Methanex Corporation (MEOH) Q2 2025 Earnings Report, Transcript and Summary

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. [Operator Instructions] 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, 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, 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 of $374 per tonne, and produced sales of approximately 1.5 million tons, generated adjusted EBITDA of $183 million and adjusted net income of $0.97 per share. Adjusted EBITDA was lower compared to the first quarter of 2025, primarily due to a lower average realized price. On June 27, we successfully closed the previously announced acquisition of OCI's methanol business. This is a highly strategic acquisition for Methanex, which we believe significantly strengthens and expands our production portfolio with 2 world-scale methanol facilities in Beaumont, Texas, which have access to stable and economic supply of natural gas feedstock. The integration is proceeding as planned, and we're focused on maintaining safe and reliable operations, continuing to meet customer commitments, and delivering the strategic and financial benefits of this acquisition. I would like to extend my personal thanks to the team for their hard work and dedication in planning and carrying out a safe, reliable, and seamless day 1 continuity of operations. It's been very exciting to welcome the new talented team members into our organization. Now turning to methanol market conditions. After realizing over $400 per ton in the first quarter of 2025, we continue to achieve strong results with second quarter global average realized price of $374 per ton. We estimate global methanol demand was about 4% higher in the second quarter compared to the first quarter. The increase was primarily driven by higher demand in China across all applications. Traditional and other energy demand in China rose in line with seasonal construction and transportation activities, as well as strong export manufacturing and domestic consumption, which offset a continued strained property market. Demand was also supported by methanol to olefins operating rates, increasing gradually throughout the quarter as supply from Iran increased post-winter gas curtailments. In the rest of the world, demand remained largely stable with minor regional differences. On the supply side, methanol production from Iran steadily increased throughout the quarter -- second quarter, as feedstock restrictions eased. We believe the disruptions to Iranian methanol production in June as a result of the significant escalation in the ongoing conflicts in the region was short-lived, and we estimate Iran's operating rates increased by over 50% from the previous quarter. Globally, we believe the methanol industry operated at very high rates with limited outages. In the Atlantic Basin, strong production and stable demand led to inventory rebuilding from a low point over the course of the quarter, with pricing softening from high levels in Q1 as a result. In the Pacific Basin and in particular, China, the inventory buildup was more moderate as increasing MTO operating rates absorbed much of the increased supply availability in the market. Looking ahead to the third quarter, we estimate the methanol affordability into MTO and the marginal cost of production in China to be in the range of approximately $270 to $290 per tonne, and we continue to see realized pricing in all other major regions at premiums to these pricing levels. We posted our third quarter European quarterly price at EUR 530 per tonne, representing a EUR 95 decrease from the second quarter. Our North America, Asia Pacific, and China prices for August were posted at $778, $370, and $350 per tonne, respectively. We estimate that, based on these posted prices, our July and August realized price range is between approximately $335 and $345 per ton. Now turning to our operations. Methanex production in the second quarter was similar compared to the first quarter, with higher production from Geismar and Trinidad, offset by lower production from Chile, New Zealand, and Egypt due to gas constraints as well as a planned turnaround in Medicine Hat. In Geismar, production was higher in the second quarter as G1 and G2 operated at full rates for the second quarter and G3 successfully restarted in early May. As it relates to the previous challenges we've experienced on G3, we feel confident we've addressed these with new start-up conditions that allow us to safely and reliably start up without risk to the autothermal reformer. Towards the end of June, we experienced utility and power outages, which reduced methanol production at the Geismar site. All plants returned to production in early July and are currently operating at full rates. For both the 100% owned Beaumont facility and the 50% owned gasoline facility, as previously mentioned, integration is going well, and both assets have operated safely and at full rates since acquisition. In Chile, we operated both Chile plants at capacity for the period September 2024 through April 2025, achieving our highest production rate since 2007. On May 1, we idled facility as planned and are currently conducting maintenance in preparation for restart late in the third quarter. While seasonality in production is expected to continue, we continue to see positive developments in natural gas availability and are working closely with gas suppliers to improve production rates over time. In New Zealand, we had lower production due to the temporary idling of operations in mid-May through the end of June under a short-term commercial agreement to redirect contracted natural gas to the New Zealand electricity market. The plant successfully restarted in early July, and we forecasted our production for 2025 for New Zealand to be approximately 400,000 tonnes. Gas supply availability in New Zealand continues to be challenged, and we continue to work with our gas suppliers and the government to sustain our operations in the country. In Egypt, we experienced some curtailments due to significant import disruptions, which ended in late June. We're 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. Our expected equity production guidance for 2025 is approximately 8 million tonnes, including the fully owned Beaumont facility, both its methanol and ammonia production, as well as our share of production from the Natgasoline plant. 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 second quarter with $485 million of our share of cash, which is inclusive of approximately $50 million that was acquired with the transaction and access to an undrawn revolving credit facility, which was upsized with the closing of the transaction to $600 million. Our priorities for the second half of 2025 are to safely and reliably operate our business and smoothly integrate the new assets. Our top capital allocation priority will be to direct all free cash flow to deleveraging in the near term through the repayment of the Term Loan A facility. We do not anticipate significant growth capital over the next few years and remain focused on maintaining a strong balance sheet and ensuring we have financial flexibility. Based on higher produced sales offset by a lower forecasted average realized price, we expect higher adjusted EBITDA in the third quarter of 2025 compared to the second quarter. As we move through 2025, we would expect production and sales of produced product to more fully reflect our run rate capacity. We'd now be happy to answer questions.

[Operator Instructions] Your first question comes from the line of Joel Jackson with BMO Capital Markets.

I'm going to ask 2 questions and ask them one by one. Rich and team, just on operating rates at G3 Beaumont and OCI, can you talk about -- it looks like G3 has been running other than the hiccup you said at the site that's been running over 90% since you restarted it. And then can you talk about how Beaumont and Nat gas have been running in the month or so since you've had it?

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 has -- these assets have been running at full rates since acquisition. I'll just say the Beaumont asset went through a turnaround in March, successful turnaround there, operating well for the -- 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 6 months of high operating rates, I believe it's a record 6 months of production there. So those assets 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. Then my final question is, when you announced the OCI deal, you had a slide in your September 2024 presentation deck where you said, look, if we get $3.50 realized in ethanol and if we get $3.50 gas, we will deliver post-OCI run rate, including synergies, $1.125 billion EBITDA, a very specific number. in your new slide deck last night, you've guided that down slightly, $50 million down to $1.075 billion under the same assumptions. What I want to ask you--

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

So that is my question, which is the $50 million difference, is that all New Zealand? Yes, it is all New Zealand. So we -- you'll see that the equity tonnes in that previous slide deck would have been around 10.2 million equity tonnes. It's now 9.6 million.

So we brought New Zealand down by 600,000 tonnes. So it's -- New Zealand is at 400,000 tonnes now in the run rate based on the -- really about gas and the outlook, the difficulty in really assessing gas beyond what we're producing this year. So -- and that really has been the main adjustment to free cash flow and EBITDA in those numbers as well. So just to be clear because it is a point, and it's one that we certainly want to clarify that has nothing to do with the transaction.

Just following up on that, Ben, 2 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?

Well, we're in the numbers in the run rate today for New Zealand, the 400,000 tons at that level, really the earnings relative to the fixed -- adjusted EBITDA relative to our fixed cost, there is not a lot of earnings and cash flows left in for New Zealand, and we've not forecasted any gas sales in those numbers either. So when we look at it next year, could we achieve it? The number includes synergies. So it includes the $30 million in synergies. And we've said that we're -- it's going to take us 18 months to achieve those synergies. So we're working on that $30 million. Everything that we've done so far has validated our initial assumptions around those hard synergies. So we're going to be progressing towards that. But it is a good number, 9.6 million equity tons. I think the it's always going to be subject to production and our ability to run the assets, and a lot of that's on gas feedstock. Now with 65% of our production in North America with stable gas, we think that those run rates are achievable and everything on -- from an EBITDA and free cash flow, we feel really confident. Of course, we've got to prove that out, and we got to have a good run on our assets, and we're going to continue to work on our gas feedstock.

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 you see operations expanding?

Yes. We're -- thanks, Hamir. We're really -- it's early for us in ammonia. Right now, we're really trying to understand the operations there and integrate it into our business. As far as the market goes, we know that the market we entered this year in a pretty tight market. Pricing rebalanced with more supply coming in. I think we're right now, Tampa is above $400 a ton. The view is there's been some tightening on supply, and that has likely projection to go up. That's about where we modeled the pricing when we did the transaction. We're going to continue to learn more. Right now, the ammonia business represents about 3% to 5% of our global sales, but it's an area we want to continue to understand better. We know that that's something we need to focus on, especially at least initially, it's about operations and integrating this into our marketing and our supply chain and getting a better understanding of it. But right now, it's very similar conditions as we would have predicted when we did the deal. So we'll have more to report, I think, as we learn more about the operations, get a better understanding in the medium, longer-term outlook in ammonia.

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

Yes. So we -- like what we said previously is that our hedging strategy in North America is to be meaningfully hedged in the short term, and where we target is to be around 50% to 70% hedged in the first 3 years. Beyond that, we stagger the hedging down 25% to 50% in the 3- to 5-year period and then lower beyond that because OCI assets are coming to us largely unhedged, and we were already at the top end with Geismar, we're now at around the 50% hedge level, which is a comfortable place for us to be. The forward curve today is not at a price in the short run anyways that's real attractive for us and spot pricing is at $3 an MMBtu. So we're comfortable with where we're at in the short term. Interestingly, the longer end of the curve is pricing down, and we've been able to get in some, I would call it, small hedging in the 2030 plus range at below $3.50 all-in cost. So we're going to continue to be opportunistically in the market, but we're comfortable with where we're at right now.

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 6 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 6 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. No, thanks, and you got right to the end. This is a GAAP requirement to go on a pro forma basis to what the prior business was. So we were -- it's prescriptive as to how that's done, and you take the OCI prior information. And so that's at last year's information with regards to price, with regards to operating rates, which is not the business that we have today. So I would encourage you to not look at that disclosure. It's a GAAP requirement.

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 2 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 2 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?

Thanks, Ben. I guess the first thing I'd say is the value will -- the value in place comes down largely to the gas stock and feedstock availability and the economics of that. That's in-place value will be determined by that. And the reason those assets are running is because of the outlook, do they have option value because we've seen over time that many, many times where assets or gas basins aren't performing that those dynamics change. And so there's certainly option value in place, and that's something that we look at is how do we preserve option value. In terms of relocation value, what we've learned through our relocation because that's also an option would be to sell the assets and have a buyer relocate to a location where there is economically priced gas. The value in relocation is not on the ability or the overall capital savings that you get from a relocation. The real value is in speed. And so if you wanted to execute a project quickly, that's the way to do it, which obviously affects project economics, the speed at which you can execute a project. So right now, the market is not -- firstly, the dynamics in each of those locations is challenged for the reason they're down. Secondly, the market is not telling us to move quickly on a project. Will those -- will that value change over time becomes a question of market dynamics, whether it's the gas or the feedstock in those locations, or what happens in the market. And if the market tells us to move quickly on a project, there's value there, which, of course, we would like to give to shareholders before we give it away. So -- but we're always looking at these things. I would say that we're not in a $15 to $20 per share value at all for those assets.

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 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, the secondary sanctions, and we can take this offline, but we believe that this is not the first secondary sanctions that have been applied, and some of these have been applied to individual plants starting in 2020. So the Cave is a newer plant, and they've now applied that to those operations. The secondary sanctions, Iran has been very successful in avoiding secondary sanctions, whether it be through the use of the shadow fleet and other means to get product to market. So we don't think that it will impact the actual production and ability to sell it into the market, but it may limit which customers. And I think your reference to India there. I think secondary sanctions, you may find that certain buyers will not touch anything that is coming from a plant that has those sanctions on them. And there could even be buyers in China that will avoid it as well. But we've seen product that has secondary sanctions still getting into the market. So there still is willing customers for that product. And it may mean that it comes in at a lower price as well. So -- but we haven't -- we don't -- we aren't forecasting any big changes in overall balances because of those actions.

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?

Yes, for sure. Thanks, Steve. It's -- the team has done a really fantastic job in getting us off to a great start with the integration day 1, everything seamless -- safe and seamless operations was really critical. We're -- right now, we're making all the connections into the business, working with our new team members. So the first thing we wanted to do is make sure the safe, reliable assets are running, the commitment to customers that we're delivering product, and we can do that seamlessly in our operations. And then what we're doing right now is obviously looking at all the systems and processes that need to be incorporated because we run our business on a global platform. So all of our systems and processes need to speak to each other. And all of those things will be happening. When it comes to synergies, the $30 million that we gave were really hard. Those were hard synergies. We think we felt we could get at within an 18-month period, things like logistics costs. And as we've incorporated this reasonably quickly into our global supply chain. Those are things that we can get at relatively quickly. The other parts are a lot of SG&A costs, insurance, tax, IT. Some of those we can get at quickly. Some of those will take time. Switching over a whole -- all your systems will take time because there's a lot of integration that has to happen around the other business systems. So we feel really confident with that, and that work is all ongoing. The operations side in the synergy numbers, we didn't put anything in there. So when we modeled these assets, we modeled them 85% to 90% operating rates in that range. We also put meaningful capital against those assets. And we can see that the team has done -- for both of those sites have done a real fantastic job in in work they've done over time. And now we're bringing in our global manufacturing expertise, and we want to work with those teams and continuing to improve operations as well as capital deployment. So we think there are further synergies beyond the $30 million. But of course, we want to learn first and be able to give guidance that we feel really good about, and we'll take our time over the next 6 months to learn more before we start setting new KPIs around that.

And just a follow-up on the broader market. There's been a lot of I'll just say, chatter in the trade pubs 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 this -- if those policies were introduced, of course, it looks like they'd be targeting idling of older facilities and possibly deferring projects that haven't met -- 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 had 2 follow-ups. First, I wanted to ask on Iran. And if the questions -- or the answer is the same, feel free to answer as briefly as you'd like. But more around the ability to ship out of Iran. So in addition to Iran being sanctioned directly, indirect sanctions, there's some sanctions that appear to be on the shippers themselves. And there's some debate about whether you could actually get enough ships to actually ship enough methanol out of Iran, and that's how you get supply impacted. Is that something you see at all?

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're able to impact the operations of those vessels that operate there. We think there's enough methanol within that fleet today to be able to put 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 not seeing anything yet, 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 proportionate -- 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. Thanks. We think that Q1 was a real low point, especially particularly for Iran as well as there were outages in the Atlantic Basin. So we saw a number of different outages across the industry there and/or restrictions, which meant the industry was operating pretty low. Inventories drew down, and we saw premiums outside of China, China pricing in at around $280, $290, and premiums outside of China got above $100 a ton. As Iran began to produce better coming out of the winter period and a lot of the other issues across the industry got resolved, we've seen healthy production rates. At this point, we look at production in the Atlantic, we look at production in the Pacific, Iran, mainly Middle East, and even China, the industry is operating really well. If you were to look at the numbers on operating rates, it might not be compelling because you'd see a number probably 65%, 70%, but a lot of the capacity that is in that number is structurally constrained, whether it's feedstock constraints that those plants are not turning on, whether it's sanctions that aren't allowing that product to get into market or even in China, when you look at a 65% operating rate in China, you have to look at that as the coal producers are operating at 75% to 80% and some of the other production, coke oven operates structurally lower. That's just the business because it's a byproduct. And the gasoline or natural gas-based plants that are in China, some of that structurally shut down. So you have to really look at the percentages closely, and that's something that we want -- we're trying to help the investment community understand that, because as of today, we just don't see a lot of latent supply in the market that can turn on. And at this point, we've got inventories in China still below historical norms and MTO not operating at full rate. So we've got a lot of capacity to absorb supply. And I think that's just indicative of not -- even though we're in a slower growth phase, methanol markets are balanced to tighten even when things are operating well.

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?

So by the end of 2025, I believe our estimated number is around 2 million tons. That -- what we have to do is be real cautious about what will shippers actually burn. We do think when the ships get into the water that methanol will be burned to test the engines for sure. Ultimately, if you're talking about conventional fuels, it will come down to energy equivalent economics between methanol and marine gas oil and VLSFO. And today, methanol is cheaper than MGO, but it's more expensive than VLSFO, which is the abundance of fuel is the low sulfur fuel oil. So today, there isn't an economic price of switching. We are looking -- shippers when it comes to methanol are more -- the discussions are more about low carbon methanol, especially because of some of the recent policy initiatives by the International Maritime Organization. And so we're working with the shipping companies on both conventional as well as low-carbon. Their focus area is a lot on the low-carbon. And in the event that stringent policy is actually implemented, they could have a fairly large gap where they have to -- they have to burn low-carbon fuel or be subject to penalties. So a lot of our discussions are in that area and not really in the conventional methanol area today.

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.

And then next question is on New Zealand. I think, Rich, you mentioned that you took your New Zealand production assumptions down 600,000 to 400,000. So is there a minimum amount of -- that the gas suppliers need to provide you with? And then I guess the second part of the question is, like for this year, if gas were not diverted to the electricity market, what would production look like?

Thanks, Nelson. And Nel, maybe I'll address that question in a number of different ways. So first off, if we hadn't diverted, we probably would have been -- we're operating the plant at around 60% operating rate, so well below full capacity. That is not an efficient way to be operating a facility. And when you look at the earnings there relative to the fixed cost and also the operation of the plant, it's certainly something that we -- on a sustained basis, that's a challenging gas profile. But you can take 60% of one plant, which is 850,000 tonnes, and that kind of would be sort of where we would have produced for the year. When we look forward, we're really looking in the short term because where we are today, our gas profile there has really deteriorated to this level because of the performance of existing wells as well as the limited capital that's going into the Taranaki Basin. And the government -- current government recognizes this, and they're trying to address that through new policy incentives. But whether that spurs on more investment is a question mark. And then even if it does, it will take time. So we're really focused on the short to medium term there. And obviously, we're looking at the best way to optimize our operations there. And our team has been doing a fantastic job of doing that in the face of a lot of uncertainty. So we are in terms of how much margin over production, overproducing we've made in the quarter, that was probably about $5 million to $10 million over and above methanol. We'll continue to look at what the demands of that local electricity market are, but we're really trying to optimize the site, and ultimately, we're trying to get more gas to support our operations there.

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. And 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 6 quarters. I recognize that might be beyond what you required to file, but it would be very helpful. Anyway, that's not a question, Michael.

Yes. We'll take that feedback. We certainly, when we get to the third quarter, we want to make sure that the investment community has a good understanding of the impact on our earnings. How we do that, we haven't quite worked that out specifically yet, but we will -- we do want to make sure that we're giving guidance on the impact that's having on our results. So we'll take back that feedback for sure.

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 do 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. So for -- 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 over time. 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 is 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.

And just so I understood, I thought another reason these discounts were getting larger was having to send more Atlantic Basin-produced methanol to the Pacific Basin. So you got more shipping -- higher shipping costs on a relatively greater amount of methanol, your ship was another driver of why the discounts were rising. Is that a fair comment?

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.