Methanex Corporation (MEOH) Q1 2026 Earnings Report, Transcript and Summary

Good morning. My name is Kate, and I will be your conference operator today. At this time, I would like to welcome everyone to the Methanex Corporation First Quarter 2026 Results Conference Call. [Operator Instructions] Thank you. I would now like to turn the conference call over to the Vice President of Investor Relations at Methanex, Mr. Robert Winslow. Please go ahead, Mr. Winslow.

Thank you. Good morning, everyone. Welcome to Methanex's First Quarter 2026 Results Conference Call. Our 2026 first quarter news release, management's discussion and analysis and financial statements can be accessed through our website at methanex.com. I would like to remind listeners that our comments today may contain forward-looking information, which, by its nature, is subject to risks and uncertainties that may cause the stated outcome to differ materially from actual results. We may also refer to non-GAAP financial measures and ratios that do not have any standardized meaning prescribed by GAAP and are, therefore, unlikely to be comparable to similar measures presented by other companies. Any references made on today's call reflect our 63.1% economic interest in the Atlas facility, our 50% economic interest in the Egypt facility, our 50% interest in the Natgasoline facility and our 60% interest in Waterfront Shipping. To review the cautionary language regarding forward-looking statements and to find definitions and reconciliations of the non-GAAP measures, please refer to our most recent news release, MD&A, annual report and investor presentation, all of which are posted on our website under the Investor Relations tab. I will now turn the call over to Methanex's President and CEO, Mr. Richard Sumner, for his comments, followed by a question-and-answer period.

Thank you, Robert, and good morning, everyone. We appreciate you joining us today to discuss our first quarter 2026 results. Our first quarter average realized price of $351 per tonne and produced methanol sales of approximately 2.2 million tonnes generated adjusted EBITDA of $220 million and adjusted net income of $23 million. Adjusted EBITDA increased versus the fourth quarter of 2025, primarily due to a higher average realized price, partially offset by slightly lower sales of Methanex-produced methanol. During the first quarter, cash flows from operations allowed us to repay $60 million of the Term Loan A facility, ending the period in a strong cash position with nearly $380 million on the balance sheet. Turning to our operations in the first quarter. Our total equity methanol production of 2.4 million tonnes was slightly higher compared to the fourth quarter. Starting with our United States operations, we produced 934,000 tonnes at our Geismar plant and 195,000 tonnes at the Beaumont plant in the first quarter. Our equity share of production at the Natgasoline joint venture was 203,000 tonnes. Our U.S. assets operated at high rates outside of a short period early in the quarter when production was reduced in response to a significant short-term spike in natural gas prices in late January. In Chile, we produced 398,000 tonnes in the first quarter, utilizing gas supply from Chile and Argentina. A third-party pipeline failure that occurred late in the fourth quarter was rectified early in the first quarter, and our plants operated at full rates for the remainder of the period. We're expecting to idle 1 Chile plant during the middle part of the second quarter, in line with gas availability during the Southern Hemisphere winter season. In Egypt, our first quarter production was similar to that of the fourth quarter with the plant operating at full rates. The plant continues to operate well today, and we're closely monitoring the regional situation for any potential impact on its gas supply. In New Zealand, we produced 158,000 tonnes in the first quarter, down moderately from the prior quarter. Despite the stable gas and production levels over the past few months, the structural gas outlook in New Zealand continues to be challenging. Our equity production for 2026 remains 9 million tonnes of methanol. Actual production may vary by quarter based on timing of turnarounds, gas availability, unplanned outages and unanticipated events. Now, turning to methanol industry fundamentals. The conflict in the Middle East, which began in late February, escalated into the second quarter. These events have significantly disrupted global markets for energy and petrochemical supply, including methanol, and we continue to monitor both short-term and longer-term impacts on global markets and our business. The Middle East supplies approximately 20 million tonnes of methanol per annum to global markets, and this has been significantly reduced since the beginning of March. Thus far, overall methanol demand has remained relatively resilient with no significant signs of customer shutdowns or demand destruction. In Asia and China, which rely significantly more on Middle East imports that need to bypass the Strait of Hormuz, we've seen no trade flows from the Middle East non-Iranian supply and very modest supply from Iran into coastal markets in China since late February and believe that downstream operations have been primarily sustained through the drawdown of inventories. We believe this situation will be unsustainable in the short term, and we're working closely with customers to understand their demand outlook. We're also trying to better understand the extent of damage to methanol plants and related supporting infrastructure in the conflict region, if any, and the length of time it might take to restore back to full operations, which is still unclear today. Given these unprecedented events, we've seen a rapid and significant escalation in methanol prices across all major regions through March and April. And we're well positioned in today's market with our advantaged asset base that continues to operate safely and reliably. As a result, we're expecting to see significantly stronger earnings and cash flows in the second quarter compared with the first quarter. Based on April and May contract price postings, we estimate our average realized price for April and May is between approximately $500 and $525 per tonne. Assuming this pricing holds through June and factoring in produced sales volumes similar to those of the first quarter, we would expect a significant increase in adjusted EBITDA in the second quarter, consistent with the first quarter and adjusted for these higher methanol prices. It should also be noted that due to the timing of inventory flows, there will be delayed recognition into the third quarter of cost increases we're seeing now from higher natural gas prices linked to higher methanol, as well as higher ocean freight costs from higher bunker fuels. We believe the current market dynamics could be prolonged for some time, and we're monitoring the medium- and longer-term impact and risks to the global economy. Our priorities for 2026 are unchanged: to safely and reliably operate our assets and supply chain; deliver on the OCI integration plan; and continue to progress our deleveraging goals. Based on our short-term financial outlook, we expect to repay the term loan of approximately $290 million in the second quarter. After the term loan is repaid, we will remain focused on directing the majority of our free cash flow towards the repayment of the bond due in 2027, while evaluating share buybacks with a smaller portion of cash if they represent an attractive investment for shareholders. We'd now be happy to answer your questions.

[Operator Instructions] Your first question comes from the line of Ben Isaacson with Scotiabank.

Rich, a supply-demand question for you. And I know on the supply side, it's very, very fluid in terms of intel. But based on your best understanding right now, what do you think has structurally changed when it comes to methanol in the Middle East? And assuming Hormuz opens, how likely is it that Iran will be able to kind of go back to that run rate of about 9 million tonnes a year, give or take? And then on the demand side, we know macro is challenging. We're seeing weak housing and construction. On methanol affordability, I believe there's a few small cracks in some of the smaller applications. So can you just discuss what you're seeing, the cadence of demand or how you're feeling about demand destruction?

Thanks, Ben. On the supply side, right now, we're -- it's difficult to get a read on exactly what could be sort of the longer-term impact on the supply side. There's a number of things that we're going to be trying to get a better read on. And so, it really starts with the infrastructure around methanol, and that would be the upstream. What -- if any, is there an extensive damage to upstream natural gas feedstock and related infrastructure? If there is, what will happen to gas allocations? Where will methanol fit in the pecking order? Has there been any structural damage to methanol plants or related logistics infrastructure? So all of those things we need to get a better read on in the -- as things start to stabilize, and we're not anywhere close to that today. So very, very, very important things for us to get a read longer term. When it comes into the demand side, for us, we haven't seen the demand -- any significant signs of demand destruction. Obviously, affordability is going to be really important. We do think that as -- particularly in coastal markets in China, the longer the blockade is in place, the lesser Iranian product will be flowing into coastal markets there, and we do think that will put pressure on MTO operating rates. We've seen methanol prices now, around the world outside of China, in the $550 to $650 range. And it's really a supply issue. So demand side, of course, we're very concerned what this means around higher costs. Right now, it's really demand still pulling the supply in. But what this means longer term in terms of inflationary implications and which end streams actually hurt the most, it remains to be seen. So we're working really closely with our customers to understand their demand outlook, their affordability levels, what impact this has both in the short term and long term. So it's a difficult one to be able to give you a lot of guidance on right now, but it's all things we're monitoring.

Your next question comes from the line of Hassan Ahmed with Alembic Global.

I just wanted to approach the earlier question a slightly different way. In talking to sort of a variety of chemical executives, it just seems that the normalization in supply chains, let's say, if peace was declared tomorrow and the Strait of Hormuz were to open up again, it just seems the way -- from sort of reopening the oil and gas fields, just the way the pecking order of various sort of chemicals, energy sort of sources, feedstocks and the like will work, it may take as long as 9 months from the opening of the Strait of Hormuz, from the declaration of peace, for these sort of supply chains to normalize. And then, obviously, as you rightly said, we still don't know the full extent of damage, particularly in Iran and certain other Middle Eastern countries. So I mean, as I sort of compare that to what I at least see in terms of consensus earnings estimates for you guys, I mean, they have you guys peaking in EBITDA in Q2 of this year and then a steep fall off thereon after, suggesting to me the consensus seems to be baking in a sort of V-shaped recovery in sort of volumes coming out of the Middle East. So I would love to hear your thoughts about this.

Yes. I mean, in the opening comments -- thanks, Hassan -- I did mention that we think this could be prolonged for some time. And what that means is, we don't think it gets fixed in short order like that. That gas infrastructure is really important, and we do think that methanol probably fits lower in the pecking order. When you think about energy products for power or for transportation fuels and fertilizers for food, we likely fit somewhere down the line in the pecking order there. So it will come down to how quickly does all the infrastructure can it actually get up and running, including the downstream, as well as the upstream. And then, you also have to think that inventories throughout the supply chain are significantly lowered. And we're not talking about just Asia Pacific here, even though it will be most acutely felt in Asia Pacific, but it's a globally traded market. And so, that's going to be drawing down inventories globally. And that's why we've seen pricing in the market run up globally. So we've got supply chains that have to be restored. We've got infrastructure that has to be back in place. We've got -- and on top of that, it's a 25- to 30-day transit time out of the Gulf. So we've got a lot of things that have to happen for these supply chains to come back. And it won't be -- our view would be that, that would very unlikely to be a light switch to happen. Now, the big thing for us is, how quickly does the demand side shut down, and do we see that happening in a big meaningful way? And then, when product does come back online, the supply get ahead of the demand restarting and those types of things. So we have to be careful about what kind of whipsaws could happen on the other side of this, which we do think will be prolonged. So hopefully, that's a little bit more context on that one.

Definitely very helpful, Rich. And as a follow-up, could you just talk a bit about sort of -- in this sort of new pricing regime that we are seeing, China's role, particularly as it pertains to the coal-based methanol, obviously, on the cost curve now, it's positioned quite differently. And the reason I ask you this is, particularly over the last couple of weeks, certain sort of further downstream chemicals like acetic acid, which rely on methanol, seem to have been coming under fairly severe downward pricing pressure in -- on the spot market in China in particular. So, I just would love to hear your views about pricing, particularly in China and how certain elevated pricing regimes in other parts of the world may actually hold up even if China puts some downward pressure on pricing.

Yes. Thanks, Hassan. So for us, when we look at our -- the pricing in China, we definitely think that it's a demand-driven price more than a cost side price for us. And it's really driven off the fact that there's 11 million tonnes of coastal MTO that are -- is a ready and willing market. So where we've seen pricing in China going from methanol is in the $400 to $450 per tonne range, which is very consistent with what you've seen around the affordability back to [ C2, C3 ] pricing, which a lot of that's driven off of naphtha price. So we do think that we're -- we've been saying for quite some time, methanol is increasingly a demand-driven pricing. And then, what we've seen is that the China price -- outside of China, we've seen pricing going into the $550 to $650 range. When we look at some of the downstream, you mentioned petrochemicals, and petrochemicals around methanol have been overbuilt. So even in the current environment, I'm assuming that a lot of the acetic acid that's come on stream over time has been a weaker -- it's been a weaker segment because of the economic -- the impact economically of what's happening. And then, of course, that -- those are consumers of methanol. So it's something we need to watch out for. Does that release more supply into the market if acid producers are lowering their operating rates? But we haven't seen a significant impact of that coming back into the supply base for us today, so -- but something we'll watch, highly driven towards a demand-driven cost curve for us. And that's on the basis that methanol is very different than other petrochemicals. We're forecasting to see a supply gap in the next 5 years of 9 million to 10 million tonnes. And that's still -- that supply still relied on Iranian production, existing production, as well as potentially new projects. So I think for us, we're in a structurally tight market ultimately, and we do think that leads more to a demand-driven cost curve.

Your next question comes from the line of Joel Jackson with BMO Capital Markets.

I'm going to ask a couple of questions on some of your marginal assets, and I'll do one by one. First, we talk about Trinidad. I've seen some of your -- so you obviously have a gas deal up for renegotiation later this year, one of those plants that are running. I've seen 2 of your [ nitrogen ] peers in Trinidad very recently sign very short-term gas deals. A third nitrogen peer has not been able to do so. Is that something you would consider doing? Like maybe describe the Trinidad environment, would you consider signing a short-term gas deal to keep the plant running, considering this very strong environment?

Thanks, Joel. I mean, right now, we're in discussions. Our gas contract is up in middle of September. We're in discussions with the NGC. We're considering all possible range of outcomes through those discussions, including a short-term deal, as well as the potential to have to idle the plants. It will come down to those NGC discussions. In the short term, Trinidad is an extremely tight gas market with LNG, ammonia and methanol, all operating below the nameplate capacity. And so, a lot of that's going to come down to those commercial discussions. But our team is looking at all possible outcomes, and also thinking -- we are looking longer term there and what optionality may come in. But we do think any new gas from Venezuela is quite a ways out and also carries risk on whether it can ever flow to methanol economically. So there's a lot for us to consider there. But yes, we would look at short term. We also are -- if we [ can't ] get, in the short and the medium term, to work together, we're also having to look at other outcomes out of those discussions.

Okay. And then, turning to New Zealand, obviously, just running the one plant there at quite low rates. Gas has been a problem there. And it looks like the Maui gas field might be closing end of this year, maybe making that situation worse. But what is the end game here in New Zealand?

So I mean, I'm going to start by -- I will kind of remind both New Zealand and Trinidad, while they represent over 10% of our production, it's less than 5% of our run rate earnings. So both these assets have performed extremely well for us over our history and operate extremely well. New Zealand, the issues around gas are not new to us. We've been seeing a deterioration in the gas supply for quite some time. And so OMV, our big gas supplier came out with an announcement that they would cease production on their Maui field by the end of the year. If that were to happen, we can no longer -- we no longer are capable of running our plant. So it's something we're working on with our gas suppliers, and we're looking at all options on how we monetize our gas position, including producing methanol or selling gas. And whatever we're doing, we're doing safely and reliably as we move towards whatever the resolution is going to be. But the outlook is tough, and it's structurally challenging there.

Your next question comes from the line of Jeff Zekauskas with JPMorgan.

In the event that your earnings slide up this year, what will happen to your cash taxes? Does your -- what would be the cash tax rate or responsibility in a much more profitable environment? And also, if you could comment on what would happen to your working capital? Would your receivables and inventories and payables go up at the same rate as sales? Or do you expect it to be faster or slower? Could you help us out on those issues?

Yes. I think I'll turn that question over to Dean Richardson, our CFO.

Yes. Thanks, Jeff. When it comes to taxes, our tax rate guidance of 25% does hold even in a different price -- a higher price environment. From a cash tax perspective, we have been guiding to the majority of our taxes being cash. However, in a higher price environment, the majority of our earnings would go to the U.S. And so, the percentage of our cash taxes would actually go down because of the significant assets and loss carryforwards we have in the U.S., given the acquisition and the build-out. So the percentage of our 25%, the cash tax would go down more towards the midrange of that. It would be about a 50-50 cash versus deferred. From a working capital perspective, certainly, methanol price has a significant impact on receivables. So we would expect -- and we did see some of that even in Q1. We would expect that in Q2 as well when it comes to our flow-through to cash flows that the receivable balance would increase with the higher price. From an inventory perspective, given we have limited purchases, most of our inventories are based on our cost structure of our plant. So we would not expect inventories to move. And there would be some offset in payables when it comes to that. So net-net, yes, we would expect a higher working capital balance due to the increase in methanol price.

And then, for my follow-up, given what you've already seen in April and whatever normal seasonal considerations there are, as a base case, would you expect to sell more produced methanol in the second quarter than you would in the first, all things being equal?

It will be highly dependent on our sales, and we're monitoring our sales quite carefully right now because obviously, looking towards, do we start to see any demand deterioration? We're also being very careful in today's environment around how much we buy as well. So if we have flexibility to not be selling in this environment, we may not be -- if it means we're covering that with produced tonnes, just given the risk that we could see things change. So to the extent that we hold our sales levels the same, you would probably see more produced tonnes coming through. If we were to decrease our sales, you may see about the same. So it's highly dependent on what our overall sales are. The majority of the inventory we are bringing through now is produced product. And that's a big change since we brought 4 million tonnes of North America supply on with G3 and the OCI acquisition.

Your next question comes from the line of Josh Spector with UBS.

I apologize if I missed this in the prepared remarks, but I guess, when you're talking about your realized pricing, you seem to be implying a discount rate that maybe is in the high-40s versus you realized in the low-40s this quarter. I wonder if you can kind of confirm that. And then like related with that, I thought when pricing is going up, the discount rate comes down as you're kind of catching up to that, and then vice versa when prices go down. So things seem a little bit backwards versus what I anticipate. So can you help me understand that?

Yes, Josh, well, for sure. What you're going to see is, when we think about the -- when we look into the second quarter here, we are expecting to sell a lower proportion of our sales in China. And that's mainly where we have flexibility on our sales and where we can reduce down the level of purchases. So that's sort of the plan today. And that -- what that results in is a higher discount because actually, pricing outside of China has higher discounts, yet a higher realized price. So we actually have higher and stronger average realized pricing when our discounts are higher. It's very -- a little backward in the way to think of it, which is why I tend to like to ignore discounts and focus on the average realized price as much as possible. But that's really the reason that you're seeing that.

Okay. That makes sense. And you made a comment earlier about some of the lags and some of the cost sharing agreements and that lagging into 3Q. That's also a bit longer than what I would anticipate. I don't think we've talked about those lags in the past really coming up. So if I interpret that right, it seems like you would over-earn a little bit in 3Q because maybe you're paying less on the equivalent gas basis versus what you would, and then, that would catch up. I guess, is that correct? And then, is there a way to think about like how long those lags are? Are they actually a 3-month lag? Or is it just that it's increasing month by month and that's kind of the catch-up we're talking about, just so we can sensitize that from a cost perspective?

Those are -- that's a fair question. So it really is about inventory flows, and we have about 45 days of inventory. So you will see some of those costs coming through, but not all of them. It won't be reflective of today's market structurally in the second quarter. So there's a lag, probably about $30 million, $40 million of that 45 days that will be coming in, in the third quarter. That would be more structural in today's higher pricing environment. And that's both on the -- includes the shipping and the gas.

Your next question comes from the line of Nelson Ng with RBC Capital Markets.

First question, just a follow-up on what was asked on Trinidad. So you mentioned that you're considering a number of options. For the Trinidad facility -- or the Titan facility, is it due for another turnaround after September 26? So like does the new contract need to be long enough so that you can fund a major turnaround?

The new contract -- no, there isn't a turnaround coming. But the economics of the existing contracts are -- the lion's share of the rents are going back to Trinidad. And any increase in any pricing means that it makes it very difficult for us to support running there. And so, obviously, a lot of this is going to be coming through the negotiations with the NGC. But I hope you understand that -- yes, that's -- obviously, we're progressing that. Indications look challenging.

Got it. Okay. And you did mention that New Zealand and Trinidad make up less than 5%. 5% of your run rate EBITDA or earnings?

Yes, 5%.

Okay. Got it. And then, my next question is about the OCI assets. I think initially, you guys provided an estimate of about $30 million of synergies that you're expecting to achieve. Can you just give a quick update on how that's progressed and what you still need to implement over the next several quarters to achieve that?

Yes. So those synergies come in, in the form of insurance, come in the form of logistics costs around terminal optimizations, come in the form of IT costs. It comes in the form of looking at how we optimize some of the sites that we have. We're in the -- things are progressing well. We're probably through some of the synergies. Others, we're actually carrying double costs this year like IT. So -- and we're progressing all that. We have a plan set out that by the end of the year, we should be through that. But we are carrying higher fixed -- we have a higher fixed cost carry this year to then achieve the synergies beginning in January of 2027.

Got it. It sounds like we'll see most of the benefits next year.

Your next question comes from the line of Hamir Patel with CIBC Capital Markets.

Rich, are you able to quantify the non-gas feedstock cost increases that you're seeing? And how much on a per tonne basis might that be once it's sort of fully apparent in Q3?

Non-gas feedstock costs.

Just your non-gas cost increases.

I see. So in the first quarter versus the fourth quarter?

Well, just by year-end as that filters through.

Okay. Well, it's mainly the costs that we're looking at. So if we think about -- I do know that there's some focus on how we get to our run rate numbers and what's in our cost structure that we're working on. The first one is our fixed cost structure, which the last caller asked about, where we are progressing to bring our fixed cost structure down through the year through the integration. The second area is ocean freight. We've had a longer supply chain through Q4. We had some lag into Q1 around our longer supply chain costs. We have seen a weaker backhaul market over the past year. That's something we're managing very closely. In today's environment, though, things have changed quite a bit around freight. Our focus around freight is around avoiding any type of spot vessel requirements in our system. Spot rates, we have -- there's 2,000 ships locked in the Gulf right now, and supply chains have increased because products got to move longer outside of the Gulf to meet demand. So spot vessel rates have gone up quite significantly, and the backhaul market has disappeared. So our goal today is to keep as little -- our ships also [indiscernible] product avoid any spot vessel requirements. And this is one of the competitive advantage we also have here is that we've got our own fleet, and we have no exposure to the shipping market. Now, our cost per tonne might be higher, but our cost per tonne is a lot lower than our competitors that face market rates today. So our attention around shipping has shifted here in today's environment, like a lot of parts of our business.

Great. That's helpful. And just the last question I had, in terms of your 2026 methanol production, what percent of that -- I'm guessing a very small percent would be spot.

Yes. In terms of our sales portfolio, we have very little in the way of spot sales. We do have some flexibility to put some product in the market. But today, our commitment is to our term contract customers, and that's who we're here to service. And we have long-term customers. We have term contract supply, which is a min-max commitment per month for their businesses. That's where our primary focus is on ensuring that reliability of supply today. To the extent that if our customers are unable to produce, we will have more product available into the market. But today, our commitment is to our contract customers.

Your next question comes from the line of Matthew Blair with TPH.

Rich, could you talk about where MTO operating rates stand in China today and how that compares, say, to like a Q1 average?

Yes. So thinking back to -- maybe I'll take back to Q4. Q4 MTO operating rates were close to in the 85% to 90%. We saw Iranian supplies actually stay on the market in Q4 until around the December time frame. And then, what we saw was a gradual lowering of MTO rates through Q1. Q1 average is around 70%, 75% rates. And through March -- we think some Iranian supply was able to move through March and April, some limited volumes, 200,000 tonnes a month. MTO has been holding in around that 70% operating rate. But now, we're seeing a dramatic shift in coastal inventories in China, which, assuming this blockade stays in place and there's no product available in behind what's come in, in the last few months, we're going to see inventories drawn. And I think we're going to -- it's going to be very difficult for -- to see those rates continuing.

Great. That's helpful color. And then, just circling back to the guide for Q2, the $500 to $525 realized price through April and May, I appreciate that your -- the discount rate is moving up because you have less sales to China. If we just look at your realized price compared to the global spot average, your realized price tends to be above 100% capture on the spot average. But in Q2, it's shaking out closer to 92%. And so, I guess, just to ask the question another way, is the guidance -- should we think of it as conservative? Like, or are you factoring in potential price decrease in June? Just trying to get a better sense of why that guidance isn't a little bit higher.

I think, in an upward market, you're going to -- and I don't know how you're trending the spot price. But in an upward market, there is some catch-up through the delay of 1 month or 1 quarter. As an example, we set our European price, which is a quarterly price, back in March. And European spot prices have gone from -- at the time, I guess, we were down in the $500 level or slightly over, to now above $600. So there's going to be those lags even on a monthly basis, depending on when you're trending the spot price. It takes a month to be able to adjust to the then prevailing market. And so, I think there could be some -- the read there could be, because we've had a steady and significant increase in market pricing, and that's led to that difference.

Your next question comes from the line of Laurence Alexander with Jefferies.

Two quick questions. Just first, a bit of housekeeping. Just on the ammonia side, can you clarify how you're doing in terms of either ASPs or margins and kind of any kind of your baseline outlook for Q2, how much you've contracted versus spot? And then, secondly, kind of higher level, given how stark the disruptions could be if the war continues and the rhetoric around the war potentially continuing several more months and all the bottlenecks that, that would imply, what are you hearing from customers about what they think it would take for the industry to undertake capacity additions elsewhere to fix the supply-demand balance?

Thanks, Laurence. To your first question on the ammonia pricing, we're -- we produce around -- produce and sell around 80,000 tonnes a quarter. And our estimates when we did the acquisition was around 50 million tonnes of EBITDA per year. And that was at a price of -- using a Tampa price of around $450 per tonne. It's now at $775 per tonne. That has climbed up over April and May. So we're obviously achieving a significantly higher earnings there, probably an uplift of $20 million plus per quarter at these prices. So that's where we are, and we are contracted there. So we do sell mostly contracted tonnes. On your question around capacity additions, it's not something yet that I think the market is in discussions today. I think what we'll have to do is take a look at when things get resolved, and I do believe it will take -- people want to get a read on where things rest long term. Does the pricing support what you need longer term to reinvest in the business, which will be a function of many things, demand supply, long-term energy prices. Is there a raise to capital because a lot of people want to do it at the same time. Many different factors would have to be worked out before I think you'd see big commitments to capital. So we're in a wait and see here on where this actually lands, and certainly things that we're going to be monitoring very closely.

Your last question comes from the line of Steve Hansen with Raymond James.

It could go to Rich or whoever. I mean, the question really is around this Iranian situation and the restart of plants in recent weeks. I mean, we've been reading about the restarts, but there doesn't really seem to have a clear path to getting product to market. So the question is ultimately, is there any indication that they're trying to recreate supply chains around the Gulf or around the Strait, either by a trucking or some other avenue to tidewater that would allow any volume of magnitude to actually get out? I mean, have you heard anything around that context? Or is the restart just really around testing the facilities as best you can tell? I'm trying to get a sense for why restart if you can't get the product out.

Yes. No, we're not hearing any of that, trying to get a different supply chain to avoid the Strait. And we do think the U.S. blockade is a very significant derailer in terms of trying to get -- move products out. So we haven't heard of any of that product. And again, everything has to move to China as well. So no, none of that has come to our attention, Steve.

That's great. And just one follow-up. Apologies for the background noise. Just wanted to ask about your operational cadence this year. I mean, are you making any plans that would differ versus your thoughts 3, 4 months ago around how to operate the assets this year, just given the tightness? I think Joel had asked the question earlier about short-term gas contracts. But even around the broader maintenance profile or anything else in your internal capability or levers to pull to run harder in this environment, is that being contemplated? Or is it still sort of the status quo plan?

Well, I think everywhere around the world in our asset portfolio -- so North America, we want to run 100%. Egypt, Chile, those are our assets that represent -- are well placed on the cost curve. Our operating strategy is always to run safely, reliably for the long term and then always enhancing how we can have reliability at the highest rates possible. Around Trinidad and New Zealand, New Zealand is a bit of a different story. The gas, actual contracts there are attractive, but we're running the plant very suboptimally because we're well below capacity, and the gas is -- it's a mature basin, and it's in decline. So if we were able to run there as a flexible asset, maybe we would. But it's really about the gas basin and it's structurally challenged. And then, Trinidad becomes more of a cost issue and really how does the NGC going to negotiate. If there was something that made sense in the shorter term, maybe we will look at that. And that was to Joel's point. But it'd to make sense in the short and medium term, and we would look at those options. But at the same time, we have to look at all possible ranges of outcomes out of those discussions, and that's what we're doing.

There are no further questions at this time. I will now turn the call over to Mr. Richard Sumner.

Thank you for your questions and interest in our company. Hope you will join us in July when we update you on our second quarter results.

This concludes today's conference call. You may now disconnect.