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Methanex Corp
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Good morning. My name is Chris, and I will be your conference operator today. At this time, I’d like to welcome everyone to the Methanex Corporation 2023 Second Quarter Results Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session. [Operator Instructions]
I’d now like to turn the conference call over to the Director of Investor Relations at Methanex, Ms. Sarah Herriott. Please go ahead, Ms. Herriott.
Good morning, everyone. Welcome to our second quarter 2023 results conference call. Our 2023 second 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 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 2023 MD&A and our 2022 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 reflects our 63.1% economic interest in the Atlas facility, 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 share-based compensation and the impact of certain items associated with specific identified events. These items are non-GAAP measures and ratios that do not have any standardized meaning prescribed by GAAP, and therefore, unlikely to be comparable to similar measures presented by other companies.
We report these non-GAAP measures in this way because we believe that they are a better measure of underlying operating performance and we encourage analysts covering the company to report their estimates in this manner.
I would now like to turn the call over to Methanex’s President and CEO, Mr. Rich Sumner for his comments and a question-and-answer period.
Thank you, Sarah, and good morning, everyone. We appreciate you joining us today as we discuss our second quarter 2023 results. For the second quarter, our average realized price of $338 per ton and produced sales of approximately 1.62 million tons generated adjusted EBITDA of $160 million and adjusted net income of $0.60 per share.
Adjusted EBITDA was lower in the second quarter compared to the first quarter, primarily due to a lower average realized price. The declines in the average realized price was driven by global methanol supply outpacing demand growth and lower global energy prices leading to a decrease in the methanol cost curve and methanol-toolefins affordability.
Methanol demand in the second quarter increased modestly compared to the first quarter of 2023, and we continue to monitor demand closely ongoing macroeconomic headwinds. Demand for traditional chemical applications, which represents 50% of global demand increased slightly compared to the first quarter, but remains at or slightly below 2022 demand.
This is mainly due to the slower than anticipated pace of economic recovery in China and the impact of inflation and resulting monetary policy actions on the rate of global industrial activity. Demand from energy related applications such as MTBE and fuel blending increased during the second quarter driven by improved mobility in China, as well as continued cost competitiveness in methanol.
MTO operating rates also improved slightly compared to the first quarter when a number of units undertook outages. Although MTO affordability remains under meaningful pressure as a result of low – continued low olefins pricing. On the supply side, methanol production from China and Iran faced natural gas restrictions in the first quarter, increased steadily throughout the second quarter, and strong operating rates in other regions led to global methanol supply, outpacing demand growth and higher global inventory levels.
Declining coal pricing in China in the second quarter also put some pressure on the methanol cost curve with coal prices moving from over RMB1,000 per ton levels to approximately RMB850 per ton currently. We estimate the industry cost curve based on the marginal coal producer cost in China to be approximately $260 to $280 per metric ton.
During the second quarter of 2023, our global average realized price was $338 per metric ton compared to $371 per metric ton for the first quarter. The declining spot prices in the second quarter, primarily in China, led to a higher discount rate of 25%. Our August posted prices in North America, Asia Pacific, and China were posted at $516, $315 and $305 per metric ton respectively, and our third quarter European price was posted at €395 per metric ton. Based on our July and August posted prices, we estimate our global average realized price to be approximately $290 to $300 per metric ton for these two months.
Turning to the emerging marine fuel demand. Announcements from the shipping industry for new dual fuel vessels continue to accelerate. In the second quarter, Maersk announced a further 17 ships and Evergreen ordered 24 dual fuel container ships. In addition to these new build orders, we are now seeing growing interest in dual fuel retrofits with Seaspan announcing to retrofit 15 vessels. By 2028, we now estimate approximately 200 dual fuel methanol ships on the water with potential demand of over 6 million tons per year, which is an increase of around 2 million tons per year compared with the demand number I reported at the end of the first quarter. We ended the second quarter in a strong financial position with approximately $600 million of cash and $300 million of undrawn backup liquidity. We continue to carefully manage the balance sheet and our current cash position allows us to operate the business with all remaining G3 spend fully funded.
With continued macroeconomic uncertainty and the impact of declining methanol prices through the second quarter, we ceased share repurchases under the normal course issuer bid, which expires in September 2023. Our intent remains to repay rather than refinance the $300 million bond due at the end of 2024, and under current market conditions and pricing levels, we will be prioritizing excess cash towards this repayment.
Construction of our G3 project is progressing safely on time and on budget with production expected in the fourth quarter of this year. Overall, the G3 project is around 90% complete. The project team remains focused on safely and – on safety and delivering a high quality and reliable plant. The expected G3 capital spend remains unchanged at $1.25 billion to $1.3 billion, and the remaining $240 million to $290 million of cash expenditures, including $65 million in accounts payable is fully funded with cash on hand.
Looking ahead to the third quarter of 2023, we are expecting lower adjusted EBITDA compared with the second quarter as we expect to realize a lower methanol price and have lower production with seasonal gas restrictions in Chile and a turnaround schedule in New Zealand. Our overall production guidance for the year of 6.5 million metric tons of equity production, excluding G3 remains unchanged.
We remain focused on delivering strong operational results from our existing assets and completing the G3 project safely on time and on budget. We are well positioned during this period of economic uncertainty with growing cash flow generation capability from G3 and a portfolio of assets that can generate cash flow across a wide range of methanol prices.
We would now be happy to answer questions.
Thank you. [Operator Instructions] First question is from Jacob Bout with CIBC. Your line is open.
Good morning.
Good morning, Jacob.
I had a question on the discount rate, a little more than what we had expected and you’re indicating that the spot market in China declined a little faster than you thought. Given the recent improvements that we’ve seen there, does this mean that we see improve – some improvement in the back half of the year?
Yes. I mean, where we – what I’d say is we’ve got – we’ve given the guidance, we’ve seen some – we saw China pricing, I think move down into the two, kind of anywhere from 230 to 250 range, and we’re now back up to around 260 range today. What we – our guidance on a normal when the market is stable is the 21%. We’re giving you kind of where we sit today based on July and August, and incorporating all of the market conditions at 290 to 300, which I think is probably around a 22% to 24% discount for the third – based on those numbers for those months. So I think there’ll be slight improvement and we’ll just have to see how the market trends, but our deviation from the guidance of that, I guess, around 4% is not unusual from our guidance when we do see a move in the quarter where prices decline throughout the whole quarter.
Okay. And then just on the supply demand fundamentals for methanol, I think you were – in your commentary, you meant that – you noted that global methanol supply of pacing demand and leading to some higher inventory levels in the quarter. Just talk a bit about across regions how those inventory levels look and when do you see the market rebalancing?
Yes. I guess, from a pure inventory perspective, we saw really high operating rates outside of China, and what that meant is, I’d say the Atlantic markets are probably sitting on high inventories. Customers are not carrying a lot of inventory. Today, they’re managing things quite carefully, so we don’t think that there’s a lot of buildup from customers. It’s more the methanol producers that are carrying inventory.
China, we had a build, but I would say, China, the coastal inventory in China is still not well above historical norms by any means, but we have seen inventories outside of China, and what that’s meant is you’ve had that you’ve seen trade flows moving to different jurisdictions to find homes. So I would say, China has increased, but it’s probably just above kind of historical averages, whereas outside of China, because of high operating rates methanol producers are mainly carrying that inventory, not seeing consumers still carefully managing things given the economic situation we’re in today.
And then on the balancing question.
On the balancing, I would say, obviously this is a peak I would this – these summer months tend to be the peak operating period in our industry, where we see restrictions happening as we tend to – as we get into the third and – later in the third and into the fourth quarter, we tend to see operating rates come off naturally. And that’s something we see every year. So that combined with stronger demand, which is something we have to continue to watch, we think the balances would improve. But again, it’s going to be dependent on operating rates and the strength of demand.
Okay, thank you.
The next question is from Joel Jackson with BMO Capital Markets. Your line is open.
A few for me. I’ll just go one by one. Can you talk to me about we’ve – it’s come up before, but north American prices, both spots and host prices are really trading at really high levels versus other markets. Is that sustainable?
I think what’s happened, Joel, over time, is that through contracting, we’ve seen a big spread on discounts, just based discounts from customers. So you’re going to see a naturally, a larger discount in those markets from within our contracts. So naturally you’re gonna see a bigger disconnect between contract and spot, because ultimately you’re trying to target a competitive price a after considering discounts.
So, so yes, your observation’s correct there, we’re going to see a – it’s a bigger, it’s a bigger spread between contract and spot. Right now, what we’d say, we look at our realized pricing, we’re kind of guiding in that 290 to 300 for July and August off of our contract pricing, which again, is probably that 22% to 24%. So we’re not seeing our pricing going down all the way to where spot is trading globally. I think average spot globally is in that kind of 240 to 250 range, but we don’t expect to see that in our average realized pricing.
Okay. Second question. There’s been a lot of good headlines and it seems like progress on gas development in Argentina. Can you talk about that and where could we see maybe some legitimate upticks in some of your gas allocations, gas availability in Chile from that?
Sure. Yes, I agree with you. We – what we’re seeing is – it’s really the Neuquen Basin that’s being developed and in particular the Vaca Muerta field, where international oil companies have been developing that basin. It’s a prolific shale play. Understand that the economics are kind of similar to the Permian. So this is – and there’s a lot of gas there. What Argentina’s been working on is building pipeline connections into the grid to allow that gas to flow to help their balances, reminder Argentina’s importing on a per base load perspective, imports natural gas from Bolivia. And then during the winter months when they hit peak demand, they also have to rely on LNG imports to satisfy their energy needs.
So what they’ve been doing is building pipeline connections, one of the big ones just recently got tied in. We understand that that is kind of in anywhere from 10 million to 20 million cubic meters per day of gas flow. That represents anywhere from 10% to 20% of Argentina’s total gas demand. So that has the ability to really change the gas dynamics for the country. There’s development that’s happening in the middle of the country. There’s gas development happening in the [indiscernible] basin, which is – in the south, which is close to our plants, which is meant to come online at the end of 2024.
All of those dynamics point to the fact that they’re going to need new – they’re going to need markets for that gas. We are a natural market for that gas in the south assuming that the balances get developed and get tied in. So we’re optimistic. Right now, we don’t – I’m not going to give guide to the fact until we get progress. I’ll guide on upside to Chile. As of right now, we’re going to continue in earnest to have those discussions to contract more gas, and I think we’re very well positioned.
And finally, what would – like, what would permit you to restart the buyback? What do you need to see in the past your predecessor was talked about a minimum methanol price, maybe a liquidity buffer? You want to pay $300 million of debt down first. What would be the catalyst to restart the buyback?
So we are – we feel we’re in a very strong position from balance sheet perspective. That’s number one. We’ve got cash – enough cash to run the business. We’ve got G3 fully funded. We’ve – we have the intent to repay the $300 million bond, and under current market conditions, we would be focused on that.
Now, we – in the medium to long-term, we still see favorable industry dynamics for methanol, and we see a tight industry going forward demand outpacing supply, notwithstanding, we’ve got some near term I would call it near term headwinds to, to, to sort of gap through.
So in the medium to longer term, we’re quite, quite positive. And if we see more favorable industry dynamics, then we will be – we’ll be looking at our reviewing our cash generation, our capability of paid pay down debt, as well as start to think about share repurchase. So I’d say we’ll be somewhat market determined and in the medium term, we’re positive.
Thank you. The next question is from Nelson Ng with RBC Capital Markets. Your line is open.
Great, thanks. So just a quick follow up on Joel’s question on the restart of the NCIB. So just to clarify or just to, yes, clarify a little bit. I think in the past – I think, if you guys had call it $200 million to $300 million of cash on the balance sheet. And I think if you were fully funded with – fully funded on G3, you would allocate most of the cash flow to buybacks. So I guess going forward, if you’re finished with G3, if you’ve repaid the debt, and if you have, let’s say, $200 million to $300 million of cash on your balance sheet. Would that be a good environment to restart the NCIB?
No, I probably wouldn’t want to commit to that right now. I think our biggest thing under the current market is to protect the balance sheet where we are today, complete G3. Debt is the focus at today’s pricing levels, but certainly Nelson, if you look at our cash generation with G3 at mid-cycle pricing, we generate a lot of cash. So there – and I think what we need to do is get back to there before we start kind of committing to anything on the NCB – NCIB, but there’d be a lot of cash beyond $300 million debt. And we don’t foresee a lot of near-term capital expenditures.
Okay. Got it. The next question relates to methanol as a marine fuel. So you mentioned that by 2028, there’ll be about 200 dual fuel ships in the water. Roughly, how many are there today?
Today, we’ve got our 19 in the water, and then I think there’s another six methanol vessels or so, and then there’s a few other now in the water, because there’s under 30 today, something like that. And I could have my numbers wrong there. So it’s probably in the 30 to 35, something like that. And yeah, the remaining – it will to get to the 200, those are all going to be new builds and now retrofits to the period from now until 2028, most of those would be on the water in the 2027, 2028 timeframe.
Okay.
But the number, again, I think momentum continues on this and we do expect that that number will continue to grow. And we’ll continue to report how that that happens each, each quarter.
Okay, thanks. And then in terms of the ships in the water today, excluding your own ships like how do they currently run on the dual field? Do they still use mostly bunker field and methanol when they’re near the coast or how do they, like, what’s the typical pattern?
We’re burning methanol a 100% on our vessels today. We don’t know for sure, but one of the other vessels are also methanol vessels as well. So it’s – we would suspect that they’re burning a lot of methanol as well, because it’s very easy for us we’re – we load our fuel at the same time, we load our product. So that it becomes quite an easy bunkering situation. We would suspect that, our competitors doing something similar and the other vessels that are on the water are quite – are small. I think, Maersk just put their vessel on the water and they did a trial with green methanol, so we know that they’re interested in methanol, but they’re also looking at how they can fuel it with green methanol.
Okay, that’s great. Thanks for the clarification. I’ll leave it there.
Thanks.
The next question is from Hassan Ahmed with Alembic Global. Your line is open.
Good morning, Rich. Two part question. Hi there. Two part question on the near term and maybe medium term supply situation. On the near-term side of it, you guys obviously talked about Q1 to Q2 sort of incremental sort of production in Iran, but recently – I’ve been reading a fair number of articles about ridiculously hot temperatures over there, and again, some redirecting of natural gas away from the industrial consumers to the residential consumers. So near-term wise in Q3, what do you see as a supply situation in Iran? And then continuing with the supply side of it, again, in the press, I’ve been reading some rumblings about China sort of forcing non-money making, chemical production capacities to shut down some inefficient facilities, chemical facilities to shut down. Are you seeing that on the methanol side as well?
Sure. I’ll – so yes, on the Iranian question, I think your point is well taken that I think it’s not just Iran. We’re seeing this in a lot of jurisdictions right now with extreme weather causing a demand pull for natural gas for residential cooling or and industrial cooling. And what we do know is that in the first quarter, Iran first off is not always easy to get a full…
Yes, yes.
But we do see things through the shipping and imports statistics and whatnot. What we do know is in the first quarter they operate, our implied operating rate was less 50%. Through the second quarter, they got up to probably in the 60% to 70% range, which they have about 11 million or 12 million tons of capacity.
So a 10% increase is going to be in the 1 million to 1.5 million tons of annualized supply. That certainly was led to part of the shift on – in supply into the market. We would also say there’s some risk to them being able to maintain that given the dynamics you just described. And then the further out you get through Q3 and into Q4, there’ll be likely a shift as well away into cooling.
So they’re under meaningful pressure and we know that it is difficult for them to keep their gas system supply just because of investments in compression and gas reinvestments in gas fields that is really hard to do under sanctions environment. When you talk about – your question about China, it’s always, we have seen the shutdown of smaller scale plants. A lot of that has – we’ve seen that happen over time where their preference is to shut down lower inefficient plants and move and have things larger scale plants into industrial complexes where it’s more – much more efficient technology.
And that’s a lot about using both from an environmental perspective but also from an energy use perspective, they’re quite conscious of that and that is reflective in their policies around any new capacity that’s also approved. So in our forward view, we have capacity being added, but we netted off against shut down of smaller scale plants. So to your point, I think when we do see China capacity additions, they’re not as large because there is some rationalization happening.
Very helpful. And as a follow-up again kind of sticking to the weather side of things, but as it relates to natural gas this time around, obviously, we’ve seen extreme volatility in natural gas prices, be it within the U.S., I obviously know you guys aren’t out in Europe, but I mean global natural gas prices have seen far a much higher degree of volatility even LNG prices than ever before. So now as you’ve seen that I mean, has there been some sort of a rethink about your own sort of natural gas hedging program?
Right now when we’re – as you – I think you know what we’re doing, but North America is probably the one that we are actively managing all of our other contracts are on longer-term contracts with methanol sharing components. And we obviously each one of those has its unique characteristics.
For North America, we’re – we continue with our hedging program and right now, we’re well hedged into it in our targets for a three – and looking three-year period and looking beyond that as well. We’re going to continue to stay open to longer-term contracts on a fixed basis and if there’s ever any interest with doing sharing with producers in the U.S., we’d be interest. And so yes, we continue to – if we can get go longer, we’d like to go longer and it’s kind of it’s what we are doing as part of our gas strategy there. Well, we would look to get a base load at longer-term pricing if it’s available given that volatility.
Very helpful, Rich. Thank you so much.
The next question is from Steve Hansen with Raymond James. Your line is open.
Yes. Good morning, guys. Thanks for the time. First question, Rich is just I wanted to circle back to question earlier, I think Joel asked around spot contract spreads. Can you just give us a bit of a broader perspective here? So am I to interpret your comments to suggest the spot contract spreads will remain excessively wide for the foreseeable future or how should we think about that?
I’m just looking at the U.S. spread in particular as being something we’ve never seen. So I mean, how should we think about that from a longer-term perspective and what that means for your discount rates?
Yes. I think first and foremost, it’s just contractual discounts. Contractual discounts have gotten big. I think that’s the most important. Starting point is that contractual discounts have gotten big, contractual discounts are what gets us to our average realized price. Now you go into, what’s the further discount to spot? And as you know in North America is a heavily contracted market, it’s not a spot market.
So those limited volumes that trade on a spot basis are kind of not what’s used to set the market price. I think so yes, in terms of contract discounts, those have continued to grow. And that’s part of the – that is a big reason why you see that, that contract to spot number being so big is just because the base contract discount has changed.
There’s a further discount today because of where the spot market’s trading, and that is something that over time typically settles out. I think we’ve seen one of the highest operating rate quarters in North America on record this last quarter. They – the industry operated at well over 90% operating rates, which we’ve never seen before. So in those situations where maybe producers have under contracted, then you see there’d be a discount – a heavy further discount in the market. So I don’t think that’s long-term, I don’t think that’s structural, but those contract discounts are bigger. Does that helpful?
And can I just ask as a follow-up? That that’s a good helpful context – as a quick follow-up. What is it that’s driving the contractual discounts as being larger? Is it volumes coming in from other regions?
It’s the fact – yes, it’s the fact, Steve, over time that there’s been producers that have started up in North America. Obviously, there’s the – it’s very attractive to service domestic markets versus export markets. And so there’s been increasing competitiveness for marketers with consumers. And that has – and the main point of contract discussions is through competitive discounts, and that has meant larger discount spreads over time.
Got it.
So I remember when I was in North America discounts were quite maybe 15% lower than they are today as an example.
Interesting. Okay. No, that’s really good perspective. And just one quick follow-up for me is just on the G3 cadence, obviously you’re well advanced here. Q4 startup is just around the corner effectively. Is it still fair to assume that no major commercial volumes really to assume are shipped in Q4 or should we expect a little bit? How do you feel about I guess the timing of that Q4 startup and shipments?
I think where we would guide to is it impacting the market and through our sales in the – in 2024. So we’ll have an inventory bill through – yes, inventory bill, but before it really gets into our sales system, it’ll be in 2024.
Okay, very helpful. Appreciate that.
The next question is from Ben Isaacson with Scotiabank. Your line is open.
Great. Thank you, and good morning. Rich, I’d like to ask a multi-part question. I’m just trying to figure out why prices are where they are right now. You mentioned that China, or sorry, you mentioned that the marginal cost of production is 260 to 280, but in Europe the price is 220 and China, it’s below that in the U.S. it’s 230-ish. So are we seeing capacity closures right now?
How much does the cost curve matter? And as part of that, if you go back over the last kind of 10, 15 years, how much has met or what percentage of time has methanol been set by the cost curve versus set by affordability? And then just as a final part of that, we always think about what mid-cycle pricing and – but China seems to be trying to push coal prices lower for its power users. And obviously you guys are – or sorry, the methanol industry is in a little bit of a different boat than power, but how confident are we that we’re going to get back to that’s kind of 350-ish mid-cycle level in the future?
Okay. A lot to unpack. We’re all – okay, I’ll start with pricing and where we are today and how pricing is typically set. So certainly, the pricing in the industry is set by the marginal cost of production. That’s – and that I think is where we’ve been traditionally and continue to be there. As of today, we have pricing in China. Cost curve we said was 260 to 280. Pricing in China is on the low end of that cost curve.
And it’s probably around the 260 level. I think why is it lower and why is it pressured is because of the olefins market. We’ve got a marginal buyer there that’s under pressure with olefins pricing. So I would say that right now that, that there’s a blend of what’s driving the price in China, which is the price setter for the market, it’s probably a blend of the coal production cost plus the ability to purchase from the MTO sector, which is under pressure.
And there’s some I think pull there just because olefins pricing has been so low. So hopefully that answers that. And then when it comes to pricing outside of China, we’ve typically seen premiums outside of the China market, and that is where we see things today still, if you look at where China’s at 260, we are saying that our pricing for July, August, we’re going to realize 290 to 300, that implies a premium over that of around $30 a ton globally, that that move – has moved up or down depending on global supply demand in the market.
And we’ve seen that as high as 50 to 60 and as low as 10 to 30. So we’ve seen – that’s kind of what we’ve seen traditionally in terms of mid-cycle pricing – and mid-cycle pricing I guess we’ve seen like last 10 years, average realized prices of around $350 a ton. I don’t think it takes much to for us to get to a $350 realized price. It’s – as of today, I think we’re in a supply demand, supply outpacing demand. So high inventory levels we’ve had relatively weak and historically low olefins pricing.
I think coal – the coal price today can easily still support a $350 price. It’s been ranging between RMB800 and RMB900 and was well above a thousand for the last year and a half. And so coal pricing that is still historically high when you look on historical basis. Over the years, we generated $350 realized price. So I don’t see us having a hard, it being that far from where we are today but we have to see some more favorable things happen in the near-term.
Sure. And just on the – what percentage of time have we – has methanol kind of lived off the cost curve versus being priced based on affordability?
I think we’ve seen it be this blend for the last year, year to year and a half, but most previous to that, I would say, we’ve been pricing off the cost curve. There’s been times when olefins pricing and affordability is way strong, way higher on a relative basis than the marginal cost. And we saw methanol pricing much higher than the marginal cost of production. So I don’t know percentage wise, we’d have to probably get back to you, but it’s – yes, yes. It’s been a blend at different points. Yes.
And then just my follow-up, you mentioned that customers are not carrying inventory, given that prices are historically at a low right now, why do you think that is? Why wouldn’t they be kind of coming back in the market and restocking given where prices are? And you talked about an expectation that or you said in the summer, operating rates are generally high and we started to see problems as we get into the back half of the year that could cause pricing to go higher. So why aren’t customers restocking right now?
I think it just has to do with the general economic outlook and manufacturing output has not been real strong, and I think that’s the concern is that not withstanding we see economic numbers that look okay. When we look at what’s underneath those, a lot of that’s being driven by its consumer spending, but on services and maybe not on durable goods.
And I think that that has meant manufacturing output has not been as strong as we would’ve hoped. And I – if you look further down the value chain and talk to our customers and see how they’re talking about the current markets, you definitely pick up that they’re still concerned and they need to see the demand stronger.
That’s very helpful. Thanks so much.
The next question is from Laurence Alexander with Jefferies. Your line is open.
Hey, good morning, everyone. So this is actually Kevin Estok on for Laurence Alexander. Most of my questions have been asked, but I guess I was wondering if you could give us some updates or your thoughts on your strategy for green or blue methanol. That would be very helpful. Thank you.
Sure. So thanks, Kevin. We – I think when we think about our strategy, it’s three pronged. One is the demand side working with the – so our low carbon solutions team is really focused on three things right now. It’s working with the shipping industry. We’re in discussions with all major shipping companies on what their commitment on their decisions on vessels, but also how they’re thinking about their fuel choice.
The second thing is supporting the bunkering and infrastructure. So we’ve done a number of different things looking at we are the biggest methanol producer. We’ve got the biggest network in terms of methanol delivery and infrastructure. So we certainly want to play a role in how we can support getting that demand, that last mile to where it needs to be for the shipping industry.
And then the third part is looking at the supply and the feasibility of methanol as it relates to decarbonization. And so that that is – that area is what I would say is sort of doing in a number of different initiatives. One is the immediate one, which is feedstock looking at renewable natural gas and using new renewable natural gas to produce green methanol.
And we’ve done that already and are to continue to do that. So we’re active in the renewable natural gas market. The other is looking at carbon capture and storage. And we’re looking at that in Geismar because of the 45Q and support under the Inflation Reduction Act. And then the third prong is looking at green. And what I mean by that is green renewable hydrogen and CO2 as a direct feed into our existing plants.
And so we think that looking at opportunities we may have to actually directly feed the backend of our plant to give us an advantage over building a greenfield project. And so we’re looking at the technological feasibility of that as well as, which location would make the most sense based on government and census available. So we’re looking at it really from the demand side, the infrastructure side, and the supply side, and how we bring solutions to this potential quite significant market.
Great. Thank you very much.
The next question is from Matthew Blair with TPH. Your line is open.
Hey, good morning. Rich, could you talk about your growth capital outlook after you finished G3? What types of projects would you be interested in? And I guess, what are the chances that, that you would green light a potentially significant green methanol or some sort of renewable methanol project?
Yes. So I think I’ll start with sort of organic growth projects. I – G3 is really the focus today in cleaning that safely on time, on budget, and it positions us really well in the medium-term. We are obviously watching in industry growth and we want to continue to grow with the industry. And I do think we’re in a period where growth may be slower than what we had anticipated, but what we are going to do is we’re going to work to create the best opportunities for growth.
So that’ll mean we will be spending limited capital, but we want to look at the feasibility, commercial feasibility of what is our next best project to position for organic growth. I think timing of when we might do that will be market driven. And I think similar to what I said earlier, I think we would need to see some more favorable industry dynamics before we were to commit any major capital. So don’t see that happening in the next few years. Low carbon is a one that I’d say is a bit will be opportunistic driven because I think whatever we’re going to do in that space, because it is going to require – it’s going to require us working with an end market.
Likely what we would do in any case is have a partner or an off-taker or some type of meaningful de-risking if we’re going to put capital in just because it’s not going to be sort supported by pricing off of a normal methanol price. It will require premiums. Of course, we’ll try to – we would try to capitalize on any incentives available. But it’s really difficult to say at this point because I think the marine industry in particular would be the one that would likely make any big investment. If – and they’re really going through a period of discovery right now on methanol and what they want and how they want to solve that, that challenge and certainly that we’re going to be positioned to have those discussions. So it’s a little early to say what we might do and when. And – but I do think it’ll be opportunity-driven and we would want to really be working with partners.
Okay. Sounds good. And then could you discuss current MTO economics and operates versus like Q2 averages? And also are you expecting any new MTO capacity to startup in the next year or so?
Sure. So maybe just what’s happened this year, we had – there’s about 21 million to 22 million tons of capacity for MTO. Currently at 100% that’s methanol equivalent demand at 100% operating rates. During the first quarter, we had about 15 – 14 million to 15 million tons of demand.
And during the second quarter, we had about 15 million to 16 million tons of demand. So I think you’re in a range at around 5% increase to 10% increase quarter-over-quarter. And that’s just based off, which plants we’re operating at what point in time.
As of today, the industry is operating at around 70% and it’s really two very large scale plants that are not operating today. And that’s the plant [indiscernible] and they represent 4 million to 5 million tons of methanol demand that is latent today and not operating. So that, that’s kind of where every all the other MTO units are operating at relatively high rates. As it relates to affordability, we’ve got any – it all depends on their integrated downstream and what derivatives they go to. And so it’s a bit complicated. But I – what I would say is it ranges anywhere from low 200s to low 300s, right, in terms of affordability levels today. And that’s at what I would call very, very historically low olefins pricing relative to oil price environment we’re in.
Great. Thanks for your comments.
[Operator Instructions] The next question is from Josh Spector with UBS. Your line is open.
Yes. Hi, thanks for taking my question. I actually wanted to follow-up on MTO and specifically just think about kind of the 22 million tons that are out there and we know some of the firms are also building refineries and crackers and may try to link up their downstream units to that supply versus MTO and bypass that operation.
Is that something that you’re seeing at any meaningful scale, any feedback from customers so that when we think two years or three years from now of that 22 million tons, is there some of that that actually comes out of the market because you’re going to feed via another route?
Yes. So that, that’s a really great question and it’s actually goes to the two units that are down today because those are the two units that, that, that are down. And I can say that the – what those units did so the [indiscernible] unit, they built a mixed feed cracker, but they also built downstream.
So their intent was not to build and then shutdown MTO, it was to have a bigger downstream into EO. And – but what’s happened in the EO markets is those have been oversupplied because of lack of demand. And so they commissioned their new unit and they have yet to start up their MTO unit, but their full slate allows them to operate both. And that’s their stated intention is to operate both. But I think they’re waiting to see markets on and demand come back online.
The Shanghai [ph] unit, they did a refinery expansion and they also have a mixed feed cracker off their refinery. They’re going into aromatics and a whole bunch of other slate of materials. We believe it’s very economic. They’re commissioning their plant. And once they have everything commissioned, they will – they would bring online their MTO unit because again, it was a full slate, full value chain investment, not just to get to see G3. So both of those unit, both of those businesses are in the market talking about when they may be back in the market. So we don’t think long-term this is a shutoff of MTO.
No, I appreciate that. That’s really helpful. And just on the [indiscernible] plant, is that also an EGEO? So we’re waiting for EGEO and maybe the fibers market to improve? Is that the thing to watch?
No, it’s – no, they’re going into a whole bunch and I think we could take this offline, but they’re going down to a much broader set of end derivatives and we think it’s actually more a technical commissioning issue today than it is a market driven delay in startup.
Got it. No, really appreciate the color. Thanks.
There are no further questions at this time. I’ll turn it back over to Mr. Rich Sumner for any closing remarks.
Okay. Well, thank you for your questions and interest in our company. Looking forward, we’re well-positioned with our current asset portfolio and strong balance sheet. Our G3 project is fully funded, progressing safely on time and on budget, and we expect to be in production in the fourth quarter of this year. We hope you’ll join us in October when we update our third quarter results.
This concludes today’s conference call. You may now disconnect. Thank you.