Methanex Corp

TSX:MX

Earnings Call Transcript 2022-Q3

[Operator]

Ladies and gentlemen, thank you for standing by. Welcome to the Methanex Corporation Q3 2022 Earnings Call. I would now like to turn the conference call over to Ms. Sarah Herriott. Please go ahead, Ms. Herriott.

[Sarah Herriott, executive]

Good morning, everyone. Welcome to our third quarter 2022 results conference call. 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 conclusion or making the forecast 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 16% 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's President and CEO, Mr. John Floren, for his comments and a question-and-answer period.

[John Floren, executive]

Good morning. I hope that everyone is continuing to stay safe and healthy. This morning, we have Rich Sumner on the call, who would become our new President and CEO on January 1, 2023. It has been a privilege to serve as Methanex's President and CEO for the past 10 years, and 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. Then we will open up the call for questions. Our average realized price of $377 per tonne 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 tonnes 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 tonne. Our November posted prices remained healthy. North American prices remained flat at $585 per tonne, Asia Pacific and China prices remained flat at $410 per tonne and $395 per tonne, respectively. Our European contract price is set quarterly, and we decreased our fourth quarter 2022 price by EUR 45 per tonne to EUR 510 per tonne.

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 in the third quarter -- 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 tonnes today to 2 million tonnes of demand over the next few years.

Our production levels were lower in the third quarter compared to the second quarter due to 2 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 $580 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 I 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 IV 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 900 -- sorry, 0.9 million tonnes. In New Zealand, we completed a successful turnaround at Motunui 1, which we started in mid-September. Motunui 2 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 million and 1.3 million tonnes.

We had low levels of production from Egypt in the third quarter as we completed an extended planned turnaround. The timing of the turnaround enabled us to enter into an agreement to redirect and sell the plant 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 the process of restarting. We ended the third quarter in a strong financial position with approximately $890 million of cash, excluding noncontrolling 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 advantaged 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 at the end of the third quarter and expect approximately $450 million to $500 million remaining capital cost before capitalized interest, which is fully funded with cash on hand.

Our asset portfolio and cash flow generation capabilities 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 for 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 onetime 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 tonne 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, advantaged 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.

[Operator]

[Operator Instructions]

Our first question is from Joel Jackson with BMO Capital Markets.

[Joel Jackson, analyst]

I don't think you said -- I don't think you gave a production volume kind of forecast for Q4. Could you tell us what you think Q4 might look like versus Q3? And then also, a second part of that question would be, should we expect the gas resale benefits in Egypt to be, on a monthly basis, like a lot lower than the kind of the $17.5 million per month rate you got in Q3 in August and September because obviously, gas price has come down?

[John Floren, executive]

Yes. So [indiscernible], we realized all the benefit in Q3. So that was all realized in Q3. So that $35 million is all the benefit of redirecting that gas for LNG and obviously sharing with the government, et cetera. So it's based on selling prices through the 3-month period. As far as production, yes, it's 1.6 million tonnes for Q4 is our forecasted production.

[Joel Jackson, analyst]

So my next question is a fun one, are you ready? Okay. So John, during your tenure at Methanex, been a long time, but over the last decade or so, as CEO, what would you say is sort of the thing that you're most proud about? And what is the one that you'd say maybe the one that got away, the opportunity or something that got away?

[John Floren, executive]

Yes. 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. I think we had a lot of volatility during the time in the last 10 years. And I think we came out a stronger company as a result of the teamwork. So I don't want to go through all the things that got away, but certainly, lots of noise during the last 10 years.

[Operator]

The next question is from Ben Isaacson with Scotiabank.

[Ben Isaacson, analyst]

In other petrochemical chains, we've seen volume down 10%, 15% in Europe, similar in China, generally hanging in, 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. But 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? So is what you're seeing consistent with what we're seeing in other chemical chains? And if not, maybe can you just talk about real-time demand on a regional basis.

[John Floren, executive]

Yes, I'll ask Rich to answer that question.

[Rich Sumner, executive]

Ben. Yes, so you're right to say that it's not the same across all regions. So in the third quarter, we saw stronger demand in for -- this is mainly on the traditional side, stronger demand in North America. Part of that was return of operating rates for acetic acid producers. But we are seeing still healthy demand in North America. Things are pulling fairly strong there. And 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. And so that -- in that region, there's a bit of 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 0 COVID lockdowns and also a slowdown in housing there. So we're watching those things closely. But we haven't any region.

Europe is the one that we have seen some modest pullback. So 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. And 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.

And we would see that continuing with high energy pricing as well as some -- if COVID lockdowns continue to ease. So we're watching all markets right now, and things are still probably trending at Q3 levels.

[John Floren, executive]

Yes. And I'd just add the MTO, right, where we've added a new plant in Bohai. So that's new demand. And that's 1.7% at total rates. So -- 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.

[Ben Isaacson, analyst]

And then 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 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?

[John Floren, executive]

Yes. Both plants are running down, Ben. I think my remark was that full rates in the quarter, so that's our expectation. So we expect to be running both plants at full rates next year provided 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.

[Operator]

The next question is from Nelson Ng with RBC Capital Markets.

[Nelson Ng, analyst]

Congrats, John, on your upcoming retirement, and congrats to you, Rich, on your new role. So first question is, it sounds like Egypt was a special situation where you were able to use excess LNG capacity to divert gas. But can you talk about whether there's any other opportunities to resell gas or divert gas? Because I remember in New Zealand, recently, you agreed to reduce production to allocate more gas to power plants. But I'm -- can you just give us a bit of color on whether there's other opportunities in other regions to divert gas?

[John Floren, executive]

Yes. 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 4 years. And the conditions were that there was excess LNG capacity and a high price in Europe. So I mean -- but those are very unique conditions. Would those conditions happen at some point in the future? Well, it hasn't happened in the last 30 years, so who knows? But certainly, we're in the business of producing and selling methanol.

[Nelson Ng, analyst]

Okay. Got it. And 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% to 100% utilization? And then on the back of that, can you give us an update on your hedging position in North America?

[John Floren, executive]

Yes. So our hedging position hasn't changed during the quarter. We haven't added any hedges. So it remains unchanged. And yes, we plan to run G3 at full rates.

[Operator]

The next question is from Steve Hansen with Raymond James.

[Steven Hansen, analyst]

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 want to 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 '23 and perhaps beyond, just given the market dynamics you're seeing? Or how would you think about that spread going forward?

[John Floren, executive]

Yes, I'll ask Rich to answer that.

[Rich Sumner, executive]

Yes, this certainly has been a dynamic we've seen. We're in contract season now and it's just starting. So it's hard to give you guidance on that. Obviously, the Atlantic is where we've seen that, the spreads and 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 going to have to watch and see what happens. But we'll obviously go through that and we'll give guidance on where we see discount levels going forward.

[John Floren, executive]

Yes. I think it's why, I mean, we look at realized price, that was important. And I think the [indiscernible] base is still our best realized price throughout our company. So yes, spreads are certainly something people watch, but we look at realized price. So $377 is if I can take that for the next 10 years or Rich could take that for the next 10 years, I'm sure [indiscernible].

[Steven Hansen, analyst]

No, fair enough. That's helpful. And just maybe as a related question then because you've introduced this new China contract that sort of breaks apart the traditional [indiscernible] China combined contract. Maybe just could you speak to the benefit that you've seen from that and whether it's been effective from what you'd originally planned?

[Rich Sumner, executive]

Yes. I think probably the biggest benefit is that just the Asia Pacific region is -- as a whole is quite -- there's a lot of unique elements to it. So 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. So I think it's working well with our customers in those regions and helping us stay competitive on a monthly basis to those markets. So yes, it's working the way we would have hoped.

[John Floren, executive]

Yes. I think when we put APCP many years ago, the Iranian product wasn't only destined for China. And I think that dynamic has really changed the Chinese import market. So the traditional freight differential from China to the other parts of Asia changed as a result. So having the 2 prices, I think, allows us to stay more in tune with the different markets in Asia.

[Operator]

The next question is from Josh Spector with UBS.

[Joshua Spector, analyst]

So just a 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 Europe 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 arm opened up, is that something you could quickly switch to if it was advantageous for you to do that?

[John Floren, executive]

Well, we own 50% of that plant, we operate. So we have a partner there, and that's mainly the government. So any ideas we talk about with our partners and look at them. I'd say this is a unique opportunity for us because we are in a planned turnaround anyway, and we won't have another planned turnaround for probably 3, 4 years. So the dynamics would be different if we're operating fully versus a planned turnaround.

So 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. Yes, we did do something in New Zealand, but that was more as a need for the country needing the gas for electricity. So it was very different circumstances than what happened here in Egypt.

[Joshua Spector, analyst]

Okay. That's helpful. And just a follow-up on the methanol for fuel demand in the marine market. I mean you talked about the 2 million tonnes 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 on how that shakes out today versus how you're seeing that maybe shift over the next couple of years?

[Rich Sumner, executive]

So the 2 million number that we've provided is demand potential that assumes all those vessels run on methanol, 100% of the time. 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, it's clean burning attributes as well as its future pathway to low carbon. So 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 our ability to decarbonize over time. So all of that will have to play out. We think that, that 2 million tonnes is what's on order today, and there's order book continuing to increase over time.

[John Floren, executive]

I think regulations will continue to get tighter and tighter, and maybe some of the alternatives today won't be alternatives in the future. So 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.

[Operator]

The next question is from Jacob Bout with CIBC.

[Jacob Bout, analyst]

I wanted to go back to methanol demand and 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 could be different this time than what we've seen historically?

[Rich Sumner, executive]

So I think when you break out the demand in the industry, we're kind of somewhere between 85 million and 90 million tonnes 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% to 4% demand growth for those derivatives. And we're seeing that trend flat today as we talked about for the third quarter. So we're going to -- we'll be watching that 45 million tons of demand and really looking at what impact that will have across the different jurisdictions.

So 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. I think the other thing that we're seeing those -- we're seeing potential recessionary impacts in a high energy price environment, and that tends to be a driver for demand growth for methanol. So how those 2 things interplay will ultimately determine demand. So we think that the high energy price environment certainly is a positive for supporting demand growth.

[Jacob Bout, analyst]

And are you more or less concerned about China this time around?

[Rich Sumner, executive]

We're watching China really closely. I think that 0 COVID has had an impact certainly on demand. What happens post the national progress and around policies there will ultimately determine how that's going to impact us. So we're watching the China market very closely right now.

[John Floren, executive]

Yes. We're probably most concerned about the MTO. So 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. So again, that's something that our team watches on a very regular basis.

[Operator]

The next question is from Hassan Ahmed with Alembic Global.

[Hassan Ahmed, analyst]

John, a question around demand. Just revisiting something you said earlier. I mean, obviously, sequentially, you guys talked about demand being flat obviously a bit different from other commodities, which has seen, say, a bit of destocking, in some cases, 10%, 15%, 20%. Can you chat a bit about inventory levels, where they are right now as more of these recession, say, sort of spread through the market, is there a genuine concern around maybe heightened degrees of destocking?

[Rich Sumner, executive]

Hassan, this is Rich here. So I -- in terms of inventory levels, we saw flat demand during the quarter, but we saw quite a -- we did see industry operating rates pull back in the quarter by about 2% to 3%. So overall, we saw actually a draw on inventories through the quarter. That -- those 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, and there are other issues, including our own turnarounds in Egypt and New Zealand.

So industry operating rates were actually when we balance 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. So -- and that obviously led to some strengthening in pricing in the China market during the quarter. So we're seeing tight to balance the tight inventory levels everywhere today.

[John Floren, executive]

I think the dynamic, Hassan, is that as we get into Q4 and Q1, those are traditionally the low end for the production because of gas diversion for heating and electricity in places like Iran got the higher gas prices in North America impacted the supply in Q3. Obviously, prices of gas now have come down to around 5%, 6%, which is somewhat a little bit more affordable if you're not hedged or fixed like we are. So -- and then you've got the high cost curve in China, right? The coal price there setting a very high cost curve. So yes, even if demand was to go down somewhat. I think there's -- the supply issues are going to be probably more impacting what the ultimate price of methanol is going to be versus somewhat of a drop in demand.

[Hassan Ahmed, analyst]

Very helpful. And as a follow-up, I noticed that sequentially, logistics costs were up around $12 million. Now looking at sort of shipping rates coming down, coming down pretty hard, should that be a nice tailwind for you guys as we think about Q4 and beyond?

[John Floren, executive]

This is one of our key competitive advantage is our integrated logistics. And yes, we paid more for fuel. And 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. But the tanker market, 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. What's happened in Russia as the supply chains and shipping days becoming much longer, the tanker market has gone up quite significantly. So the rates of 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. So the rates we're getting for that would be quite a bit higher this year versus last year. So 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. And 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 only get longer and which will lead, we believe, to a tight tanker market for most of next year.

[Operator]

The next question is from Matthew Blair with TPH.

[Matthew Blair, analyst]

Could you talk about MTO economics currently? Is it fair to say that they're a little bit better than Q3 levels? And what are your expectations for MTO operates in Q4 into 2023?

[John Floren, executive]

Yes, Matthew. So MTO affordability, when we look at it on a straight ethylene propylene basis is around $280 today, thereabouts. It's below $300. What we've seen is a bit of a disassociation between -- that's in a high oil price environment, traditionally we'd see higher oil MTO affordability. So 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. So that's something we're monitoring very closely.

There's other factors that are at play for true economic operating decisions for the MTO units. You 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. So 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 start-up of the 1.8 million tonnes in North China.

So as of today, we'd say operating rates for MTO are around just under 80% operating rates. So there's latent demand there. Hard for them to start up when inventories in China are really tight today. And at current pricing in China, $330 a tonne, we're going to watch and see what operating rates to expect, but we would probably hold operating rates at levels at around 80% today and then watch the decisions that will be made.

[Matthew Blair, analyst]

Great. You also mentioned that 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?

[John Floren, executive]

Yes. So 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 diesel oil. There's probably a discount on an energy equivalent basis of about 20% to 30%. We've seen those prices come down recently to where it's actually more on a fairly neutral level of pricing. So still looks attractive to be burning methanol against the alternatives.

[Operator]

[Operator Instructions]

Our next question is from Chris Shaw with Monness Crespi.

[Christopher Shaw, analyst]

I have a longer-term question around natural gas availability, both for, say, your current operating plans and any, I guess, potential future plans or expansions. Given what's happened with the Russian gas and protracted conflict in Ukraine, Europe's bringing in a lot more LNG and look like they're trying to expand their capacity to do so and store. Do you see any shifts in like supplies where you are now, again, or other places with maybe 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, 4, 5, 10 years down the line? How does this all play out?

[John Floren, executive]

I guess it depends on what your LNG price forecast is. I mean, certainly, if it's $30, $40, if that's your forecast, that it makes more sense to use gas to make LNG than making ethanol, unless you have a view of methanol price being $800 a tonne, then I don't think there'll be many new methanol plants being built, if your alternative is $30 to $40 LNG. So I don't know what the future is going to 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.

And 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. But I think when we look at the forward curves on gas in North America, it's still in the $4 to $5 range. So there's lots of gas in North America that can be developed very economically, at that $4 to $5 range. So assuming past capital allocation and capital that's since -- or 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.

[Christopher Shaw, analyst]

And then I guess North America is your only market that has the excess gas to liquefied centers to Europe, right? I mean New Zealand, Chile, Argentina, all those places, if they had that much, that would be probably a good problem to have, right?

[John Floren, executive]

Yes. I don't think there's enough gas in Chile, Argentina today. I mean, maybe at some time in the future as the [ Neuquén ] gets developed, they'll develop an export LNG market, but that's sometime in the future as they continue to develop the [ Neuquén ] Basin. New Zealand certainly not enough gas to think about an LNG plant. We have, obviously, Trinidad has LNG production and so does Egypt, but Egypt's gas outlook is only getting more and more favorable as it wanting to become a regional hub for Cypress and Israel gas plus their additional gas that they're developing. So 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.

[Operator]

Our last question is from Steve Hansen with Raymond James.

[Steven Hansen, analyst]

Just one quick follow-up. If we think forward here, 12 or 15 months, G3 is up and running full, which would be a great outcome. How are you going to feel about capital allocation at that time? It might be too early to ask, but if we think about the backdrop there's very little incremental capacity being built over the next couple of years, arguably, the market will start to need it. But then at the same time, you're going to have to play this out with your idea around returning cash to shareholders. So 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 the capacity again? Or are you going to be more tilted towards the returning cash side?

[John Floren, executive]

Yes, it's a great question. I'm glad you asked it. Yes, you're right to point out at any methanol price around where we are today or even much lower, we're going to generate a lot of cash as G3 comes up. We don't have any significant projects in the pipe today. I mean, G3 is going to 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 will take some time. So 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.

But I think that's somewhere post G3 1 or 2 years at least. So we do want to 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. So it's really since 2020, we've seen basically very, very little demand growth. So we don't need to grow if we want to maintain our market share and G3 is going to more than satisfy our growth aspirations.

So assuming it will come up and it will run well. We're convinced of that. 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 going to commission well and run well. And we'll take the excess cash beyond maintenance capital and the dividend we have and buy back shares. That's our plan.

Just I'll add one thing that we do plan to retire the debt that's coming due as well, $300 million. So retiring the debt and buying back shares.

[Operator]

No further questions at this time. I'll turn it over to John Floren for any closing remarks.

[John Floren, executive]

Yes. 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 that's used in hundreds of consumer and industrial products. Methanol is also a cleaner burning fuel that has increasing demand as our 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 is 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.

[Operator]

Ladies and gentlemen, this concludes today's conference call. Thank you for participating. You may now disconnect.