Methanex Corp (MEOH) 2016 Q3 法說會逐字稿

Welcome to the Methanex Corporation Q3 2016 earnings call. I would now like to turn the conference over to Ms. Sandra Daycock, Director of Investor Relations. Please go ahead, Ms. Daycock.

Thank you. Good morning, ladies and gentlemen. Welcome to our third-quarter 2016 results conference call. Our 2016 third-quarter news release, Management's discussion and analysis, financial statements, and presentation slides summarizing the Q3 results can be accessed from the Reports tab of the Investor Relations page on our website at www.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 conclusion or making the forecasts or projections which are included in the forward-looking information. Please refer to our third-quarter MD&A and to our 2015 annual report for more information.

I would also like to caution our listeners that any projections provided today regarding Methanex Corporation's future financial performance are effective as of today's date. It is not our policy to comment on or update this guide in between quarters.

For clarification, any references to revenue, EBITDA, cash flow, or income made in today's remarks reflect our 63.1% economic interest in the Atlas facility and our 50% interest in the Egypt facility. 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.

We report these non-GAAP measures in this way to make them 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?

Thank you. Good morning. Our financial results improved in the third quarter of 2016 due to a higher methanol pricing and record sales volume. During Q3, we recorded adjusted EBITDA of $74 million and an adjusted net loss of $1 million, or a $0.01 loss per share. This compares to adjusted EBITDA of $38 million and an adjusted net loss of $31 million, or a $0.34 loss per share, in Q2.

Our average realized price increase from $223 per tonne in Q2 to $236 per tonne in Q3. Sales of produced methanol increased from 1.69 million tonnes in Q2 to a Company record of 1.86 million tonnes in Q3, and our total sales volume in Q3 was just under 2.5 million tonnes, which is also a Company record.

Methanol prices began to trend upward late in the third quarter, which we believe is attributable to a number of factors. The cost of coal-based production in China increased due to the rising thermal coal prices and we now estimate the high end of the cost curve to be in the range of $240 to $260 per tonne. The cost curve is consistent with spot prices in China today, which are around $260 to $270 per tonne.

Further, a number of plant outages in the Middle East, Southeast Asia, and Trinidad contributed to a tightening of global supply. These factors, as well as strong demand, led to an increased contract prices across all regions in the quarter. Prices have continued to increase as we begin Q4.

Our posted price in Asia increased $25 a tonne in November to $310 per tonne, and in North America, our November posted price increased $26 a tonne to $319 per tonne. Our European price was adjusted upward EUR10 per tonne for Q4 to EUR250 per tonne.

Overall methanol demand growth was healthy in Q3. We estimate total Q3 demand at 16.8 million tonnes, representing a year-over-year industry demand growth rate of around 10%. Methanol to olefins, or MTO demand continued to lead growth, as the MTO plants operated at higher average operating rates of more than 80% in Q3, supported by positive cash margins.

We expect two more MTO plants to be completed in the coming months, and a third in 2017, with the three plants able to consume up to 4.5 million tonnes of methanol based on their announced capacity.

Chemical demand was also strong in the quarter, as we saw solid demand from traditional chemical applications. Waterfront Shipping took delivery of two more 50,000 deadweight tonne vessels capable of running on methanol. The remaining seventh vessel is expected to be delivered in November.

Also during the quarter, Waterfront Shipping was nominated for Company of the Year for the 2016 Lloyd's List Global Shipping Awards. I'm proud to say that Waterfront was honored with the designation of Highly Commended in that award category in recognition of our investment in these clean-burning methanol dual fuel vessels and our leadership in the shipping industry.

Our plants continued to run well during the quarter and produced 1.75 million tonnes, down slightly from a record production of 1.77 million tonnes achieved in Q2. Our overall plant reliability remains much better than we've recorded in the past few years. In North America, our Geismar plants continue to operate at strong rates.

Our Medicine Hat facility was idled due to a technical issue during the quarter, which resulted in lost production of about 30,000 tonnes. We continue to be frustrated with the ongoing technical issues at this site, which is leading to lower production relative to capacity despite our significant capital investment over the past few years.

In New Zealand, our facilities ran at an annualized rate of 2.2 million tonnes, which is in an excellent performance and represents full operating rates based on current natural gas composition. Our Egypt facility continued to operate at reduced rates in Q3. The plant was taken off line for planned maintenance activities for approximately 40 days during the quarter.

We continue to expect the plant to be subject to gas restrictions in the near term, although the medium-term outlook for gas supply in the region is improving as activities progress to develop new reserves including the Zohr field. Since we started up this plant in 2011, we have experienced 55 plant cycles, which could lead to an additional technical issues over the coming months and years.

Our Chile plant produced 68,000 tonnes of methanol during the third quarter. The plant underwent planned maintenance for approximately 30 days and restarted in early August. We continue to make significant progress in securing additional gas supply for our Chile plant.

In July, we reached an agreement with our main gas supplier ENAP for additional gas supply through -- until May 2018, and we also amended and extended our gas supply agreement with GeoPark. Our combined gas supply commitments from these and other sources are expected to allow our 880,000 tonne Chile I facility to achieve an annual operating rate of approximately 60% of capacity on average through May 2018.

We continue to believe that increasing our Chile production represents our lowest capital cost growth opportunity. As further progress is made in lowering the cost of developing Chilean gas reserves, we are optimistic that additional competitively priced gas could become available in the near future. In Trinidad, we continued to experience gas restrictions of approximately 15% during Q3. We expect the rate of gas curtailments in Trinidad to remain in the order of roughly 15%.

We ended the quarter with $234 million in cash. Methanex's share of the cash, including our proportionate share of Egypt and Atlas cash, increased $5 million to $213 million during the quarter. At current Q4 contract prices, we expect cash generation, excluding any impact from working capital, to be more than sufficient to cover debt service requirements, our dividend, and maintenance capital, which we estimate at this time to be around $100 million from October 1 until the end of 2017.

The outlook for the fourth quarter is positive. We expect higher average methanol prices in Q4 than in Q3 and production is expected to be similar to Q3. As a result, we expect EBITDA to be higher in Q4 2016 compared to Q3. I would now be happy to respond to any questions.

(Operator Instructions)

The first question is from Jacob Bout of CIBC. Please go ahead.

Good afternoon. I had a few questions around the Geismar, or the G1 renegotiation. Is there any fees associated with that, and as it stands right now, is there any price participation for that contract?

There's no fees associated with the assignment of the contract, if that was the question.

Was there a break fee or anything like that?

We're not involved in -- we don't know the details, if there was a break fee between the two negotiating parties. Certainly, we didn't have to pay any additional fees. We had to apply our consent for that contract to be assigned, which we did, in exchange for some benefits for Methanex, so as a result, our gas price today is slightly lower than it would have been under the old contract.

Okay. Does this change the guidance that you have given historically for how we should be thinking about natural gas costs for the overall Company?

Sure. About one-third of our gas today is not linked to methanol pricing so the previous guidance was about one-third sharing above certain methanol prices. It's probably more like one-quarter today.

Okay. But there was a base price previously, so you're saying the base price is unchanged, so I'm assuming that base price must be higher than areas where you [did] have that price participation?

As we said in release, the base price hasn't changed. We don't comment on individual gas contracts.

Maybe just as a second question here, just on Trinidad, we've been dealing with these gas curtailments for a long time, and it's not only you, it's the nitro producers and others in the area. How do you look at this longer term? Does it get any worse in your mind? How are you thinking about that?

Yes, there's some new developments coming on in Trinidad. The big one is the Juniper field that BP is bringing on. There's also some work on land to increase compression, so we would expect restrictions to be around 15% going forward with some improvement in the next 24 months, but until we see it, we're cautious.

All right. Thanks a lot, John.

Thanks, Jacob.

Thank you. The following question is from Steve Hansen of Raymond James. Please go ahead.

Yes, hi, John. Just a quick one on the concept of buybacks in the future. You suspended the buybacks some time ago on the depressed methanol price environment. It's obviously had a small uptick off the bottom. At what point will you guys be comfortable in reigniting the buyback program?

Well, nothing has really changed, Steve, to our strategy about cash distributions. Three uses of cash: growing the Company, dividend, and buying back shares. That hasn't changed. We have some unique opportunities, we think, in Chile to grow our business by another 1.5 million tonnes for roughly $100 million of capital over the coming years.

We have some privileged projects in Medicine Hat and Geismar that we're continuing to focus on. I don't think any significant capital spend on those in the coming 12 to 18 months, but we're continuing to spend some money there.

Our dividend, three pillars, sustainable, growing, and meaningful. It's certainly meaningful today. It's sustainable as we've proven at the bottom end of the cycle, and we didn't grow it this year. So we will continue to look at the dividend.

Any excess cash beyond that we'll use for share buybacks. That looks pretty attractive in today's market. We're trading at around $550 a tonne of capacity, so share buybacks look, for us, pretty attractive in the current situation.

Okay. Helpful. And then just on the Chilean gas then, it does strike me as well that, that's a low-cost opportunity for you guys, but can you give us a sense for how much lower the gas price needs to whittle down before you get the confidence to execute on that next layer of contracts for the first plant, and then secondarily for the additional plant that's still idle?

We're pretty happy with the gas price right now so it doesn't to have whittle down any more. It's more of supply. We believe there's enough gas that's been developed and available, excluding Argentina, for a one-plant operation, so for quite some time, there's more development.

I was just down there last week and there's a lot of exciting things happening in the basin. We're really optimistic that we'll see more gas for a second plant. So it just has to be developed and the economics are looking quite favorable.

Okay. That's it for me. Thanks, guys.

Thank you. The following question is from Hassan Ahmed of Alembic Global. Please go ahead.

Morning, John. John, reading through the press release, you talked about 10% annualized demand growth year-on-year. Obviously, an impressive number. Again, in there you talked about how, beyond MTO, conventional methanol demand was looking quite good, as well. Just trying to get a sense, acetic, formaldehyde, and the like, are they trending above normal, typical 3% demand growth that historically you have seen?

When we look at the demand growth Q3-over-Q3, 12-month period with a 10% growth rate, the traditional chemical derivatives grew at 5% in that period, which is quite strong. And then the--

Very good.

The non-traditional energy were 19%, so when you combine them together, we saw 10%, which is quite healthy.

Yes, big number, absolutely. Now, shifting gears a bit, obviously we've seen some big moves up in coal prices, but it just seems that, depending on the grade of coal that you are using, you have seen some divergent pricing moves. So could you just give me a sense of, as you look at the cost curve, and you look at that big number in the cost curve that comprises of Chinese coal-based production, can you help me decipher between high grade versus low grade and how this divergent pricing movement will flow through in terms of cost curve, in terms of market pricing, and the like?

The high end of the cost curve today is still being made up by anthracite coal and natural gas. The anthracite coal hasn't moved to the same extent as thermal, and natural gas hasn't moved at all, and they tend to move with that price based on oil, which is $50, so we may see some increases there. We haven't seen anything yet.

But the Chinese have been pretty clear on what they're trying to do with their coal resource. Maybe they've overbaked it a little bit. Who knows. We will continue to monitor it, but certainly the cost curve has risen by about $40 in the past 60 to 90 days, so that's quite positive.

Super. Thank you, John.

(Operator Instructions)

The following question is from Joel Jackson of BMO Capital Markets. Please go ahead.

Hi, thanks. This is Milan on for Joel today. Just a question here. You talk about three MTO plants starting up through end of 2017. What's the outlook beyond that and is there another MTO wave to come? And if there is, how long does it typically take from, say, construction or decision to build one to actual ramp-up?

There's another wave on the books, but I would say, in the current environment, unlikely that a lot of those projects would go forward. Naphtha pricing has been quite low and hasn't even followed traditional ratios to oil. To build one of these, probably 18 to 24 months, something like that.

It depends on how big the complex is and all the associated derivatives and the tie-ins. Sometimes the easy part is the actual MTO facility, but it's all the other tie-ins to the methylene glycols, propylene oxides, et cetera, so we continue to have a long list that we watch on a regular basis. Beyond this first wave, you would have to see naphtha pricing and oil pricing adjust a little bit further before you see further investments.

Okay. Then can you help us understand the tax rate in the quarter? I remember some previous commentary talking about maybe the tax rates being a little wonky when prices are low or moving rapidly, but how do we model this going forward?

I will let Ian Cameron, our CFO, take a stab at that one.

In terms of taxes, as I said before in other calls, that when you get into these low earnings environments, you tend to get unusual tax rates, and a couple million dollars of taxes can have a huge impact on the rate. But the absolute number does not make a difference.

That could be caused by a whole bunch of things like foreign exchange, where the product is sold, things like that. So you will get unusual tax rates that will hit at low prices or low earnings levels. Structurally, when we think about a long-term price that's say, [$300 to $450], our guidance has been 20% to 25%, and that guidance is still valid.

Thank you.

The following question is from Laurence Alexander of Jefferies. Please go ahead.

Good afternoon. Two questions. One is, can you give an update on the progress you made evaluating a possible site in Medicine Hat, and particularly, any possible government subsidies for such a project? And secondly, once the outages at competitors end what do you see keeping -- as the factors that will keep the Atlantic price above the Pacific price for the methanol contracts?

Sure. As far as Medicine Hat, we're anxiously awaiting decisions by the government, which we understand could come in the coming weeks, but we don't have a specific date. We think our project is exactly the kind of project that the government was looking for to invest in. Having said that, we don't have any inside information that we're going to be approved, but we're optimistic that we will get royalty subsidies for gas, so we're anxiously awaiting that and we're quite optimistic.

As far as basin balances, it's hard to predict how the industry is going to operate. If I look at the first two quarters of this year, the industry operated well above historical averages and the second two quarters, we're back to where we were historically.

Having said that, we normalize things, our view on the basin balance, premium in the Atlantic, would be around $10 to $20 a tonne. That's really as Middle Eastern product would prefer to flow to Asia as opposed to Europe or North America on average. That's what our current planning scenario looks like, and until we see different, that's what we'll continue to focus on.

Maybe if I can fit in a third, could you just give an update on your experience with the methanol fueled ships, what you're seeing in terms of, are they performing as expected?

Well, it's the first time anybody's done this and we've had a few small technical issues, but nothing major. It's only been a few months. We've run over 50 days with methanol, and we're quite excited about what we're seeing. Until we actually run a ship for six months to get the data that we -- confirming what we expect on emissions and efficiency, it's probably too early to comment beyond that.

But five of the six ships have boarded methanol and we take the seventh ship next month. So it's too really early, but we're quite excited to be doing this, and to introduce methanol as a fuel, not only for ferries, but now for ocean-going vessels.

Thank you.

Thank you. The following question is from John Roberts of UBS. Please go ahead.

Thank you. Could you give us an update on the global capacity addition outlook?

Sure. Iran is a little opaque, but we estimate, between now and 2019, about 4 million tonnes coming on in Iran. Besides that, we have a plant in the United States, somewhere late next year, early 2018, the nat gas project, and about 3 million to 4 million tonnes in China between now and 2019.

Then we've had both oil and Chinese coal move up during the quarter. If coal were to reverse, do you think oil has moved up enough to support prices roughly where we currently are, or do you think we would backtrack a fair amount if coal were to reverse in China?

I never like to predict price, John. We look at supply/demand balance, and we're quite pleased with the healthy demand growth that we're seeing. 10% year-over-year is quite solid. We've got another 4.5[%] coming, in the coming months, so we expect demand to continue to outstrip supply, which will lead to a market where high cost producers need to run in order to keep things balanced. What that leads to in price, I'm not going to go there.

Okay. All right, thank you.

Thank you. The following question is from Robert Kwan of RBC Capital Markets. Please go ahead.

Good morning. If I can just come back to Medicine Hat, and John, you referenced the outages that you had. I'm just wondering what you've had in Q2, Q3, were those related, or are they different issues? And ultimately how do we think about the run rates and the time to get the work done going forward?

One was related and one was unique. Both related to design, not to operations so really frustrating for us. We spent a lot of money to get that plant to run at high rates. You get a design issue from the original days of the plant, and that surfaced a couple of times, and now we have to find a more permanent solution, which is going to impact us. Until I see the plant running at high rates on a consistent basis, I will reserve my comments.

Is it a situation where you're still trying to work through what a fix might be, or do you know what it is and you just have to engineer it and get it put in place?

We unfortunately know what it is, and we've got a solution that we're implementing. The length of time is a little unclear at this point, but we have a solution.

Okay. My second question also relates to Medicine Hat. You benefited from lower Alberta gas prices. I'm just wondering, can you talk about where you are with the hedges for those plants in terms of the duration? And with that, are you taking a Corporate view on the hedging strategy going forward, just given some of the pipeline talks that may have -- that could have implications to narrow the Alberta basis against the rest of North America?

We're happy with where we're at right now with hedging. We've started to layer in a bit of gas for Medicine Hat in the 2020 period, so that's relatively new, but we're in the $2 to $3 range for hedges. We're pretty well covered for the next few years. Then as you get to 2018, 2019, one-half covered, or 60%, something like that. I can get you the exact numbers off line.

But we're pretty happy with where we're at, certainly for Geismar, where you shouldn't expect us to layer any more hedges in there at this point. We've got enough gas covered for 10 years that allow us to run those two plants at 70%, if the spot market does blow out. We've got sufficient pipeline capacity there so we're not worried about that. We do see Western Canadian gas continuing to be at a discount to US Henry Hub, so we might layer in a little bit more for 2020 at current pricing, which is below $2.50, but beyond that, we're pretty happy with where we're at.

That's great. Thanks very much, John.

(Operator Instructions)

The following question is from Cherilyn Radbourne of TD Securities. Please go ahead.

Thanks very much and good morning.

Good morning.

Most of my questions have been asked, but maybe I can get to you comment on the situation in Trinidad during Q3. What I'm driving at there is there had been speculations certainly in some of the industry publications that there might be greater than normal gas restrictions as a result of some platform work that was occurring but your plant seemed to have operated in line with the long-term guidance you've given regarding gas restrictions?

Don't always believe everything you read in an industry publication. Not all of it is accurate. They get information from a number of different sources. All we know is what we know about our operations. I wouldn't speculate about our competitor or the ammonia industry down there.

What we've been told is what we've been seeing, so we do expect to have about 15% restrictions, and that's what we've been experiencing. I can't really comment on others and their particular situation and whether their gas contracts expire. I don't know. I just know our situation.

Okay. That's fair. Then very quickly, how much importance to the industry do you think the upcoming decision on sulfur emissions from the IMO may have?

It's great news. They announced, I believe it was today or yesterday that the 0.5 sulfur limit will come into effect in 2020. There was some talk it might be 2025. Now that it's 2020, then shippers are going to have to do something quicker than they were thinking, and methanol is part of that solution.

People are still waiting to see how we do with our ships and our trials, but there's certainly a lot of interest and a lot of publication and press about methanol. It won't be the solution. It will be part of a solution. You will see probably some LNG. You will see low sulfur marine diesel, et cetera, but longer term we're very excited about the potential for methanol, especially as these tighter regulations -- not only on sulfur, but we would expect particulate matter and nitrogen also to be tighter in the future.

Methanol is a nice fuel to meet all those new requirements, as well as it's renewable. I know shipping companies are looking for fuels that over the long term could be made from renewable sources like CO2, like we're doing in Iceland, so there's a lot of exciting things about methanol as a fuel, and again, on a scale of one to 10, we're probably at step one. So we'll continue to monitor this, but that ruling is certainly going to be favorable for methanol versus 2025.

Great. Thank you. That's all for me.

Thank you. The following question is from Christopher Perrella of Bloomberg Intelligence. Please go ahead.

Thank you. On the capital spending, what are some of the growth projects or projects could you pull if the methanol environment or market improves in 2017?

I've mentioned earlier that the Chile projects for about $100 million, once we get comfortable with the gas situation being enough for two plants, you would expect us to spend $50 million in the next 24 months and another $50 million towards the end of the decade, if everything works out on the gas supply.

The Geismar 3 and the Medicine Hat 4 project, they're both looking to be projects that are better than brownfield, and much better than greenfield. We're awaiting the Alberta royalty decision, which, if it's positive, certainly puts that project even in a better position than we're looking at today.

For us, we would have to see a little higher pricing. We still believe the long-term price of methanol is well north of where we are today. But we'll continue to work on those projects. And it's not just the price of methanol, there's other things, transportation to the coast for the Medicine Hat plant, as well as being able to execute, i.e., construction labor is pretty tight in the US Gulf. It looks to be a little better in Alberta.

There's a number of different factors. It's just not methanol price. But we want to be in a position at the right time to execute on either or both those projects. We still believe to construct plants in the North American environment today, you're talking $1,000 a tonne.

So that's the kind of capital that you would be looking at, over $1 billion. We would like to have a partner, a partner that can bring gas and maybe take methanol, working on that, as well. So those two projects, we'll continue to work on, and at the appropriate time, when we have all these boxes checked, we'll execute.

All right, thank you.

Thank you. The following question is from Daniel Jester of Citibank. Please go ahead.

Good morning. When you have seen these outages that you mentioned in your press release in the Middle East, Southeast Asia, et cetera, have you seen the Chinese producers actually ramp up production rates? And maybe just any updated thoughts on the ability of the Chinese to flex capacity in periods when you see higher prices?

Time will tell on that one, Daniel. We continue to see a lot of imports into China. We continue to see, in the last two quarters, a fairly significant inventory drop, so the excess production or idle production has not anywhere been close to making up for what the production rates were in the first quarter of this year. So it's a watching space, but we haven't seen the ramp-up in Chinese production come anywhere close to compensate for what's been lost.

And you mentioned that you brought down some of your own inventories in the quarter by about 100,000 tonnes. Can you just comment where your inventory levels are today relative to normal?

We're quite comfortable where our inventory levels are. What we drew down was produced inventory. So where our inventories are today is where you should expect them to be. As we grow our sales, we might add some inventory, but we'll grow our sales in line with our production and our next increase in production will come from Chile, so stay tuned.

Thank you very much.

Thank you. The following question is from Steve Hansen of Raymond James. Please go ahead.

Oh, hi, John. Just want to circle back quickly on the Egypt plant. You made some reference to the plant being through 55 cycles at this point. Can you just explain what that means in terms of future maintenance dollars and how we should think about that going forward?

Thanks, Steve. These plants like to run at 100%. They're designed to run at 100%. I will remind you, at the front end, very high temperature, almost 1,000 degrees Celsius, so they like to be steady. When you have a plant cycle 55 times what does that mean?

Shut down, start up, lower the operating rate, sometimes a hard shutdown. Plants don't like that. It's difficult to predict the impact of that kind of operating structure on the technical and structure of the plant going forward. So just being cautious, saying that, until we see steady gas that allows us to line the plant up and run it at a steady rate, based on our previous experience with plants, we may run into some technical issues that we're not anticipating.

We haven't had a turnaround at that plant since it started up. We've been doing patchwork, I would say, and in a very difficult environment, through what's happened in the country. These plants are designed to run at full rates and come down every three to four years for a turnaround, and that certainly hasn't been our experience in Egypt.

Okay, much appreciated. Thanks.

Thank you. There are no further questions registered at this time. I would like to turn the meeting back over to Mr. Floren.

Thank you. We believe that we witnessed the bottom of the current methanol price cycle in Q2 of this year. We're committed to remaining focused on prudent cost management and maintaining a solid financial position as we navigate out of a challenging period for the methanol industry.

With our focus on safety and reliability, we have emerged a stronger Company with an outstanding asset portfolio. We're in an excellent position to generate strong cash flows for shareholders as the methanol price improves. Thank you for the interest in our Company.

The conference has now ended. Please disconnect your lines at this time. We thank you for your participation.