Good morning. My name is Gil, and I will be your conference operator today. At this time, I would like to welcome everyone to the Methanex Corporation Second Quarter 2025 Results Conference Call. I would now like to turn the conference call over to the Director of Corporate Development and Investor Relations at Methanex, Ms. Jessica Wood-Rupp. Please go ahead, Ms. Wood-Rupp.

Thank you. Good morning, everyone. Welcome to our second quarter 2025 results conference call. Our 2025 second 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 forecasts or projections, which are included in the forward-looking information. Please refer to our second quarter 2025 MD&A and to our 2024 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's 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, our 50% economic interest in the Egypt facility, our 50% interest in the Natgasoline facility and our 60% interest in Waterfront Shipping. In addition, we report our adjusted EBITDA and adjusted net income to exclude the market-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, are unlikely to be comparable to similar measures presented by other companies. We report these non-GAAP measures in this way because we believe they are a better measure of underlying operating performance, and we encourage analysts covering the company to report their estimates the same way. 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, Jessica, and good morning, everyone. We appreciate you joining us today to discuss our second quarter 2025 results. Our second quarter average realized price was $374 per tonne, with produced sales of about 1.5 million tons, generating adjusted EBITDA of $183 million and adjusted net income of $0.97 per share. Adjusted EBITDA was lower than in the first quarter of 2025, largely due to a decrease in the average realized price. On June 27, we completed the acquisition of OCI's methanol business, which we consider highly strategic for Methanex, significantly enhancing our production portfolio with two large methanol facilities in Beaumont, Texas, that have access to a stable and cost-effective supply of natural gas feedstock. The integration is going as planned, and we are focused on ensuring safe and reliable operations, meeting customer commitments, and realizing the strategic and financial benefits of this acquisition. I want to personally thank the team for their hard work and commitment in achieving a safe and seamless transition. We are thrilled to welcome new talented team members to our organization. Now, regarding methanol market conditions, after achieving over $400 per ton in the first quarter of 2025, we recorded a strong second quarter global average realized price of $374 per ton. We estimate that global methanol demand increased by about 4% in the second quarter compared to the first quarter, primarily driven by higher demand in China across all applications. In China, traditional and other energy demand rose alongside seasonal construction and transportation activities, as well as strong export manufacturing and domestic consumption, which compensated for the ongoing strain in the property market. Demand was additionally supported by gradually increasing methanol to olefins operating rates throughout the quarter as supply from Iran improved following winter gas supply curtailments. In the rest of the world, demand remained mostly stable with slight regional variations. On the supply side, methanol production from Iran consistently rose throughout the second quarter as feedstock restrictions eased. We believe the disruptions to Iranian methanol production in June, due to significant escalations in regional conflicts, were brief, and we estimate that Iran's operating rates increased by over 50% from the previous quarter. Globally, we believe the methanol industry operated at very high rates with minimal outages. In the Atlantic Basin, strong production and consistent demand led to inventory rebuilding from a low point over the quarter, causing a softening of prices from the high levels seen in Q1. In the Pacific Basin, particularly in China, the inventory increase was more moderate as the rising operating rates for methanol to olefins absorbed much of the heightened supply in the market. Looking ahead to the third quarter, we estimate methanol pricing into MTO and the marginal cost of production in China to be around $270 to $290 per tonne, and we anticipate realized pricing in all other major regions to be at premiums to these levels. We reported our third quarter European price at EUR 530 per tonne, reflecting a EUR 95 decrease from the second quarter. Our North America, Asia Pacific, and China prices for August were announced at $778, $370, and $350 per tonne, respectively. Based on these prices, we estimate our realized price range for July and August to be approximately $335 to $345 per ton. Now, regarding our operations, Methanex's production in the second quarter was similar to that of the first quarter, with increased output from Geismar and Trinidad, offset by declines in Chile, New Zealand, and Egypt due to gas constraints and a planned turnaround in Medicine Hat. In Geismar, production increased during the second quarter as G1 and G2 operated at full capacity, and G3 successfully restarted in early May. We are confident that we have addressed prior challenges related to G3 with new startup conditions, permitting a safe and reliable operation without risks to the autothermal reformer. Towards the end of June, we encountered utility and power outages that impacted methanol production at Geismar, but all plants resumed production in early July and are currently running at full capacity. The integration of both our 100% owned Beaumont facility and the 50% owned Natgasoline facility is progressing smoothly, with both assets operating safely and at full capacity since the acquisition. In Chile, we had both plants running at full capacity from September 2024 through April 2025, achieving our highest production rate since 2007. On May 1, we idled the facility as planned for maintenance, preparing for a restart in late third quarter. While production is expected to be seasonally influenced, we are encouraged by improvements in natural gas availability and are collaborating closely with gas suppliers to enhance production rates over time. In New Zealand, production was lower due to temporarily idling operations from mid-May through the end of June as part of a short-term commercial agreement to redirect contracted natural gas to the electricity market. The plant successfully resumed operations in early July, and we project our production for 2025 in New Zealand to be around 400,000 tonnes. Gas supply issues in New Zealand continue, and we remain in discussions with our gas suppliers and the government to sustain operations there. In Egypt, we faced some production curtailments due to significant disruptions in imports, which concluded in late June. We are closely monitoring the gas market and anticipate potential curtailments in 2025, especially during the summer months, depending on gas supply and demand dynamics. We expect our equity production guidance for 2025 to be approximately 8 million tonnes, including the fully owned Beaumont facility, its methanol and ammonia production, and our share from the Natgasoline plant. Actual production may vary each quarter based on turnaround schedules, gas availability, unplanned outages, and unforeseen incidents. Now, let’s review our financial standing and outlook. We concluded the second quarter with $485 million in cash, including about $50 million from the acquisition and access to a $600 million undrawn revolving credit facility, which was increased at the transaction's closing. Our focus for the second half of 2025 is to operate our business safely and reliably while integrating the new assets. Our primary capital allocation priority will be to direct all free cash flow towards reducing debt in the near term through repaying the Term Loan A facility. We do not expect significant growth capital needs over the next few years and are committed to maintaining a robust balance sheet for financial flexibility. Due to higher produced sales, although offset by a lower projected average realized price, we anticipate an increase in adjusted EBITDA for the third quarter of 2025 compared to the second quarter. As we progress through 2025, we expect our production and sales to align more closely with our capacity run rates. We are now ready to answer any questions.

Your first question comes from Joel Jackson with BMO Capital Markets.

I'm going to ask two questions one at a time. Rich and team, could you discuss the operating rates at G3 Beaumont and OCI? It appears that G3 has been running smoothly at over 90% since the restart, aside from the issue you mentioned. Can you also provide an update on how Beaumont and Natgasoline have been performing over the past month?

Yes. So thanks, Joel. Yes, G3 has operated really well since we restarted in early May. We did have those disruptions towards the end of the quarter. But beyond that, G3 has operated at high rates for that period and is operating at those high rates today. I wouldn't give you exact percentage, but the G3, when we run the asset, it's been at very high rates, so above 90%. The assets, Natgasoline and Beaumont, have been running at full rates since acquisition. I'll just say the Beaumont asset went through a turnaround in March, a successful turnaround there, operating well for 2025. Natgasoline went through a turnaround in 2024, had an outage towards the end of the year, and has a really good run on six months of high operating rates, I believe it's a record six months of production there. So those assets are going really well. Of course, we've got to get in, and we're currently doing that with our global manufacturing team and making all the connections there with the operations. So they've done a lot of great work with those assets. And for us, it's getting in and working with the team, bringing our global expertise to the table as well.

Okay. My final question is regarding the OCI deal announcement. In your September 2024 presentation, you mentioned that if we achieve $3.50 for ethanol and $3.50 for gas, we could deliver a post-OCI run rate, including synergies, of $1.125 billion EBITDA, which is a very specific figure. However, in your new slide deck last night, you've slightly adjusted that guidance down by $50 million to $1.075 billion under the same conditions. What I would like to ask is...

Sorry, Joel, just to be clear, it isn't actually the same assumptions. We have brought down production mainly in New Zealand. And so that $50 million is everything to do with New Zealand.

So my question is about the $50 million difference. Is that entirely related to New Zealand? Yes, it is. In the previous slide deck, the equity tonnes would have been around 10.2 million equity tonnes, but it is now 9.6 million.

We have reduced New Zealand's production by 600,000 tonnes, bringing it to a run rate of 400,000 tonnes. This adjustment is primarily related to gas and the challenges in predicting future gas output beyond this year's production. This change has been the main factor affecting our free cash flow and EBITDA figures. To clarify, this adjustment is unrelated to any transactions.

Just following up on that, Ben, two parts. Is that a number that you can achieve next year, assuming no unplanned outages? And as part of that, yes, New Zealand is down at 400,000 tonnes. Are you not getting the proceeds from selling the gas back to the grid? Like are you not being made whole anyways?

We are currently tracking a run rate of 400,000 tons in New Zealand. At this level, the earnings compared to our fixed adjusted EBITDA are limited, and we have not projected any gas sales into those figures. Looking ahead to next year, the forecast includes synergies, specifically the $30 million we expect to achieve over 18 months. Our efforts so far have confirmed our initial assumptions regarding these hard synergies. While we've got a solid number with 9.6 million equity tons, it will depend on our production capacity and the effective use of our assets, particularly regarding gas feedstock. With 65% of our production based in North America and stable gas supplies, we are optimistic about meeting these run rates and feel very confident about our EBITDA and free cash flow. However, we need to demonstrate that our assets perform well and continue to enhance our gas feedstock supply.

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

Rich, with your entry now into the ammonia business, what's your outlook for the market there? And how do you see operations expanding?

Yes, thanks, Hamir. It's early for us in ammonia, and we're currently focused on understanding the operations and integrating it into our business. The market we entered this year is quite tight, with pricing adjusting due to an increase in supply. Currently, prices in Tampa are above $400 a ton. We observe some tightening in supply, which may lead to an increase in prices, aligning with our initial projections when we made the transaction. The ammonia business currently accounts for about 3% to 5% of our global sales, and we aim to gain a deeper understanding of it. Our focus, at least initially, will be on operations, integrating this into our marketing and supply chain, and improving our overall understanding. Presently, the market conditions are consistent with what we anticipated when we entered the deal. We expect to have more information to share as we continue to learn about the operations and develop a clearer medium to long-term outlook for ammonia.

And how should we think about the gas hedging associated with the new OCI assets?

Yes. As we mentioned earlier, our hedging strategy in North America involves being significantly hedged in the short term, targeting a hedging level of about 50% to 70% in the first three years. After that, we plan to gradually reduce our hedging to 25% to 50% over the three- to five-year period, and then lower it further, as the OCI assets we are acquiring come to us mostly unhedged. Currently, we are around a 50% hedge level, which we find comfortable. The forward curve is not particularly attractive in the short term, with spot pricing at $3 per MMBtu. Therefore, we feel good about our current position. Notably, longer-term pricing is declining, and we have managed to secure some modest hedging for 2030 and beyond at an all-in cost below $3.50. We will remain opportunistic in the market while feeling secure in our current stance.

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

With the OCI acquisition, how much does your quarterly depreciation rise?

I'll turn this over to Dean Richardson, our CFO.

Yes. One thing with the assets is, of course, we've got the Natgasoline joint venture. So that's going to be accounted for on an equity basis. So you do need to consider that. But approximately $25 million per quarter would be the change, inclusive of that.

And then on the very last page of your release, you provide a pro forma if you owned the OCI business for six months. And you know there are various disclaimers, but you show net income of $241 million, I guess, versus the $215 million that you reported for the six months. Can you explain a little bit of your calculation and what that implies either for EBITDA or for EBIT? When I do a rough calculation, it seems to imply about $100 million in EBITDA for the first half, but maybe I did it incorrectly.

Yes, thank you for your question. The pro forma presentation is a GAAP requirement that reflects how the prior business operated. It follows specific guidelines, utilizing last year's data regarding prices and operating rates, which differ from our current business. I would advise against placing too much emphasis on that disclosure, as it is mandated by GAAP.

Then perhaps you could assist us in some form?

Yes, I'm happy to take that offline with you and walk you through that.

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

Two questions. Rich, can we talk about salvage value, or maybe a better term is trapped value within your portfolio? So you have two plants not running in New Zealand and kind of moving toward a third. You have the big Atlas plant not running. And now you have these two Dutch plants not running. What is that collection worth? And is there a way that you can monetize that and then return that capital to shareholders? I was just thinking, is that like $10, $15, $20 a share of value potentially locked up?

Thank you, Ben. The first thing I want to highlight is that the value in place primarily depends on the availability of gas stocks and feedstock, as well as the associated economics. This in-place value will be influenced by these factors. The assets are currently operational due to the favorable outlook, and they hold option value since we have seen situations where the performance of assets or gas basins can change. Therefore, preserving option value is one of our key focuses. Regarding relocation value, what we've discovered is that selling the assets and having a buyer move them to a location with more competitively priced gas can be beneficial. The value in relocation is less about capital savings and more about the speed of execution. If a project needs to be completed quickly, relocation is often the best approach, influencing project economics by accelerating timelines. Presently, the market dynamics in these areas are challenging, which is why operations are halted. Additionally, the market is not signaling an immediate need for us to expedite any projects. The potential change in value over time will depend on market conditions related to gas and feedstock, and various market developments. If the market indicates urgency for project execution, there lies value that we want to ensure benefits shareholders rather than being overlooked. However, we are not currently valuing those assets in the range of $15 to $20 per share.

And just as a follow-up question, we saw Trump this week penalize or at least talk about penalizing India via secondary sanctions for purchasing petroleum from Russia and maybe from Iran as well. A month ago, the U.S. placed secondary sanctions on Cave methanol, which I think is the first for Iran with respect to secondary sanctions. Rich, can you talk about what this means? And do the secondary sanctions mean anything in terms of impacting trade flow or impacting how much methanol gets out of Iran? Or is it just kind of more of the same?

Thanks, Ben. Yes, regarding the secondary sanctions, we can discuss this further later, but we believe this isn’t the first instance of secondary sanctions being applied, as some have been enforced on individual plants since 2020. The Cave is a newer plant, and sanctions have now been applied to its operations. Iran has managed to effectively navigate secondary sanctions using methods like the shadow fleet to get products to market. Therefore, we don't anticipate that these sanctions will significantly disrupt actual production or the ability to sell in the market, though it might restrict who we can sell to. Your mention of India is relevant; secondary sanctions could lead certain buyers to avoid products from affected plants. There might also be buyers in China who will stay away as well. Nonetheless, we’ve seen products under secondary sanctions still enter the market, indicating there are still customers willing to buy, albeit possibly at a lower price. However, we do not expect any major changes in overall market balances because of these sanctions.

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

Just a couple of quick ones. Rich, can you just maybe speak to some of the integration priorities as you bring OCI into the tent here? It sounds like the facility is already running quite well. I think when the transaction was proposed, you were thinking there would be some upside to potential operating over time. But just maybe describe what those near-term priorities are on integration, whether it be operational or marketing, or other?

Thank you, Steve. The team has done an excellent job with the integration from day one, ensuring everything went smoothly. Safe and seamless operations were crucial. Currently, we're connecting with our new team members, focusing first on making sure our reliable assets are operational and that we are meeting our customers' needs without any issues. We are also assessing the systems and processes necessary for our global platform to ensure everything aligns effectively. Regarding synergies, the $30 million we projected consists of concrete savings we believe we can achieve within 18 months, particularly in logistics costs as we integrate into our global supply chain. While some savings, like those from SG&A, insurance, tax, and IT, can be realized quickly, transitioning entire systems will require more time due to the needed integration with existing business systems. We are confident in this ongoing work. In terms of synergy estimates, we didn't factor in any operations-related numbers. When we assessed these assets, we based our model on operating rates of 85% to 90%, alongside significant capital investments. Both sites have performed exceptionally well, and with our global manufacturing expertise, we aim to enhance operations and capital allocation further. We believe that additional synergies beyond the initial $30 million are possible, but we want to learn more before providing updated guidance and new KPIs over the next six months.

And just a follow-up on the broader market. There's been a lot of, I'll just say, chatter in the trade publications about China taking action against some of the older stock facilities in the country, and it's even created a little bit of upward pressure in the market there on a spot basis. Is that something that you're monitoring? And is it worth us paying attention to? Do you think that has an impact on that broader market from a supply side perspective? I'd just be curious to know if you're paying attention to there.

Yes. We're monitoring it closely because anything China does to rationalize overbuilt industries would be helpful. I think methanol is not an overbuilt industry. So first for us, we're in a very healthy industry when it comes to supply and demand balances. And I do think that's a difference between us and some of our chemical peers that we don't have the overbuild that we've seen in other industries. Having said that, we do indirectly get impacted, in particular, in the olefins market. And any rebalancing that could happen in the olefins market would be really a positive to our pricing in our industry because, really, it's about affordability of methanol into that sector, which is a big sector for us. So if those policies were introduced, of course, it looks like they'd be targeting the idling of older facilities and possibly deferring projects that haven't reached construction. I think it was initially introduced with maybe an aggressive mandate. Now there's a bit more softening of it. But we're going to continue to watch it. It's still early, but anything there would obviously be a positive for us.

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

I have two follow-ups. First, I wanted to ask about Iran. If the question or the answer is the same, feel free to respond briefly. I'm curious about the ability to ship out of Iran. In addition to direct sanctions on Iran, there seem to be some indirect sanctions affecting the shippers. There is some uncertainty over whether you can actually secure enough ships to transport sufficient methanol out of Iran, which would impact supply. Is this something you've observed?

It's something we're going to watch closely. But to date, they've really been able to get around the shipping through the use of the shadow fleet, and whether they can impact the operations of those vessels that operate there. We think there's enough methanol within that fleet today to be able to put the product into the market. And we continue to see compared to the first quarter, Iran is opaque for us. We don't have a lot of on-the-ground information of what's happening, but what we do see is imports into China, and imports into China have continued to increase as they've increased their operating rates. So, Josh, something we'll continue to track. And if they're able to get at those vessels, which we think there's adequate capacity today, then that could have a meaningful impact, but we're not seeing anything yet; it’s something we'll continue to monitor.

And a question for Dean on the accounting side. When we look at your balance sheet, you have about $2.9 billion in debt. We saw with the OCI deal, there was another $0.5 billion or so to come from basically assumed net debt and lease liabilities, and we didn't see anything go up on that. So I'm not sure if there's some weird accounting because the deal closed late, if that's maybe in nonconsolidated, or is your kind of in aggregate net debt less than what we were expecting?

Yes. Thanks, Josh. I think there's nothing about the closing date or anything like that. I think what it is, is the Natgasoline debt, which when we did the purchase price and when we did all our valuations, we assumed half of the debt in our modeling. That's how we look at it, even though it gets accounted for on an equity basis. So it's really sort of hidden in the investment and associate line on the balance sheet. That's an asset value and less debt. So it's a GAAP thing. But we'll continue to do all of our measures on a proportionate basis, like notwithstanding the accounting, because we do full consolidation for Egypt. Now we do equity for Natgasoline. But when it comes to our disclosures, it will all be reconciled back to our proportionate interest in our assets. Happy to follow up.

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

This is Kevin Estek on for Laurence. So my first question is just about global operating rates. I know you said they sort of improved over Q2, especially towards the back half. I'm just wondering sort of where they maybe started out in April, how they kind of ended the quarter, and maybe what you're seeing so far into Q3?

Yes, thank you. We believe that the first quarter was a significant low point, particularly for Iran, alongside outages in the Atlantic Basin. We experienced various outages and restrictions across the industry, leading to low operational levels. Inventories decreased, and we noticed premiums outside of China, while pricing in China was around $280 to $290, with premiums outside surpassing $100 per ton. As Iran's production improved after winter and other industry issues were resolved, we've observed healthy production rates. Currently, production levels in the Atlantic, Pacific, and Middle East, including Iran and China, are performing well. If you examine the operating rates, the numbers may not appear compelling, as they might be around 65% to 70%. However, a significant portion of that capacity is facing structural constraints, such as feedstock issues preventing plants from operating, sanctions restricting product access to markets, or lower operational rates in China. For example, while coal producers are operating at 75% to 80%, other production, like coke ovens, runs structurally lower, and some gas-based plants in China are also not fully operational. Therefore, we encourage the investment community to examine these percentages closely, as we currently do not see substantial latent supply in the market. Additionally, inventories in China remain below historical averages, and MTO plants are not operating at full capacity, indicating we can absorb supply. This situation suggests that even though we are experiencing slower growth, the methanol markets are balanced and may tighten even when operations are running smoothly.

And then just my second question, I guess, by your estimates, I mean, how much potential marine fuel demand on a run rate basis, I guess, could be sort of operational by year-end if all those dual-fuel ships ran on methanol, sort of blue sky scenario?

By the end of 2025, I estimate our number to be around 2 million tons. We need to be careful about what shippers will actually use. We believe that once the ships are operational, methanol will definitely be used to test the engines. Ultimately, when it comes to traditional fuels, the decision will hinge on the economic comparison between methanol, marine gas oil, and very low sulfur fuel oil. Currently, methanol is less expensive than marine gas oil but more expensive than very low sulfur fuel oil, which is more readily available. At this point, there isn't a significant economic incentive to switch. Discussions with shippers are increasingly focused on low-carbon methanol, particularly in light of recent policy initiatives from the International Maritime Organization. We're collaborating with shipping companies on both conventional and low-carbon options, but currently, their main interest lies in low-carbon solutions. If stringent policies are enforced, they may face a considerable need to use low-carbon fuels to avoid penalties. Therefore, most of our conversations currently revolve around low-carbon options rather than conventional methanol.

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

First one, just a quick follow-up. On the Natgasoline debt, I think back in September, the assumption was there would be about $450 million of debt and leases. Is that still a good number to use?

Yes, it's a good number, Nelson. Obviously, since that time, there's been normal course payments, the Natgasoline entities also refinanced the debt. So there's been some puts and takes, and we're going through an adjustment period, but 450,000 is still a good number to use.

The next question is about New Zealand. Rich, you mentioned that you reduced your New Zealand production estimates from 600,000 to 400,000. Is there a minimum amount that the gas suppliers need to provide you with? Additionally, if gas were not redirected to the electricity market this year, what would production look like?

Thanks, Nelson. I'll address that question in several ways. First off, if we hadn't diverted, we would have been operating the plant at around a 60% operating rate, which is significantly below full capacity. This is not an efficient way to run a facility. Considering the earnings in relation to fixed costs and plant operations, maintaining such a low output is certainly challenging for gas supply. If we take 60% of one plant, which processes 850,000 tonnes, that's roughly what our production would have been for the year. Looking ahead, our focus is on the short term. Currently, our gas profile has deteriorated due to existing well performance and limited investment in the Taranaki Basin. The government is aware of this and is attempting to address it through new policy incentives, but whether this will lead to increased investment remains uncertain, and even if it does, it will take time. Our efforts are concentrated on optimizing operations, and our team has been doing a fantastic job despite the uncertainties. In terms of profit margins for this quarter, we estimate that we made about $5 million to $10 million above methanol. We'll continue to monitor the local electricity market demands while striving to optimize the site and increase gas supply to support our operations.

And just a quick clarification on that. So when you divert gas to the electricity sector, you would idle your facility rather than run it at even a lower rate?

Well, we're at a point right now with the gas that we're getting, we're already on minimum operating rates. So to the extent that we're diverting, we're very close to minimum operating rates. We do think that this largely does happen seasonally. So right now, it's the winter period there, where there is more demand from the electricity sector. And so if there is large demand there, then we would shut down the plant.

The last question comes from the line of Roger Spitz with Bank of America.

First was a request tagging onto Jeff. Will you consider putting out, perhaps in an 8-K/A sort of OCI methanol sales and EBITDA, at least as you pick it up? I know you didn't take the bad hedge for the past six quarters. I recognize that might be beyond what you required to file, but it would be very helpful. Anyway, that's not a question.

Yes, we appreciate that feedback. As we approach the third quarter, we want to ensure that the investment community clearly understands how this affects our earnings. We haven't fully determined how we will communicate that yet, but it's important for us to provide guidance on how this is influencing our results. We will definitely take that feedback into account.

Great because we're having to just put it together from what they used to publish and make adjustments, and I guess, assumptions. So the realized net price discount versus your posted nondiscount benchmark price has been moving higher over the quarters. But I wonder how you think the OCI Methanol acquisition will impact that discount? Meaning, will it potentially lower the discount? Will it be higher than the discount about the same? I mean, I guess it depends on how that's all being sold.

Yes. Our focus is really largely what we focus on is our realized pricing. What we have seen is that over time, discounts in the Atlantic Basin have gotten larger. But at the same time, those regions also price at a premium over the cost curve. When we announced the deal, we knew that the business we were buying was largely selling in the Atlantic markets. That's confirmed. Most of the customer contracts that we have are Atlantic-based pricing. So I would expect that could move the average discount up. But what that will mean for our portfolio is higher realizations with a shorter supply chain. So it's an improvement in the portfolio, notwithstanding it might be an increase in the discount.

I understood that one reason for the increasing discounts was the need to ship more methanol produced in the Atlantic Basin to the Pacific Basin. This resulted in higher shipping costs due to the larger quantity of methanol, and that contributed to the rising discounts. Is that accurate?

I wouldn't say that was the driver. I think what happens is in the methanol markets, the way that suppliers and the way consumers buy and the way sellers sell is based off of a contract price less a discount. And as there's been more Atlantic production over time and with the rise in shipping costs, a greater incentive to stay closer to the plant; that's led to an increase in discounts with the competition that's been in the market. And so that has led to that expansion in discounts, notwithstanding the price realizations are still at premiums over the cost curve.

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

Well, thank you for your questions and interest in our company. We hope you will join us in October when we update you on our third quarter results.

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