout the second quarter, and strong operating rates in other regions led to global methanol supply outpacing demand growth and higher global inventory levels. Declining coal pricing in China in the second quarter also put some pressure on the methanol cost curve, with coal prices moving from over RMB1,000 per ton levels to approximately RMB850 per ton currently. We estimate the industry cost curve based on the marginal coal producer cost in China to be approximately $260 to $280 per metric ton. During the second quarter of 2023, our global average realized price was $338 per metric ton compared to $371 per metric ton for the first quarter. The declining spot prices in the second quarter, primarily in China, led to a higher discount rate of 25%. Our August posted prices in North America, Asia Pacific, and China were posted at $516, $315, and $305 per metric ton respectively, and our third quarter European price was posted at €395 per metric ton. Based on our July and August posted prices, we estimate our global average realized price to be approximately $290 to $300 per metric ton for these two months. Turning to the emerging marine fuel demand, announcements from the shipping industry for new dual fuel vessels continue to accelerate. In the second quarter, Maersk announced a further 17 ships and Evergreen ordered 24 dual fuel container ships. In addition to these new build orders, we are now seeing growing interest in dual fuel retrofits with Seaspan announcing to retrofit 15 vessels. By 2028, we now estimate approximately 200 dual fuel methanol ships to be on the water with potential demand of over 6 million tons per year, which is an increase of around 2 million tons per year compared to the demand number I reported at the end of the first quarter. We ended the second quarter in a strong financial position with approximately $600 million of cash and $300 million of undrawn backup liquidity. We continue to carefully manage the balance sheet, and our current cash position allows us to operate the business with all remaining G3 spend fully funded. With continued macroeconomic uncertainty and the impact of declining methanol prices through the second quarter, we ceased share repurchases under the normal course issuer bid, which expires in September 2023. Our intent remains to repay rather than refinance the $300 million bond due at the end of 2024, and under current market conditions and pricing levels, we will be prioritizing excess cash towards this repayment. Construction of our G3 project is progressing safely, on time, and on budget, with production expected in the fourth quarter of this year. Overall, the G3 project is around 90% complete. The project team remains focused on safety and delivering a high-quality and reliable plant. The expected G3 capital spend remains unchanged at $1.25 billion to $1.3 billion, and the remaining $240 million to $290 million of cash expenditures, including $65 million in accounts payable, is fully funded with cash on hand. Looking ahead to the third quarter of 2023, we are expecting lower adjusted EBITDA compared with the second quarter as we expect to realize a lower methanol price and have lower production with seasonal gas restrictions in Chile and a turnaround schedule in New Zealand. Our overall production guidance for the year of 6.5 million metric tons of equity production, excluding G3, remains unchanged. We remain focused on delivering strong operational results from our existing assets and completing the G3 project safely on time and on budget. We are well-positioned during this period of economic uncertainty with growing cash flow generation capability from G3 and a portfolio of assets that can generate cash flow across a wide range of methanol prices. We would now be happy to answer questions.

Thank you. First question is from Jacob Bout with CIBC. Your line is open.

Good morning.

Good morning, Jacob.

I had a question on the discount rate, a little more than what we had expected and you’re indicating that the spot market in China declined a little faster than you thought. Given the recent improvements that we’ve seen there, does this mean that we see some improvement in the back half of the year?

Yes. I mean, where we are right now, we’ve given the guidance; we’ve seen some improvements in China pricing. I think prices moved down into the $230 to $250 range, and we’re now back up to around the $260 range today. Our guidance on when the market is stable is the $21%. We’re giving you kind of where we sit today based on July and August, incorporating all of the market conditions at $290 to $300, which I think is probably around a 22% to 24% discount for the third quarter based on those numbers. I think there’ll be slight improvement, and we’ll just have to see how the market trends, but our deviation from the guidance of that, I guess, around 4% is not unusual from our guidance when we do see a move in the quarter where prices decline throughout the whole quarter.

Okay. And then just on the supply-demand fundamentals for methanol, I think you noted that global methanol supply is pacing demand and leading to some higher inventory levels in the quarter. Just talk a bit about how those inventory levels look across regions and when do you see the market rebalancing?

Yes. From a pure inventory perspective, we saw really high operating rates outside of China. What that meant is that I’d say the Atlantic markets are probably sitting on high inventories. Customers are not carrying a lot of inventory. Today, they’re managing things quite carefully, so we don’t think there’s a lot of buildup from customers. It’s more the methanol producers that are carrying inventory. In China, we had a build, but I would say the coastal inventory in China is still not well above historical norms by any means. However, we have seen inventories outside of China increase, and what that’s meant is you’ve seen trade flows moving to different jurisdictions to find homes. So I would say, China has increased, but it’s probably just above kind of historical averages, whereas outside of China, because of high operating rates, methanol producers are mainly carrying that inventory, with consumers still carefully managing things, given the economic situation we’re in today.

And then on the balancing question.

On the balancing, I would say, these summer months tend to be the peak operating period in our industry, where we see restrictions happening. As we get into the third quarter and into the fourth quarter, we tend to see operating rates come off naturally. And that’s something we see every year. So that combined with stronger demand, which is something we have to continue to watch, we think the balances would improve. But again, it’s going to be dependent on operating rates and the strength of demand.

Okay, thank you.

The next question is from Joel Jackson with BMO Capital Markets. Your line is open.

A few for me. I’ll just go one by one. Can you talk to me about the fact that north American prices, both spot and host prices are really trading at really high levels versus other markets. Is that sustainable?

I think what’s happened, Joel, over time, is that through contracting, we’ve seen a big spread on discounts, just based discounts from customers. So you’re naturally going to see a larger discount in those markets from within our contracts. Yes, your observation is correct there; we’re going to see a bigger spread between contract and spot. Right now, when we look at our realized pricing, we’re guiding in that $290 to $300 for July and August off of our contract pricing, which again, is probably that 22% to 24% discount. So we’re not seeing our pricing going down all the way to where spot is trading globally. I think average spot globally is in that $240 to $250 range, but we don’t expect to see that in our average realized pricing.

Okay. Second question. There’s been a lot of good headlines, and it seems like progress on gas development in Argentina. Can you talk about that and where could we see maybe some legitimate upticks in some of your gas allocations or gas availability in Chile from that?

Sure. Yes, I agree with you. What we’re seeing is really the Neuquen Basin that’s being developed and in particular the Vaca Muerta field, where international oil companies have been developing that basin. It’s a prolific shale play. Understand that the economics are kind of similar to the Permian. There’s a lot of gas there. What Argentina has been working on is building pipeline connections into the grid to allow that gas to flow to help their balances. As a reminder, Argentina’s importing on a per base load perspective, imports natural gas from Bolivia. During the winter months when they hit peak demand, they also have to rely on LNG imports to satisfy their energy needs. They’ve been building pipeline connections; one of the big ones just recently got tied in. We understand that this is anywhere from 10 million to 20 million cubic meters per day of gas flow. That represents anywhere from 10% to 20% of Argentina’s total gas demand. This has the ability to really change the gas dynamics for the country. There’s development that’s happening in the middle of the country. There’s gas development happening in the southern basin, which is close to our plants, which is meant to come online at the end of 2024. All of those dynamics point to the fact that they’re going to need new markets for that gas. We are a natural market for that gas in the south assuming that the balances get developed and get tied in. So we’re optimistic. Right now, I’m not going to give guidance to the fact until we get progress. I’ll guide on upside to Chile. We’re going to continue in earnest to have those discussions to contract more gas, and I think we’re very well positioned.

And finally, what would permit you to restart the buyback? What do you need to see in the past your predecessor talked about a minimum methanol price, maybe a liquidity buffer? You want to pay $300 million of debt down first. What would be the catalyst to restart the buyback?

We feel we’re in a very strong position from a balance sheet perspective. That’s number one. We’ve got enough cash to run the business. We’ve got G3 fully funded. We have the intent to repay the $300 million bond, and under current market conditions, we would be focused on that. In the medium to long-term, we still see favorable industry dynamics for methanol, and we see a tight industry going forward with demand outpacing supply. Notwithstanding, we’ve got some near-term headwinds to navigate through. So in the medium to long-term, we’re quite positive. If we see more favorable industry dynamics, then we will be reviewing our cash generation capability of paying down debt, as well as start to consider share repurchase. I’d say we’ll be somewhat market-determined, and in the medium term, we’re positive.

Thank you. The next question is from Nelson Ng with RBC Capital Markets. Your line is open.

Great, thanks. Just a follow up on Joel’s question on the restart of the NCIB. So just to clarify, I think in the past – if you guys had call it $200 million to $300 million of cash on the balance sheet, and I think if you were fully funded with G3, you would allocate most of the cash flow to buybacks. So if you’re finished with G3, if you’ve repaid the debt, and if you have, let’s say, $200 million to $300 million of cash on your balance sheet. Would that be a good environment to restart the NCIB?

No, I probably wouldn’t want to commit to that right now. I think our biggest thing under the current market is to protect the balance sheet where we are today, complete G3. Debt is the focus at today’s pricing levels. But certainly, if you look at our cash generation with G3 at mid-cycle pricing, we do generate a lot of cash. So I think what we need to do is get back to there before we start committing to anything on the NCIB. There’d be a lot of cash beyond $300 million in debt, and we don’t foresee a lot of near-term capital expenditures.

Okay, got it. The next question relates to methanol as a marine fuel. So you mentioned that by 2028, there’ll be about 200 dual fuel ships in the water. Roughly, how many are there today?

Today, we’ve got our 19 in the water, and then I think there’s another six methanol vessels or so, and then there’s a few others now in the water. So it’s probably under 30. The remaining will get to the 200; those will be new builds and retrofits in the period from now until 2028, most of those would be on the water in the 2027 and 2028 timeframe.

Okay.

But again, the momentum continues on this, and we do expect that number will continue to grow. We’ll continue to report how that happens each quarter.

Okay, thanks. And then in terms of the ships in the water today excluding your own ships, how do they currently run on dual fuel? Do they still use mostly bunker fuel and methanol when they’re near the coast, or how do they, like, what’s the typical pattern?

We’re burning methanol 100% on our vessels today. We don’t know for sure, but we suspect that other vessels are also methanol vessels as well, so it’s very easy for us; we load our fuel at the same time we load our product. It becomes quite an easy bunkering situation. We suspect that our competitors are doing something similar. The other vessels that are on the water are quite small. I think Maersk just put their vessel on the water, and they did a trial with green methanol, so we know that they’re interested in methanol, but they’re also looking at how they can fuel it with green methanol.

Okay, that’s great. Thanks for the clarification. I’ll leave it there.

Thanks.

The next question is from Hassan Ahmed with Alembic Global. Your line is open.

Good morning, Rich. Two-part question. Hi there. Two-part question on the near-term and maybe medium-term supply situation. On the near-term side of it, you guys have obviously talked about Q1 to Q2 sort of incremental production in Iran, but recently I’ve been reading a fair number of articles about ridiculously hot temperatures over there and again, some redirecting of natural gas away from the industrial consumers to the residential consumers. So near-term-wise in Q3, what do you see as the supply situation in Iran? And then continuing with the supply side of it, again, I’ve been reading some rumblings about China sort of forcing non-money-making chemical production capacities to shut down some inefficient facilities. Are you seeing that on the methanol side as well?

Sure. I think your point is well taken that I think it’s not just Iran. We’re seeing this in a lot of jurisdictions right now with extreme weather causing a demand pull for natural gas for residential cooling. What we do know is in the first quarter, Iran is not always easy to get a full picture, but we do see things through the shipping and imports statistics. In the first quarter, our implied operating rate was less than 50%. Through the second quarter, they got up to probably the 60% to 70% range, with 11 million or 12 million tons of capacity. So a 10% increase could lead to 1 million to 1.5 million tons of annualized supply. This certainly contributed to supply shifts in the market. We would also say there’s some risk to them being able to maintain that, given the dynamics you just described. Further out, there’ll likely be a shift in Q3 and into Q4. They’re under significant pressure, and we know it is difficult for them to keep their gas system supply in a sanctions environment. As for your question about China, we’ve seen the shutdown of smaller scale plants. We’ve seen this over time where their preference is to shut down less efficient plants and have larger scale operations into industrial complexes. They are quite conscious of that from an environmental and energy perspective.

Very helpful. And as a follow-up, again sticking to the weather side of things, but as it relates to natural gas this time around, obviously, we’ve seen extreme volatility in natural gas prices both within the U.S. and globally. Has there been some sort of a rethink about your own sort of natural gas hedging program?

Right now, as you might know, in North America, we’re actively managing our contracts. All of our other contracts are on longer-term agreements with methanol sharing components. North America, we continue with our hedging program, and we’re well hedged into our targets for a three-year period, and we’re looking beyond that as well. We’re going to continue to stay open to longer-term contracts on a fixed basis if longer-term pricing is available, given that volatility.

Very helpful, Rich. Thank you so much.

The next question is from Steve Hansen with Raymond James. Your line is open.

Yes. Good morning, guys. Thanks for the time. First question, Rich, is I wanted to circle back to a question earlier. Can you just give us a bit of a broader perspective here? So am I to interpret your comments to suggest the spot contract spreads will remain excessively wide for the foreseeable future? How should we think about that? I’m just looking at the U.S. spread in particular as being something we’ve never seen. So how should we think about that from a longer-term perspective and what that means for your discount rates?

Yes. First and foremost, the contractual discounts have gotten big. That’s the most important starting point; the discounts are what gets us to our average realized price. The further discount to spot varies. North America is a heavily contracted market, not a spot market. Limited volumes trade on a spot basis. In those situations where maybe producers have under-contracted, you see a heavy further discount in the market. It’s not structural long-term, but those contract discounts are bigger.

And can I just ask as a follow-up? That’s a good context. As a quick follow-up, what is it that’s driving the contractual discounts to be larger? Is it volumes coming in from other regions?

It’s the fact that producers have started up in North America. It’s very attractive to service domestic markets versus export markets. There’s been increasing competitiveness for marketers with consumers, and that has meant larger discount spreads over time. I remember when I was in North America that discounts were quite possibly maybe 15% lower than they are today.

Interesting. Okay. No, that’s really good perspective. And just one quick follow-up for me is just on the G3 cadence, obviously you’re well advanced here. Q4 startup is just around the corner effectively. Is it still fair to assume that no major commercial volumes will be shipped in Q4, or should we expect a little bit? How do you feel about the timing of that Q4 startup and shipments?

I think we would guide that it will impact the market through our sales in 2024. We’ll have an inventory build through Q4, but before it really gets into our sales system, it’ll be in 2024.

The next question is from Ben Isaacson with Scotiabank. Your line is open.

Great. Thank you, and good morning. Rich, I’d like to ask a multi-part question. I’m just trying to figure out why prices are where they are right now. You mentioned that China, or sorry, you mentioned that the marginal cost of production is $260 to $280, but in Europe the price is $220 and China, it’s below that; in the U.S. it’s $230-ish. So are we seeing capacity closures right now? How much does the cost curve matter? As part of that, if you go back over the last 10-15 years, how much has methanol been set by the cost curve versus set by affordability? And then just as a final part of that, we always think about mid-cycle pricing but China seems to be trying to push coal prices lower for its power users. How confident are we that we’re going to get back to that $350-ish mid-cycle level in the future?

Okay. A lot to unpack. When pricing is typically set, it’s usually set by the marginal cost of production. As of today, we have pricing in China. The cost curve we said is $260 to $280. Pricing in China is on the low end, around the $260 level. The reason it’s pressured is due to the olefins market where there’s a marginal buyer under pressure with olefins pricing. Right now, the pricing is probably a blend of what’s driving the price in China, which is the price setter for the market. It’s probably a blend of coal production cost plus the ability to purchase from the MTO sector. Prices for the U.S. still show a premium. Our pricing for July, August is $290 to $300; that gives us a premium over $30 a ton globally. Mid-cycle pricing has seen average realized prices around $350 a ton historically. It doesn’t take much for us to get to that realized price. Right now, we’re in a supply-demand imbalance with high inventory and weak olefins pricing. Coal prices today can easily still support a $350 price. It’s been ranging between RMB800 and RMB900. We’ve generated $350 realized prices before, so it’s not that far to go assuming we see more favorable trends.

Sure. And just on that, what percentage of time has methanol lived off the cost curve versus being priced based on affordability?

One could say we’ve seen it live off the cost curve for a significant part of the previous years, with some blending happening more recently due to competitive pricing dynamics. This mixture has varied significantly over time.

And then just my follow-up, you mentioned that customers are not carrying inventory. Given that prices are historically low right now, why do you think that is? Why wouldn’t they be coming back in the market and restocking?

I think it just has to do with the general economic outlook and manufacturing output hasn’t been really strong. That’s the concern—despite some economic numbers that look okay. A lot of that’s being driven by consumer spending, but in services and not so much on durable goods. That has meant manufacturing output hasn’t been as strong as we would have hoped, and this leads our customers to be cautious in their buying behavior.

The next question is from Laurence Alexander with Jefferies. Your line is open.

Hey, good morning, everyone. This is actually Kevin Estok on for Laurence Alexander. Most of my questions have been asked, but I guess I was wondering if you could give us some updates or your thoughts on your strategy for green or blue methanol. That would be very helpful.

Sure. When we think about our strategy, it’s three-pronged. One is the demand side, working with our low-carbon solutions team focused on discussions with major shipping companies on their fuel choices. The second is supporting the bunkering and infrastructure. We’re the biggest methanol producer and have the biggest methanol delivery infrastructure. The third is looking at supply feasibility regarding decarbonization. We’re active in renewable natural gas markets and are exploring carbon capture projects. We also look at how to incorporate green renewable hydrogen directly into our existing plants, giving us an edge over building new projects. We’re pursuing these strategies from demand, infrastructure, and supply perspectives.

The next question is from Matthew Blair with TPH. Your line is open.

Hey, good morning. Rich, could you talk about your growth capital outlook after you finished G3? What types of projects would you be interested in? And what are the chances that you would green-light a potentially significant green methanol or some sort of renewable methanol project?

I think I’ll start with organic growth projects. G3 is the focus today in cleaning that safely on time and on budget, putting us in a good position in the medium-term. We’re watching industry growth and looking for the best opportunities but spending will be limited until we see favorable market dynamics. Low-carbon projects will be opportunistic; we'd look to partner or find ways to de-risk investments.

Okay, sounds good. And then could you discuss current MTO economics and operates versus Q2 averages? Are you expecting any new MTO capacity to come online in the next year or so?

Sure. There’s about 21 million to 22 million tons of MTO capacity. Currently at 100% that's methanol equivalent demand. During Q1, we had 14 million to 15 million tons of demand, and during Q2, we had about 15 million to 16 million tons. The industry is operating at around 70%, with two very large scale plants not operating today. Current affordability ranges anywhere from the low 200s to low 300s; it depends on their integrated downstream and the derivatives they go to. That’s complicated, but reflects historically low olefins pricing.

The next question is from Josh Spector with UBS. Your line is open.

Yes, hi, thanks for taking my question. I actually wanted to follow-up on MTO, considering the firms are building refineries and crackers. Are you seeing any feedback from customers that within two to three years it could pull some of the 22 million tons out of the market because they’ll bypass MTO?

That’s a great question. What those units are doing is commissioning mixed feed crackers with downstream expansions. They intend not to shut down MTO but expand their downstream capabilities while maintaining MTO operations. We think they’re really waiting for market demand to come back online. None of those constructions indicate a plan to remove MTO from the market.

No, I appreciate that. That’s really helpful. Thanks.

Okay, thank you for your questions and interest in our company. Looking forward, we’re well-positioned with our current asset portfolio and strong balance sheet. Our G3 project is fully funded, progressing safely on time, and on budget, and we expect to be in production in the fourth quarter of this year. We hope you’ll join us in October when we update our third quarter results.

This concludes today’s conference call. You may now disconnect. Thank you.