Ladies and gentlemen, thank you for standing by. Welcome to the Methanex Corporation Q3 2022 Ernings Call. I would now like to turn the conference call over to Ms. Sarah Herriott. Please go ahead, Ms. Herriott.
Good morning, everyone. Welcome to our Third Quarter 2022 Results Conference C all. Our 2022 third quarter news release, Management's Discussion and Analysis, and financial statements can be accessed from the Reports tab of the Investor Relations page on our website at methanex.com. I would like to remind our listeners that our comments and answers to your questions today may contain forward-looking statements. 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 third quarter 2022 MD&A and our 2021 annual report for more information. I would also like to caution our listeners that any projections provided today regarding Methanex's future financial performance are effective as of today's date.
It is our policy not to comment on or update this guidance between quarters. For clarification, any references to revenue, average realized price, EBITDA, adjusted EBITDA, cash flow, adjusted income, or adjusted earnings per share made in today's remarks reflect our 63.1% economic interest in the Atlas facility and our 50% economic interest in the Egypt facility and our 60% interest in Waterfront Shipping. In addition, we report our adjusted EBITDA and adjusted net income to exclude the mark-to-market impact on our 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 in this manner. I would now like to turn the call over to Methanex President and CEO, Mr. John Floren, for his comments and a question-and-answer period.
Good morning. I hope that everyone is continuing to stay safe and healthy. This morning, we have Rich Sumner on the call, who will become our new president and CEO on January first, 2023. It has been a privilege to serve as Methanex President and CEO for the past 10 years. I look forward to seeing Rich continue to extend our global market leadership position, as well as continue to lead our strong performance in safety and operations as he assumes the CEO role. On the call today, we will review our third quarter 2022 financial results, provide an overview of the methanol markets, discuss our operational results, and share our near-term outlook. We will open up the call for questions.
Our average realized price of $377 per ton generated adjusted EBITDA of $192 million and adjusted net income of $49 million or $0.69 per share. Adjusted EBITDA was lower in the third quarter compared to the second due to a lower average realized price, lower sales of Methanex produced methanol because of planned turnarounds and some unplanned outages, and higher spot gas costs in North America that impacted EBITDA by approximately $10 million. This was partially offset by redirecting and selling our contracted natural gas in Egypt. Global methanol demand in the third quarter was flat compared to the second quarter of 2022.
Demand from the traditional chemical applications was down slightly with acetic acid plant restarts in North America being offset by other plant outages and logistics constraints across various downstream sectors, as well as a slowdown in demand growth, primarily in Europe and China. Demand for methanol to olefins or MTO remained stable with the start-up of the new Bohai Chemical MTO plant, which can consume up to 1.8 million tons of methanol, ramping up to 70% in the third quarter. This offset lower operating rates from existing plants in July and August as MTO affordability came under pressure. Demand from energy-related applications increased in the third quarter as easing COVID-19 restrictions in China led to an increase in demand for MTBE and other fuel applications. Industry operating rates decreased in the third quarter because of extended turnarounds as well as planned and unplanned outages globally.
We estimate the industry cost curve based on the marginal coal producer cost in China to be approximately $350 per ton. Our November posted prices remained healthy. North American prices remained flat at $585 per ton. Asia Pacific and China prices remained flat at $410 a ton and $395 per ton, respectively. Our European contract price is set quarterly, and we decreased our fourth-quarter 2022 price by EUR 45 per ton to EUR 510 per ton. Less volatile spot prices in the third quarter, primarily in China, led to a lower discount rate of 21.5% compared to the second quarter. We're currently seeing demand similar to the third quarter.
We recognize there's potential downside risk in demand due to the energy crisis in Europe, extended COVID-19 lockdowns in China, global inflationary pressures, and rising interest rates' impact on consumer sentiment and demand. High global energy prices enhance methanol's cost competitiveness against alternative fuels, which could lead to increased methanol demand. Demand from the shipping industry continues to grow, and based on existing dual-fuel ships and orders to date, we expect potential demand to increase from approximately 300,000 tons today to 2 million tons of demand over the next few years. Our production levels were lower in the third quarter compared to the second quarter due to two planned turnarounds, some unplanned outages, and a redirection of sale of our contracted gas in Egypt, which I will discuss after an update on the rest of our sites.
Medicine Hat had lower production in the third quarter due to an unplanned outage in July caused by storm damage impacting the plant's power supply. Geismar had lower production in the third quarter due to an unplanned outage in July, which we extended due to elevated gas prices at the time. Also, at the end of September, the utility supplier for the Geismar site experienced an extended loss of power due to a failed transformer, which lasted until mid-October. The team took this opportunity to advance some critical Geismar 3 tie-ins. We are forecasting a natural gas price of approximately $5.80 per MMBtu for the fourth quarter for the 35% spot portion of natural gas purchases that are not contracted.
In Chile, production was lower in the third quarter, although higher than the third quarter of 2021, as only Chile one was operating due to limited gas availability from Argentina. We typically experience lower gas deliveries in the southern hemisphere winter months, impacting our second and third quarters. Chile four restarted in mid-October with gas deliveries from Argentina that we expect will allow us to operate both plants through the first quarter of 2023. We estimate the 2022 production to be approximately 0.9 million tons. In New Zealand, we completed a successful turnaround at Motunui one , which restarted in mid-September. Motunui two operated throughout the third quarter, but at lower levels due to gas availability restrictions from the Maui gas field. We expect both plants to be operating at full rate sometime in the fourth quarter.
Based on the production to date and our outlook for natural gas in New Zealand, we estimate the 2022 production to be between 1.2 milion tons and 1.3 million tons. We had low levels of production from Egypt in the third quarter as we completed an extended plant turnaround. The timing of the turnaround enabled us to enter into an agreement to redirect and sell the plant's contracted natural gas from late July to late October. This was a unique opportunity to utilize excess LNG capacity in Egypt during a period of elevated LNG prices in Europe and was done in collaboration with our Egyptian government partners.
We estimate that the sale and redirection of our gas resulted in an incremental benefit to the third quarter of approximately $35 million compared to using this gas for production of methanol for the period of time it was not scheduled to be under turnaround. The plant is in the process of restarting. We ended the third quarter in strong financial position with approximately $890 million of cash, excluding non-controlling interest and including our share of cash in the Atlas joint venture, and we have $600 million of undrawn backup liquidity. We remain committed to our disciplined approach to capital allocation. We continue to focus on maintaining our business, pursuing economic value-added growth opportunities that exceed our cost of capital by 3 percentage points, and returning excess cash to shareholders.
Construction of our Advantage G3 project is progressing safely and is scheduled to be completed in the fourth quarter next year. We've spent approximately $810 million before capitalized interest to the end of the third quarter and expect approximately $450 million-$500 million remaining capital cost before capitalized interest, which is fully funded with cash on hand. Our asset portfolio and cash flow generation capability will be significantly enhanced when G3 comes online next year. With our G3 project being fully funded, our strong cash position, and our ability to generate meaningful cash flow across a wide range of methanol prices, we are well-positioned during this period of economic uncertainty to continue returning cash to shareholders through a sustainable growing dividend and share buybacks, including our 5% share buyback announced in mid-September.
Production in the fourth quarter is expected to be approximately 1.6 million tons, much higher than the third quarter. We anticipate a build of produced inventory through the quarter as the methanol sold in the quarter will be more weighted to purchase product as a result of our FIFO inventory flows. Based on our posted prices in October and November and higher expected produced sales, we expect higher adjusted EBITDA in the fourth quarter compared to the third quarter if the one-time benefit of the Egypt natural gas sale of $35 million is removed. In the medium term, the methanol market outlook is positive, and we have growing cash flow generation capability with G3 coming online in the fourth quarter next year.
At $375 a metric ton methanol price and $4 MMBtu gas, we expect G3 to generate approximately $250 million of EBITDA per year. We have a strong balance sheet and committed to deliver on our capital allocation commitments of returning excess cash to shareholders. Looking forward, our geographic diversity advantage feedstock cost position with 85% of natural gas needs in North America hedged next year and our unique global supply chain will continue to allow us to be the methanol supplier of choice and deliver value to shareholders. We would now be happy to answer questions.
At this time, if you would like to ask a question, please press star then one on your telephone keypad. Our first question is from Joel Jackson with BMO Capital Markets. Your line is open.
Hi. Good morning, John.
Hey, Joel.
We're running out of calls like this. I don't think you give a production volume kind of forecast for Q4. Could you tell us what you think Q4 might look like versus Q3? Also a second part of that question would be, should we expect the gas resale benefit in Egypt to be, you know, on a monthly basis, like, a lot lower than the kind of $17.5 million per month rate you got in Q3 in August and September because obviously gas prices have come down?
Yeah. Egypt, we realized all the benefit in Q3. You know, that was all realized in Q3. That $35 million is all the benefit of redirecting that gas for LNG and, you know, obviously sharing with the government, et cetera. It's based on, you know, selling prices through the three month period. As far as production, it's 1.6 million tons for Q4 is our-
Okay.
forecasted production.
Okay. My next question is a fun one. Are you ready?
I'm ready.
Okay. John, during your tenure at Methanex, it's been a long time, but, you know, over the last decade or so as CEO, what would you say is sort of the thing that you're most proud about? What is the one that you'd say maybe the one that got away, the opportunity or something that got away?
Yeah, I would say our safety record is the thing I'm most proud about and our internal succession process and developing people. Those would be the two things I'm most proud about. One thing. Many things got away. You know, I think we had a lot of volatility during the time in the last 10 years. You know, I think we came out a stronger company as a result of the teamwork. I don't wanna go through all the things that got away, but you know, certainly lots of noise during the last 10 years.
Okay. Thank you.
Thanks, Joel.
The next question is from Ben Isaacson with Scotiabank. Your line is open.
Thank you very much, and good morning, everyone. In other petrochemical chains, we've seen volume down 10%-15% in Europe, similar in China, generally hanging in the rest of Asia and North America. Now, you did say that Q3 volume was flat versus Q2, and right now what you're seeing is that it's flat, and you also highlighted the risks in Europe and China already. When you say that it's flat right now, does that mean it's stronger in some regions and it's weaker in other regions? Is what you're seeing consistent with what we're seeing in other chemical chains? If not, maybe can you just talk about real-time demand on a regional basis?
Yeah. I'll ask Rich to answer that question.
Hey. Good Morning, Ben. You're right to say that it's not the same across all regions. In the third quarter, we saw stronger demand for traditional. This is mainly on the traditional side, stronger demand in North America. Part of that was return to operating rates for acetic acid producers. But we are seeing still healthy demand in North America. Things are pulling fairly strong there. We actually do think that there is some impact of lower operating rates in Europe that may be shifting some industrial production into North America. In Europe, we are seeing traditional demand down. In that region, there's a bit of a some offset there. We're continuing to track China for traditional demand growth.
We would say that that's been relatively flat, and there is some pressure obviously with zero COVID lockdowns and also a slowdown in housing there. We're watching those things closely. We haven't seen a significant pullback in demand in any region. Europe is the one that we have seen some modest pullback. We're continuing to watch all of it across all applications. We have had some offset obviously with higher, stronger demand into other energy applications in China. You know, Q2 was a period where COVID lockdowns were quite restrictive. In Q3, some of that eased off, which meant there was better demand for transportation fuels as well as other thermal applications.
We would see that continuing with high energy pricing as well as some easing if COVID lockdowns continue to ease. We're watching all markets right now. You know, things are still probably trending at Q3 levels.
Yeah. I'd just add the MTO, right, where we've added a new plant in Bohai. That's new demand, and that's 1.7 at full rate. Yeah, we watch the other, our customers, what they're reporting as well. We're just not seeing that in our business yet, but we're certainly cautious about what could be coming.
Thank you. Just a quick follow-up. You mentioned, John, that I think you said both plants in New Zealand will be up and running sometime in Q4. Does that mean that this Maui gas field issue is now behind us and, you know, as we look into 2023, in the absence of any turnarounds, we should be kind of back to normal production in New Zealand, all else equal?
Yeah, both plants are running now, Ben. I think my remark was that full rates in the quarter.
Okay.
That's our expectation. We expect to be running both plants at full rates next year, provided, you know, there's not any further disruptions in the gas supply. That's what our gas suppliers have told us, and that's what we're expecting.
Great. Thank you very much.
The next question is from Nelson Ng with RBC Capital Markets. Your line is open.
Great. Thanks. Congrats, John, on your upcoming retirement and congrats to you, Rich, on your new role. First question is, it sounds like Egypt was a special situation where you were able to use excess LNG capacity to divert gas. Can you talk about whether there's any other opportunities to resell gas or divert gas? 'Cause I remember in New Zealand recently you agreed to reduce production to allocate more gas to power plants. Yeah, can you just give us a bit of color on whether there's other opportunities in other regions to divert gas?
Yeah. We're in the business of producing methanol and selling methanol. I think the Egypt opportunity was unique because we had a planned turnaround at the same time, and which only happens every four years. The conditions were that there was excess LNG capacity and a high price in Europe. I mean, but those were very unique conditions. Would those conditions happen at some point in the future? Well, they haven't happened in the last 30 years, so who knows? Certainly we're in the business of producing and selling methanol.
Okay. Got it. Then, you talked about G3 and your expectation of, I think $250 million of EBITDA contribution per year. Is that assuming that it's operating close to, or 90%-100% utilization? Then on the back of that, can you give us an update on your hedging position in North America?
Yeah. Our hedging position hasn't changed during the quarter. We haven't added any hedges, so it remains unchanged. Yeah, we plan to run G3 at full rates.
Okay, thanks. I'll leave it there.
Thanks.
The next question is from Steve Hansen with Raymond James. Your line is open.
Yeah. Good morning, guys. I'll just echo the congratulations comments earlier to both of you. Question to start is just around regional contract spreads. I know we've been in a position like we have for some time now, but I just wanna ask about the regional spreads being extremely wide relative to history here, particularly in the Atlantic Basin. Is that a situation that you expect to carry through 2023 and perhaps beyond, just given the market dynamics you're seeing? Or how would you think about that spread going forward?
Yeah. I'll ask Rich to answer that one.
Hi, Steve. Yeah, this certainly has been the dynamic we've seen. We're in contract season now. It's just starting, so it's hard to give you know, guidance on that. The Atlantic is obviously where we've seen that, the spreads. That's been on the back of a lot of new capacity that's been added over time. We haven't seen any new capacity or in our outlook any new capacity other than G3, so we're gonna have to watch and see what happens. You know, we'll obviously go through that and we'll give guidance on where we see discount levels going forward.
Yeah. I think as well, I mean, we look at realized price. That's what's important. I think, you know, like the Atlantic Basin is still our best realized price throughout our company. Yeah, spreads are certainly something people watch, but we look at realized price. $377 is, you know, if I could take that for the next 10 years, or Rich could take that for the next 10 years, I'm sure he'd be very happy.
No, fair enough. That's helpful. Just maybe as a related question then, because you've introduced this new China contract that sort of breaks apart the traditional Asia,China combined contract. Maybe just could you speak to the benefit that you've seen from that and whether it's been effective from, you know, what you'd originally planned? Thanks.
Yeah. I think probably the biggest benefit is that just the Asia Pacific region as a whole is quite—there's a lot of unique elements to it. Having the China market separate from the Asia market, those markets don't move the same way, and we're able to obviously stay competitive with our customers in those markets in a lot more timely fashion. I think it's working well with our customers in those regions and helping us stay competitive on a monthly basis to those markets. Yeah, it's working the way we would have hoped.
Yeah. I think when we put APCP in many years ago, you know, the Iranian product wasn't only destined for China. I think that dynamic has really changed the Chinese import market. You know, the traditional freight differential from China to the other parts of Asia changed as a result. Having the two prices, I think allows us to stay more in tune with the different markets in Asia.
Appreciate that . Thanks.
The next question is from Josh Spector with UBS. Your line is open.
Yeah. Hey, thanks for taking my question. Just to follow up on the Egypt gas sale, and I understand it's not that you don't want that to be your normal mode of operation, but assuming your prices for gas go up again, was this a unique kind of discussion with the government to make this happen, and you'd characterize it as more one-off? Or if that door opened up, is that something you could quickly switch to if it was advantageous for you to do that?
Well, we own 50% of that plant. We operate, so we have a partner there, and that's mainly the government. You know, any ideas we talk about with our partners and look at them. I'd say, you know, this is a unique opportunity for us because we are in a plant turnaround anyways, and we won't have another plant turnaround for probably three, four y ears so that, you know, the dynamics would be different if we're operating fully versus a plant turnaround. I don't like to predict the future. I'm not very good at it, but certainly this was very unique and hasn't happened in our 30-year history. Yeah, we did do something in New Zealand, but that was more as a need for the country needing the gas for electricity.
It was very different circumstances than what happened here in Egypt.
Okay, thanks. That's helpful. Just a follow-up on the methanol for fuel demand in the marine market. I mean, you talk about the 2 million tons of potential demand to be added. Curious if you could provide any color. Like, within that calculation, are you assuming a mix of fuel in those dual feed engines similar to what it's at today, which is kind of a low level of methanol? Are you assuming that's all methanol? Just curious of kinda how that shakes out today versus how you're seeing that maybe shift over the next couple of years.
The 2 million number that we've provided is demand potential. That assumes all those vessels run on methanol 100% of the time. You know, what fuel will be the choice will be dependent on each of the shipping companies and what they're operating at the time. We think certainly that the shipping companies are choosing methanol because of one, its clean burning attributes as well as its future pathway to low carbon. We think that methanol has been the choice they've made because of that, and they're looking and seeking the economics of methanol as well as its our ability to decarbonize over time. All of that will have to play out.
We think that 2 million tons is what's on order today, and there's a lot of other discussions that are going on, which we would expect to see that order book continuing to increase over time.
Yeah. I think regulations will continue. Regulations will continue to get, you know, tighter and tighter and maybe some of the alternatives today won't be alternatives in the future. It's really if all the ships that are on order or on the water today were to run 100% on methanol, it would be 2 million in demand.
Got it. Very helpful. Thank you.
The next question is from Jacob Bout with CIBC. Your line is open.
Good morning. Wanted to go back to
Hi, Jacob.
Yeah. Wanted to go back to methanol demand and, you know, increasing concern about a recession here going into 2023. Maybe just walk us through how you're thinking about methanol demand in either kind of a moderate or severe recession scenario and what, you know, could be different this time than what we've seen historically.
Sure. I think you know, when you break out the demand in the industry, we're kind of somewhere between 85 million and 90 million tons. Around 45 million of that is in the traditional demand segment. That would be the segment we'd be monitoring very closely in terms of any recessionary impact. Right now we would have forecast at the beginning of this year a 3%-4% demand growth in for those derivatives, and we're seeing that trend flat today, as we talked about for the third quarter. We'd be watching that 45 million tons of demand and really looking at what impact that will have across the different jurisdictions. Knowing exactly or predicting exactly what the impact.
It tends to follow GDP, so however we would forecast GDP growth will tend to be how that segment is driven. You know, I think the other thing that we're seeing, though, is we're seeing potential recessionary impacts in a high energy price environment, and that tends to be a driver for demand growth for methanol. How those two things interplay will ultimately determine demand. We think that the high energy price environment certainly is a positive for supporting demand growth.
Are you more or less concerned about China this time around?
Well, we're watching China really closely. You know, I think the zero COVID has had an impact certainly on demand. What happens, you know, post the national Congress and around policies there will ultimately determine how that's gonna impact us. We're watching the China market very closely right now.
We're probably most concerned about the MTO. I mean, that's always been our biggest concern by the operating rates, although they're a little bit lower, they're still quite healthy. Again, that's something our team watches on a very regular basis.
I'll leave it there. Good luck to you, John Floren.
Thanks, Jacob.
The next question is from Hassan Ahmed with Alembic Global. Your line is open.
Morning, John, and congratulations.
Thanks.
John, a question around the demand. You know, just revisiting something you said earlier. I mean, obviously sequentially, you know, you guys talked about demand being flat, obviously a bit different from other commodities, you know, which has seen, you know, fair bit of destocking, you know, in some cases 10, 15, 20%. You know, can you chat a bit about inventory levels, where they are right now? You know, as more of these recession fears sort of spread through the market, is there a genuine concern around, you know, maybe heightened degrees of destocking?
Yeah. Hi, Hassan. This is Rich Sumner here. In terms of inventory levels, we saw flat demand during the quarter, but we did see industry operating rates pull back in the quarter by about 2%-3%. Overall, we saw actually a draw on inventories through the quarter. The production outages were mainly in Iran, where we saw outages across a number of plants. There were outages in North America. The European refinery units are operating at low rates. There were other issues, including our own turnarounds in Egypt and New Zealand.
Industry operating rates were actually balanced when we balanced out demand and production. We saw a draw during the quarter that was most pronounced in the import markets into China, where we see actually quite low inventory levels today. That obviously led to some strengthening in pricing in the China market during the quarter. We're seeing tight to balanced to tight inventory levels everywhere today.
Yeah, I think the dynamic, Hassan, is that, you know, as we get into Q4 and Q1, that those are traditionally the low end for the production because of gas diversion for heating and electricity in places like Iran. But the higher gas prices in North America impacted, you know, the supply in Q3. Obviously, prices of gas now have come down to around 56, which is, you know, somewhat a little bit more affordable if you're not hedged or fixed like we are.
Yeah.
You got the high cost curve in China, right? The coal price there, you know, setting a very high cost curve. Yeah, even if demand was to go down somewhat, I think there's, you know, the supply issues are gonna be probably more impacting what the ultimate price of methanol is gonna be versus somewhat of a drop in demand.
Very helpful. As a follow-up, you know, I noticed that sequentially, logistics costs were up around $12 million. Now, looking at sort of, you know, shipping rates coming down pretty hard, you know, should that be a nice tailwind for you guys as we think about Q4 and beyond?
Well, you know, this is one of our key competitive advantages, our integrated logistics. Yeah, you know, we paid more for fuel in when fuel was quite high. It's come down a little bit, and we're running methanol wherever we can on our ships as well. The tanker market, you know, if you look at what happened in the dry cargo market a few years ago, the tanker market didn't have the same reaction. It kept to be quite low. With what's happened in Russia and the supply chains and shipping days becoming much longer, the tanker market has gone up quite significantly. The rates in the tanker market, if you're not integrated like we are, and you're buying spot, you're paying double and sometimes more versus this time last year.
I'll remind you, about 35% of what we carry is on a backhaul basis. The rates we're getting for that would be quite a bit higher this year versus last year. I think our supply chain and our own shipping and integrated logistics is a key competitive advantage, not only to deliver product on time in the quality our customers want, but now that the shipping market looks to be in the tanker market quite strong going forward. With the further restrictions now in Europe, where Russian methanol and other clean petroleum products will not be allowed to be exported into Europe. Those supply chains are only going to get longer, and which will lead, we believe, to a tight tanker market for most of next year.
Very helpful. Thank you so much.
The next question is from Matthew Blair with TPH&Co. Your line is open.
Hey. Good morning. Could you talk about MTO economics currently? Is it fair to say that they're a little bit better than Q3 levels? What are your expectations for MTO operations in Q4 into 2023?
Yes. Hi, Matthew. MTO affordability, when we look at it on a straight ethylene propylene basis, is around $280 today, thereabout. It's below $300. What we've seen is a bit of a disassociation. That's in a high oil price environment. Traditionally, we'd see higher oil MTO affordability. There's been a little bit of disassociation from oil because of what's happening in their downstream. Some weaker demand into olefins market, combined with ample supply. That's something we're monitoring very closely. There's other factors that have to be at play for true economic operating decisions for the MTO units.
You'd have to look further downstream into what they're producing downstream, as well as the synergies that a lot of these units have with their other parts of their facilities. It's not a straight mathematical number that you can rely on in terms of their knowing their operating decisions. Today, we know that there's a few plants that aren't operating today, and that's been offset, as John said, with the startup of the 1.8 million ton plant in North China. As of today, we'd say operating rates for MTO are at around just under 80% operating rates. There's latent demand there. Hard for them to start up when inventories in China are really tight today.
At current pricing in China at $330 a ton, we're gonna watch and see, you know, what operating rates to expect. We would probably hold operating rates at levels at around 80% today and then watch decisions that will be made.
Great. Thanks for all the color. You also mentioned your ships are running on methanol whenever possible. What's the economic benefit there? What's the spread between methanol and, like, a low sulfur fuel oil or low sulfur diesel?
Yeah. Earlier in the year when oil pricing was well above $100 a barrel, we saw methanol on an energy equivalent basis being quite a bit more affordable than the other alternatives of marine gas oil or ultra-low sulfur fuel oil. There's probably a discount on an energy equivalent basis, about 20%-30%. We've seen those prices come down recently to where it's actually more on a fairly neutral level of pricing. Still looks attractive to be burning methanol against the alternatives.
Great. Thank you.
As a reminder, if you'd like to ask a question, that's star one on your telephone keypad. Our next question is from Chris Shaw with Monness, Crespi, Hardt & Co. Your line is open.
Yeah. Hi, good morning, everyone. How you doing?
Hey, Chris.
I have a longer term question around natural gas availability, both for, say, your current operating plants and any, I guess, potential future plants or expansions. You know, given what's you know, happened with Russian gas and the protracted conflict in Ukraine, you know, Europe's bringing in a lot more LNG and look like they're trying to expand their capacity to do so and store. I mean, do you see any shifts in, like, supplies where you are now again, or, you know, other places, you know, with maybe, you know, producers of natural gas looking to liquefy more and send it to Europe in the future? I mean, or is this actually something that's spurring probably more development, and you'll actually have better supplies?
Like, how do you see that, I don't know, four, five, 10 years down the line? How does this all play out?
I guess it depends on what your LNG price outlook forecast is. I mean, certainly if it's $30, $40, if that's your forecast, then it makes more sense to use gas to make LNG than making methanol. Unless you have a view of methanol price being $100 a ton, then you know, I don't think there'd be many new methanol plants being built if your alternative is $30-$40 LNG. You know, I don't know what the future is gonna hold for gas prices on LNG, but usually economics prevail, and it's a price that gets you a return on your capital employed above your cost of capital that people make investment decisions on. Certainly there's an abundance of gas around the world.
It's unfortunately today because of what's happened in Europe, it's not in the right place, and that's leading to dislocations on pricing. You know, I think when we look at the forward curves on gas in North America, you know, it's still in a $4-$5 range. There's lots of gas in North America that can be developed very economically at that $4-$5 range. Assuming past capital allocation and capital decisions are in the future, you would expect producers of gas to be investing in production if the demand is there at those kinds of prices. That's usually how commodities work, and I don't see anything that I've seen that changes that because of a short-term dislocation because of a war in Europe.
I guess North America is your only market then that has the excess gas to liquefy and send to Europe, right? I mean, New Zealand, Chile, Argentina, all those places, that'd be. If they had that much, that'd be a, probably a good problem to have, right?
Yeah. I don't think there's enough gas in Chile or, you know, Argentina today. I mean, maybe at some time as in the future, as the Neuquén gets developed, they'll develop an export LNG market. That's sometime in the future as they continue to develop the Neuquén Basin. New Zealand, certainly not enough gas, you know, and to think about an LNG plant. We have, you know, obviously Trinidad has LNG production and so does Egypt, but Egypt's gas outlook is only getting more and more favorable as it be, you know, wanting to become a regional hub for Cyprus and Israel gas, plus their additional gas that they're developing. You know, of all those regions, I would probably expect Egypt to be the most likely to develop more LNG capacity at some point in the future.
Oh, great. That's helpful. Thank you.
Our last question is from Steve Hansen with Raymond James. Your line is open.
Yeah, thanks. Just one quick follow-up. You know, if we think forward here 12 or 15 months, G3 is up and running full, which would be a great outcome. How are you gonna feel about capital allocation at that time? It might be too early to ask, but you know, if we think about the backdrop of very little incremental capacity being built over the next couple of years, you know, arguably the market will start to need it. At the same time, you're gonna have to play this off with your idea around returning cash to shareholders.
you know, I know you've got a strong focus on a balanced approach, but when a lot of that cash flow is flowing, I mean, are you going to be keen on adding new capacity again, or are you gonna be more tilted towards the returning cash side? Thanks.
Yeah, it's a great question. I'm glad you asked it. Yeah, you're right to point out, you know, at any methanol price around where we are today or even much lower, we're gonna generate a lot of cash as G3 comes up. We don't have any significant projects in the pipe today. I mean, G3 is gonna certainly satisfy our demand aspiration or supply aspiration growth, and we'll focus on getting Titan and Waitara Valley back up and running if we're able to secure additional gas, which, you know, will take some time. I think we'll have lots of cash to distribute, whether we invest a little bit in green methanol or other projects like that to be determined. I think that's somewhere post-G3, you know, one or two years at least.
You know, we do wanna grow in line with the market. Most of the questions today have been about demand, and we've seen very little demand growth overall since COVID-19. Really since 2020, we've seen basically very little demand growth. We don't need to grow if we wanna maintain our market share, and G3 is gonna more than satisfy our growth aspirations. You know, assuming it will come up and it will run well, we're convinced of that. You know, we've got a great commissioning team. It's been a great project. It's been a great executed project. There's nothing that leads us to believe it's not gonna commission well and run well.
We'll take the excess cash beyond maintenance capital and the dividend we have and buy back shares. That's our plan.
Okay. Great. Thanks, John. Appreciate it.
I'll add one thing that we do plan to retire the debt that's coming due as well, you know, $300 million. You know, retiring the debt and buying back shares.
No further questions at this time. I'll turn it over to John Floren for any closing remarks.
Yeah. Thank you for your questions and interest in our company. Before we close the call, I want to emphasize we produce an essential chemical building block, which is used in hundreds of consumer and industrial products. Methanol is also a cleaner burning fuel that has increasing demand as a marine fuel. We believe that the methanol industry has a positive outlook with growing demand and minimal new capacity additions. Our well-positioned asset portfolio generates meaningful cash flow across a range of methanol prices, which allows us to execute on our capital allocation priorities. We are well-positioned in this period of economic uncertainty with a strong balance sheet.
Our G3 project fully funded and coming online next year, which we'll expect to add approximately $250 million of EBITDA at $375 methanol price and $4 gas, which will significantly enhance our cash flow generation capability. We hope you'll join us in January when we'll update you on our fourth quarter results. Thank you.
Ladies and gentlemen, this concludes today's conference call. Thank you for participating. You may now disconnect.