Good morning. My name is John, and I will be your conference operator today. At this time, I would like to welcome everyone to the Methanex Corporation Fourth Quarter 2024 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. Thank you. I would 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 fourth quarter 2024 results conference call. Our 2024 fourth quarter news release, management's discussion and analysis, and financial statements can be accessed from the Financial 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 forecast or projection, which are included in the forward-looking information. Please refer to our fourth quarter 2024 MD&A and to our 2023 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, adjusted EBITDA, cash flow, adjusted income, or adjusted earnings per share made in today's remarks reflect our 63.1% economic interest in the Atlas facility or 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 fourth quarter 2024 results. I'd like to start the call by thanking our global team for their ongoing dedication to safety. We achieved the best safety performance on record for the company in 2024 in a year of meaningful changes in our operating assets, and these results are a demonstration of the team's commitment to responsible care across the globe. Now turning to the financial and operational review of the company for the fourth quarter. Our fourth quarter average realized price of $370 per ton and produced sales of approximately 1.5 million tons generated adjusted EBITDA of $224 million and adjusted net income of $1.24 per share. Adjusted EBITDA was higher compared to the third quarter of 2024, primarily due to a higher average realized price and higher produced sales. For the full year of 2024, we had an average realized price of $355, produced sales of just over 6 million tons, and generated adjusted EBITDA of $764 million and adjusted net income of $252 million, or $3.72 per share. Now turning to short-term methanol pricing and market dynamics. We entered the fourth quarter with very tight market conditions in the Atlantic basin, underpinned by stable demand and low operating rates from several key supply sources, with these conditions remaining through the quarter. In the Pacific basin, we entered the fourth quarter in a more balanced market with stable production and healthy inventories from lower methanol to olefins operating rates in the third quarter. Through the fourth quarter, conditions in the Pacific tightened because of increased operating rates from MTO producers combined with increasing supply constraints, particularly from Iran. Consequently, MTO operating rates decreased late in the fourth quarter, with this trend continuing into the first quarter. Overall, tight market conditions globally led to an increased methanol pricing environment in the fourth quarter and into 2025. Our global average realized price of $370 per metric ton was $14 higher than the previous quarter. Methanol pricing strength continued into the first quarter of 2025, with our European quarterly price posted at €700 per ton, representing a €130 per ton increase from the fourth quarter. Our posted prices for North America and China increased in January and rolled in February; and in Asia-Pacific, we increased posted prices in January and February. Comparing methanol demand in 2024 to 2023, we estimate global methanol demand increased by approximately three million tons, which included relatively flat year-over-year demand for methanol-to-olefins, given supply constraints in the industry. In 2025, we expect methanol demand to grow at a similar rate to 2024 driven by demand from traditional chemical applications, as well as energy applications, with operating rates in methanol-to-olefins again playing a critical role in balancing the market. We expect incremental supply will come from full-year production of G3 and from the Malaysian Sarawak plant, which we understand recently started producing methanol. Looking beyond 2025, we continue to see favorable supply and demand dynamics, with traditional chemical and energy applications demand expected to outpace supply, given limited capacity additions projected in the industry. Now turning to our operations, Methanex production in the fourth quarter was higher compared to the third quarter with higher production from Geismar, Chile, New Zealand, and Egypt. Our production was higher than our produced sales in the fourth quarter of 2024 due to an inventory build that produced methanol from these higher production levels. In Geismar, production was higher during the fourth quarter with G3 operating at full rates in October and December. In mid-November, we took a proactive shutdown of G3 to inspect some of the newly commissioned equipment to ensure reliability. The plant successfully restarted and resumed full operating rates in December and has been operating at high rates since the restart. In Chile, I’m very happy to share that both plants have been operating at full rates and that after a brief maintenance outage in November, we produced 150,000 tons of methanol in December, which is the highest monthly level of production we've reached in Chile since 2007. We have gas contracts in place with Chilean and Argentina gas producers until 2030 and 2027 respectively, which underpin approximately 55% of the site’s gas requirements year-round. We continue to expect seasonality in production, but are seeing positive developments, making full gas supply for a two-plant operation available for longer periods. Based on contracted gas, 2025 production is expected to be between 1.3 million and 1.4 million tons, which would result in the fourth consecutive annual increase in production from Chile. In Egypt, production increased compared to the third quarter as temperatures moderated, the gas balances in the country stabilized, and we operated at close to full rates based on improved gas availability. We are monitoring the gas market closely and would expect to experience some curtailments in 2025, particularly in the summer months depending on gas supply and demand dynamics. In New Zealand, production in the fourth quarter was higher compared to the third quarter with the restart of our Motunui 2 plant in November. In August, operations were temporarily idled as we entered short-term commercial arrangements to provide contractual natural gas into the New Zealand electricity market until the end of October 2024. Based on the current outlook from gas suppliers, we expect 500,000 to 700,000 tons of production from New Zealand in 2025, which will be dependent on gas availability and any selling of gas into the electricity market to support New Zealand's energy needs. In 2025, we have three turnarounds scheduled that will impact our production in the first three quarters. Our expected equity production guidance for 2025 is approximately 7.5 million equity tons, which includes the impact of these turnarounds and forecast for gas feedstock availability outside of North America, but excludes any incremental production from OCI assets post-acquisition closing dates. Actual production may vary by quarter based on timing of turnarounds, gas availability, unplanned outages, and unanticipated events. Now turning to our current financial position and outlook, we ended the fourth quarter with $879 million of our share of cash and continued access to our $500 million undrawn revolving credit facility. During the fourth quarter, we repaid the $300 million bond with cash generated from operations and executed our OCI acquisition financing plan, including issuing a $600 million bond and securing a $650 million Term Loan A commitment from our banking partners. The completion of these arrangements gives us the financial capacity and flexibility to complete the OCI acquisition and our targeted deleveraging plan. We're continuing to progress the regulatory process as planned. Looking forward to 2025, our priorities are focused on closing the OCI transaction, safely and efficiently integrating the assets, achieving the identified synergies, and reducing leverage by repaying $550 million to $600 million in debt over the next 18 months, assuming a $350 realized methanol price. Beyond this, we do not anticipate significant growth capital over the next few years and remain focused on maintaining a strong balance sheet and financial flexibility. With strong free cash flow capability from our existing assets, which we expect to be strengthened by the OCI acquisition, we're positioned to execute a balanced approach that includes deleveraging and shareholder distributions, depending on future market conditions and methanol pricing. Based on our first quarter European posted price, along with our January and February posted prices in North America, China and Asia-Pacific, our January and February average realized price range is forecasted to be between approximately $395 and $405 per metric ton. Based on this higher forecasted average realized price, coupled with our produced sales expected to normalize closer to fourth-quarter production levels, we expect significantly higher adjusted EBITDA in the first quarter of 2025 compared to fourth quarter. We'd now be happy to answer questions.

Thank you. Your first question comes from the line of Hamir Patel with CIBC Capital Markets. Please go ahead.

Hi, good morning. Rich, are you able to give us an update on how the regulatory approvals for the OCI deal are progressing and should we still assume a close sometime in the first half?

Yes. Thanks, Hamir. We're progressing things well as planned, and we're going through the process in both Europe and the U.S. as we discussed previously. And right now, the expectation is to close in the first half. It's looking like it's going to be more of a Q2 close sometime in the first half of the year, but I got Q2 close right now. So we're getting things all prepared for that and starting to plan integration as we get ready for regulatory approvals.

Okay. Great, Rich. Thanks and just a second – last question I had was could you speak to what you're hearing about output levels from the Iranian methanol industry? It seems like from some of the trade reports that they were barely running in December. If you have any insights into how much has come back and potential for further supply disruptions there this year?

Yes. Well, we don't have direct insight but what we do is track a lot of the flows and import statistics into China, and we've seen a significant reduction in imports into China, which is impacting inventory levels there. It would indicate that you're right. There is not a lot of production coming through in December and likely into January. And I think the energy crisis that Iran is going through is pretty well publicized. So they're having quite a difficult time just from keeping the residential demand supplied, and that's significantly impacting industry and methanol production. So we think that, that probably leads to constrained supply, particularly through the winter here, but likely, as we saw last year, maybe a more prolonged impact of that through the first quarter and possibly into the second quarter, but we're going to continue to monitor it.

Okay, fair enough. That’s all I had. I’ll get back in the queue. Thanks.

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

Good morning, Rich. Just following up on a question, I think you just said. So you said – I think you said that you expect – sorry, sales of produced methanol in Q1 to be similar to production levels in Q4. Is that right?

That's correct, yes.

Now, it seemed like it would be higher in Q1 because if I take your guidance and I factor in turnarounds, like, it seems like production should be similar in Q1 versus Q4. And you had 400,000 tons of inventory build in Q4. So can you tell us what the attributable production look like in Q1 versus Q4? And then aren’t you drying down the inventory?

Well, we’re – I don’t think we’re going to be dry. It’s an inventory build, a produced product. Because there’s a bit of a change in our system when we bring in our overall inventory levels are the same, but we’re bringing in more produced with more production, which means a change from produced methanol to our own produced methanol, which is a good thing for us. So we’ve got an inventory build of produced, not an overall inventory build. And so where we are, production should be similar. Where we’re operating is consistent with the fourth quarter. Right now the assets are running really well, so we would expect a similar production level at this point. But we’ll have to – our focus is making sure we’re delivering and performing on the assets. So we expect that kind of production level would be more kind of our run rate that we would see coming through, assuming we keep production levels at really high levels they are today. Hopefully that answers the question.

Sure. And then I’ll follow-up. So your mid-cycle methanol, $350 methanol you talked about before what you want to do as you close the OCI deal and pay down debt before you restart buybacks.

Yes.

I’m sure you saw the sensitivity here. We’re not at $350 methanol, we’re at $400. I mean, can you just give a sense of if it’s $400 methanol, not $350, like how many months quicker do you get through that debt repayment or how do you think about what is $400 methanol versus $350 methanol mean for how fast you can restart buybacks?

Yes. So I think if we look at where we are, Q1, we would be at this methanol price with our assets performing the way they are. We would expect free cash flow in the $150 million or more range. So if you just kind of do the math, this is pre-OCI deal with our existing asset base producing where it is, that would be a 12-month time frame. But of course, we’re going to plan for a lower methanol price environment and we’ve got all the financing in place that we have. And right now I think this is great because assuming a Q2 close, we’re going to be bringing more cash to the table on close and our starting incremental leverage is going to be a lot lower than when we first came out with the deal announcement. So we’re already making our way on our deleveraging as we operate every day in a tight methanol market and that’s what we’re going to continue to focus on.

Thank you.

Your next question comes from the line of Ben Isaacson with Scotiabank. Please go ahead.

Thank you, and good morning, everyone. Two questions. First one is on New Zealand. Rich, last quarter on the call you said to start modeling one plant in New Zealand going forward and that’s certainly consistent with your guidance. But the question is, when you said that, were you thinking 500,000 to 700,000 tons for the year or is this actually a step worse than you were thinking? And the reason why I’m asking is, what is the risk that we completely lose methanol production in New Zealand in two or three years?

Yes. So at the time when we were gearing to a one plant operation, we were looking at working with our gas suppliers on the future deliveries of gas, and what we were seeing was enough gas to run a one plant operation. The actual rates were going to be determined on really looking closely at production for the year. And the range we’ve given also does include potentially some downside in methanol production where we may be on selling some gas into the market. But Ben, you’re right, we do need to see a production and investment going into the upstream in New Zealand from where we are today to continue to support the one plant operation into the future, and that’s something that we’re going to be working on with gas suppliers as well as with the government who we believe is looking at a lot of the policies that have not been incentivizing the right things for the upstream in the country. And we’re 50% of the market, so we’re going to be working through that and we’ll be giving guidance as we progress. So it’s hard to say, it’s hard to say beyond this year. What is it going to look like? And is there risk? Yes, there’s risk. There’s risk and it’s something that we’re going to be working to preserve the long-term sustainability of our supply into New Zealand. So – but we'll continue to give updates and right now we do think it's one plant at less than full rates with the potential that some gas gets diverted depending on what happens in the country. And what's happening in the country with the energy crisis partly because of the lack of upstream and the government today recognizes that. So that's something we think there is a focus on and something we'll be working towards.

Perfect, that's helpful. And then my second question is, and I may have missed this when the OCI deal was announced, but does the regional mix shift of sales volume post OCI mean that you'll have a higher ASP, all else equal on $350 methanol? And if so, does that also mean you'll have a higher margin, all else equal?

So just on the ASP, I think the answer is – in today's pricing environment where we're seeing premiums outside of China, I think the answer is, yes. A lot of the markets that we expect to be selling to will probably be mainly Atlantic based. So yes, on the higher realized price in terms of translating into higher profits, we would have modeled all this into our forecast of earnings and we used everything at a $350 price. So we would expect there to be a higher uplift in ARP. How that models back to our average realized price sort of remains to be seen on how differentials work in the industry. And one of the things that you'll see this year is we've reduced down our sales and that will probably be showing up mainly in China, but we'll also be reducing down purchases in the region. So net-net, it's not a – it wasn't a big margin driving part of our business. And so you shouldn't expect – you should expect a higher uplift in price, but not necessarily tracking back to margin because that wasn't where we were earning a lot of the margins in our business.

Got it. Thanks so much. Appreciate it.

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

Hey, guys. This is James Cannon on for Josh. I just wanted to double click on one of the earlier questions on gas availability in New Zealand. You said that the guidance there reflects potential for some on selling of gas. But could you just frame for us based on your pure gas supply, what the implied production would look like.

I think right now on gas, we're probably in the middle of that range or somewhere between the 600,000 and 700,000 without any gas on selling. And that's going to be dependent on production out of the gas fields. And then if it goes lower than that, it's likely – we would be selling into the gas market. And I will remind that – from a business perspective, we – when we given our future forecast on earnings, that we do have a few sites, Trinidad and New Zealand, these are – from a volume perspective are still in our numbers, but from an overall earnings perspective and our run rate earnings are now representing a lot smaller proportion. And so right now we do see a shift with G3 and now the OCI acquisition where we are seeing a lot of the value uplift mainly in North America and as well as upside around Chile today.

Yes, that makes sense. And then just one more on the MTO affordability. I don’t know if you mentioned that earlier. Could you just remind us where that sits right now?

Yes. Today we see ethylene and propylene prices at around $850 to $900 per ton. And that translates into around a $300, somewhere between $280, $300 MTO affordability. But that’s at a C2, C3 level. They also have integrated downstream, and when you factor in the integrated downstream, it’s slightly higher or slightly could be slightly lower depending on where they’re going. So we do think that we’ve seen pricing above that level in China, which is indicating that markets are tight and that we’ve seen it pushing to above right up to their highest kind of affordability for coastal MTO producers at that $310, $320 level.

Got it. Thank you very much.

Thanks.

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

Good morning, Rich. A question on pricing. Obviously, there’s been a fair degree of buoyancy across all the regions, but there continue to be sort of variances, particularly in terms of North American pricing and Asian pricing. So, how should we think about the delta between those two?

Thanks, Hassan. I think right now we see – there are some more and more what we’d say on the existing supply. There’s more and more – well, there’s temporal constraints on supply and then there’s more structural constraints on supply. And so, we saw the Atlantic markets getting a lot firmer because of European pressure on European producers. We’ve also seen Venezuela operating at low rates. Trinidad – ourselves reduced production in Trinidad by 1 million tons. There’s a plant in Equatorial Guinea that we think is operating methanol today. And so you’ve seen that those being – some of that’s temporary but a lot of that is structural. So we’ve seen imports and particularly into Europe being under pressure and there isn’t a lot of free flows that are from maybe the Middle East that might balance the market because there’s pressure on the trade. Firstly there’s not a lot of uncontracted volume and secondly the trade routes through the Red Sea is effectively no one wants to take the risk to move product there. So we do think that these forces are in place for at least now and we’re going to have to see how balance comes back into the markets as some of these temporal things change. But there is structural forces that we think are in place that aren’t going to ease in any kind of short time frame. So we do think that this premium that we’re seeing in the Atlantic is likely be there for at least into the near to medium-term here. And then I think we have seen premiums in the Asia Pacific outside of China as well. The Asia market’s probably trading at a $20 to $30 premium above China. So today that’s sort of what we’ve seen and that tightness in the market sort of remains. And as we look forward, demand continues to grow and these supply constraints, we’ll have to see how much actually gets into the market. And then also geopolitical forces could put increased pressure on some of the supply into the industry as we see what impact the new U.S. administration is going to have in certain jurisdictions as well.

Understood. Very helpful. And as a follow-up, I guess, like a two-part thing on the North American sort of gas situation. I mean, obviously, Henry Hub prices are up meaningfully over the last several months. And obviously, you guys are doubling down on your North American capacity with the whole OCI acquisition. So how are you guys thinking about the hedging strategy as it exists today, will there be any changes to that? And then sort of moving slightly away from the gas side, just – I mean, obviously, a lot of noise around Canada tariffs and the like. How are you thinking about that? And I mean, would that have any – if at all, there were any Canadian sort of tariffs imposed, would that have any impact on your trade flows and earnings?

Yes, thanks, Hassan. So I'll start with the gas side. We have seen spikes in the kind of what I call the short end of the spot pricing, which – we think spot pricing is heavily impacted by weather and inventory levels. And so from that perspective, we expect volatility in the short term. And we – our hedging strategy is to be 70% hedged and have the flexibility to participate in the market in that volatility, and we do take the risk in a short term that we see spikes, but we also get the benefit when it's below the forward curve. When we look at the forward curve, the forward curve stayed more steady, which is an indication, even – we have even seen it coming down a little bit, which is an indication that the supply and demand balances look healthy from a supply perspective and from a cost structure perspective for us. So we're – we like the North American gas market and that was clearly something we took a very close look at when we did the OCI deal. And we like the structural forces there. And so I think this new administration is also looking to increase supply across the oil and gas industry which is positive, and there's other things that will obviously factor in there. But we like long-term North American gas. When we look at trade policy and we're – we think about tariffs, obviously, the big ones that are being discussed are Canada, Mexico, and then China. For us, the acute business impact is pretty marginal. We have – do have some product flowing from Medicine Hat across the border into the U.S., but we're talking about a pretty small volume for what we sell in a year. And we have – if that cost is difficult to recover. We have ways to manage it within our supply chain and the flexibility to deliver to customers from a different point at potentially a pretty marginal incremental cost. So no concern from that perspective. I think for us, we are now going to be a very big U.S. producer. And so we'll add an exporter out of the U.S., and we'll have to really carefully look at potentially retaliatory tariffs. We don't have any U.S. product going to China right now because there's already a tariff on methanol. And – but it's something we'll be following really closely but don't see any acute impact on our business.

That’s very helpful, Rich. Thank you so much.

Your next question comes from the line of Steve Hansen with Raymond James. Please go ahead.

Yes. Good morning, guys. Now that the OCI transaction seems to be drawing closer, and likely moves ahead as fully proposed. What do you need to do to get ready in advance? I'm just trying to think about supply chains, the broader marketing logistics mechanism or team that you've got in place. I mean, what do you need to do to be ready to take on all these tons as the transaction draws closer?

Thanks, Steve. We're busy doing a lot of integration planning right now. We're obviously still going through the regulatory process. So for us, it's being ready on day one. And we've got a great team in place on our side across all the functions, looking at the integration and it's a huge priority for the company right now. We're going to be – the big thing is a safe and reliable integration and doing that as quickly as we can by doing it safely and reliably, and we've got all of our teams looking at it. I don't – for us right now, there's a big thing about can we process and operate the business on day one, and we're spending a lot of time trying to figure out, make sure that we're ready and well planned for the closing. So right now, when you think about marketing and logistics, yes, we understand the market and the supply chain as well. And we don't see any big complications there, but we're going to be thinking through everything really carefully as we go to execute this safely and reliably and efficiently as soon as we possibly can.

Okay. Helpful. Thanks. And I just wanted to go back to the inventory question that was raised earlier by Joel. I think I understand the context around increasing your company produced product in inventory, that stands a reason to me. But it was still a big number of $440,000 or whatever it was. How should we think about inventory levels of produced products going forward, maybe as the question, just in the sense that do we expect some of that to draw down through the period in the first half of this year? How do we think about that level changing over time?

Yes. I mean, it’s hard I guess, hard to say. Overall inventory levels, we don't think when we finish the year are necessarily high for our supply chain. So the mix between purchased and produced inventory, we think probably stays about the same, and it should be around 80% produced and 20% purchased. That's if we have our supply chains kind of steady. And so – and that's where we are today. So I don't think we're going to see a big release. But when we do have a period like we went from – we weren't operating in New Zealand. We are operating one plant in Chile. We didn't have G3 operating and Egypt was operating lower. So it's a significant build in the quarter to a more structural kind of inventory position at the end of the year, if that helps.

No, that's actually very helpful. And just one last one, if I may, is just around the court decision that you referenced in the release just so we all understand it. This is really around the ability for you to market the product coming off the Natgasoline plant. I think that was sort of the core of that legal case. And if you can confirm that – maybe just that it's actually the question. Could you confirm that so we can understand how you'll be marking those tons?

Yes. It was the dispute was around the transferability of the joint venture partners rights, and that's rights for everything, operational decisions, financial decisions, and marketing decisions. And so right now, we believe that is now 50%. The decision is that those rights all transfer to a purchaser and that's been – that's the judgment of the court. And so that's exactly what we'd expect as those rights are now transferring on sale. Of course, there is an appeal process that we're not aware of what will happen there. And so something we still have to track. And we'll update you as things progress there.

Okay, very helpful. Thank you.

Your next question comes from the line of Kevin Estok with Jefferies. Please go ahead.

Hey Guys, thank you for taking my question. Just back on MTO operating rates I know there's been some fluctuation in the back half of the year. I think on Q3, maybe they're around like 65% and then around 85% in Q4. I guess where do they currently stand as of like early January or currently? Just want to build up some assumptions here?

Yes. Right now, we think that the operating rates are in the low-70s. And there's probably going to be increased pressure, there's a bit of a lag impact with Iran, as Iran's operating rates they sort of show up 30 to 45 days after the production impact. So we do expect that imports into China continue to be under pressure and MPO is a big, big buyer of Iranian imports. So with that in the 70s right now, and it's something we're going to continue to watch. Really, at the end of the day, what this is, is balancing the market. It's really a supply-driven operating rate because there's just not enough supply available for them to run consistently. So in a lot of ways, the lower operating rates are indicative of a tight supply market.

Okay. Thank you. Appreciate it. And then just on discount rates. I guess what are your expectations for the year or at least Q1 just given the higher overall average pricing?

Well, I think we probably haven't given guidance on discount rates. I do think what you will see is a higher percentage of Atlantic-based sales, which should result in a higher discount rate than 2024 on average. But I'd also translate, as we discussed earlier in the call into a higher average realized price just given the markets that we are selling and these are higher netback markets. So I think the higher discount is probably not the area to look at, it's probably the fact that we're realizing actually a higher price in our network.

Got it. Okay. Thank you. I appreciate it.

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

Thank you and good morning. Maybe sticking on the discount rates, as we think about the discount for 2025, is anything changing regarding how you're negotiating new methanol contracts for this year? And in particular, should we expect discount rates to generally increase as the year progresses?

I think what we're seeing is the Atlantic markets have been pretty constrained on supply. I think – I don't think we – you should expect a big deterioration in discount rates, but given the higher proportion of sales, our average discount may go up, but that's not the result of a big deterioration in discount rates. Again, I think that translates into higher pricing for the business, which is a positive.

Sounds good. And then was there another New Zealand gas diversion benefit in the fourth quarter? And if so, what was the EBITDA impact there?

Yes, there was and we were diverting it up until the end of October. The number is around, I believe it's around $30 million. But that's obviously needs to be offset with that doesn’t include the lost margin of not producing methanol, right? So we going forward we'll be producing methanol and won't have the margin on the gas sales. And so all that needs to be factored in as we move forward.

Sounds good. Thank you.

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

Great, thanks. Just a quick follow up on Hassan's question on North American gas hedges. So, I think prior to the OCI acquisition, you had plans to hedge around 70% of North American production. And I believe you're buying the OCI plants without any gas hedges, so.

That's correct.

So, going forward, is that 70% the right level and meaning you'll enter into a bunch of hedges later this year?

Yes, that will be. Today we like our gas strategy and again it's usually we're about 70% hedged in the first three years and then a little less in the three-to-five-year period and then less again beyond the five-year period. And then we can opportunistically layer in more hedging as we get expiries as time passes. And that strategy has worked well for us. And right now, obviously we're taking a close look at our hedging strategy as we plan for integration and closing of the OCI deal. But, so we won't, we haven't layered anything in anticipation of that and we'll be starting to do that as we get closer to the closing and bringing those assets into that same strategy.

Great, thanks. And then just one last one, another clarification on the whole tariff situation with the U.S. so you mentioned that there's very limited trade between Canada and the U.S. no exports from the U.S. to China. Does any methanol go to Mexico?

No, not in our system. There's very little. There is some domestic actual production in Mexico with some demand there, but it's not a big methanol market.

Okay. So any tariffs would mainly be just the indirect impact of a slowdown in I guess domestic consumption or even global consumption.

Yes, that's right. I think the one we watch for sure is just, on China, 10% tariffs, that one of the, where methanol is consumed in China is for export manufacturing. So, we will look closely, and if that impacts demand in China for manufacturing of export goods that would be going to the United States. And obviously what is the roll-on impact? Where does that manufacturing show up and how long does that take and the overall impact that that may have on industry demand, but nothing acute to our business and for in terms of incremental costs or any risks there that we see today.

Great, thanks. That's all for me.

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

All right. Well, thank you for your questions and interest in our company. We hope you'll join us in April when we update you on our first quarter results.

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