Methanex Corp. (NASDAQ:MEOH)
Investor Day Conference Transcript
September 27, 2012 3:00 PM ET
Jason Chesko - Director, Investor Relations
Bruce Aitken - President and CEO
Michael Macdonald - SVP, Global Operations
John Floren - SVP, Global Marketing and Logistics
Paul Schiodtz - SVP, Latin America
Lisandro Rojas - Exploration Manager, E&P Business Line, ENAP Sipetrol
Tim Williams - VP, Upstream and Feedstock Acquisition
Ian Cameron - SVP, Corporate Development and CFO
Jacob Bout - CIBC World Markets
Charles Neivert - Dahlman Rose & Co.
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Thank you so much. Welcome to the [margin of product commercial] portion of the Medicine Hat Investor Conference. Also I want to welcome those who are listening in today by webcast.
Before we get started, I just wanted to provide a brief safety briefing about the hotel. So in the event of an emergency, where we would need to evacuate the building today, we would exit through the doors behind you, where we all entered and turn right and proceed to the front desk, and exit through the front doors. While some of the area would be in the open parking area in the front of the petrochemical station to the right of the hotel.
I’d also wanted to remind everybody that we are going to have forward-looking statements in both our presentation material and comments made in today’s remarks, and for more information you refer to the appendix.
So just a brief overview of today’s agenda, we have several members of our senior management team here. They are going to touch and highlight the key areas that the investment community is focused on in terms of the industry and our company.
We also have a guest speaker today, Lisandro Rojas, who is from Santiago, Chile. He works with ENAP Sipetrol and he will be giving us sort of a deeper dive into the Chile natural gas resource.
The presentations are expected to last about two and half hours. We’ll have a 15-minute break about halfway into it. And just a key point in track, we are going to have one Q&A session at the end of all of our presentation, which will last about 25 minutes. So I asked people to resume all of your questions for that time period.
So, with that, I’ll things over to our President and CEO, Bruce Aitken to first some introductory remarks.
Great. Thanks, Jason, and good afternoon, everyone. I hope you enjoyed your trip to the plant this morning. So as the main engineer, I know we’ve got lots of main engineers in the plant that probably are the most interesting plants in the world to visit that you don’t see anything going in the front and nothing coming up the back. But there is, you know there is a lot of stuff going on inside there.
But I think part of the value of coming to see a plant like Medicine Hat is you get to see and how we run our organization. And I think a lot of things that Bryan said in his introduction talking about Responsible Care and how important that is to us.
But, any successful chemical company that doesn’t pay lot of attention to environment, health and safety, if you don’t do that well, then you are -- you put in peril your success as an organization.
I think the efforts we make with people and a lot of the comments Bryan made around people. I think if you go into any Methanex site anywhere in the world, you’ll find the similar spirit, different cultures but similar spirit. I think another recent observation today is lots of the different accents from Trinidadian, the Kiwi, the Canadian and then there’s probably few others unless, we had some Chilean as well.
So Methanex is a little united nations. We are very active in moving people around the world, and this is all about continues improvement and making sure that we share lessons and share best practice. So I think some of things that I hope you got out of them today.
So I’ve just got a few little comments to set the stage. We’ve had the same strategy as a company now for 15 years and I think that’s appropriate, strategy is not something to change every year. We are very focus on being a global leader and I think we’ve achieved the leadership position in the methanol industry that delivers lots of value for us.
And I’m sure again if you custom and back the Bryan’s presentation earlier today, you see lot of the words that we use in our corporate strategy are also used in the manufacturing groups strategy.
And after that, what is our competitive advantage? Do we have the competitive advantage? And I think its, our flexible global supply chain, which -- and which has really explained in this chart. We are manufacturing in six different countries around the world. I’m counting Louisiana in that six as it’s just around the corner.
We have our shipping company with storage facility and spread over many countries around the world. So it’s our ability to move product from multiple production sites and multiple proto-sites to supply customers in every market around the world that I think is something is quite unique about our company and very difficult to duplicate.
I think we get value out of that by buying in the lowest cost countries and reselling in the higher cost countries or in the higher sales regions. We get value by having I think the best intelligence in this industry which enables us then to set methanol prices.
So John will cover this slide in a bit more detail, but at a high level demand continues to grow very robustly for methanol. This is a chart is prepared by CMAI, so 8% compound average growth rate over the next five years.
We are the 15 million tonne industry, so it implies 4 million tonnes of new supply is needed every year, that’s four [Wilscon] plants. And when we talk about supply anywhere in industry there is very little thing added on the supply side. And certain plants that we are heading into an environment of tight demand and supply which implies also high prices.
We are going to talk about most of things as we go through and various members of the senior team will discuss some of that. The big picture is that we are in positioning to grow our, double our production from the year 2010 through the 2014 and most of the places were in place to be able to achieve that.
As a company, we had very impressive line of earnings. We’ve never had negative earnings in the history of the company, 21 years that I’ve been with Methanex. We’ve always generated positive earnings and positive EBITDA.
Clearly, we suffered a lot during the financial crisis as most companies did, but I think the fact that we continue to generate positive earnings and continued all of our projects during that time was -- as system and about the robustness of our organization.
Really the decline in earnings from 2006 and 2007 more many things was been driven by the less of production in Chile and really that’s where we are starting climb out of that production halt today and as we talk about increase production going into 2013, ’14 and ’15, you will see those, our anticipation of much stronger earnings in the next few years.
And I think the equation of capital allocation is very typical subject that I hear a lot of chatter about in the investment community today, that our approach to it is that we are very committed to our dividend. We initiated the dividend back in 2001. We’ve increased it every year except for the year of the financial crisis. We anticipate as we continued to increase production levels, that we will be able to continue to improve our dividend payout. So that is one commitment that we’ve made.
We think it’s sustainable. We never even contemplated stopping or curtailing our dividend during the crisis. Again, this is something about how we run our company and the robustness of our balance sheet and the robustness of our organization.
We’ve bought back a lot of shares in the last 10 years. And so when we are thinking about buying back shares, there is an element of balance between growth and share buyback. So we’re always contemplating the projects that we have on hand and the opportunity to buyback shares.
So the opportunity today is to execute the projects that we are working on. As one example at Medicine Hat, we spent $50 million resetting that plant and today it’s generating over $100 million of EBITDA. So, clearly, I wish we had a whole lot more projects as good as that.
New Zealand is almost as good as that. The paybacks are a little longer that levered between one and two years, depending on your assumptions and the payback on the relocation project in Louisiana is three to four years, again depending on your assumptions around natural gas pricing and methanol prices.
So the projects that we are working on today I think have very strong returns and are very compelling. So as long as we have those sorts of opportunities, we are motivated to continue building our leadership position in this industry and you shouldn’t expect to see us buying back shares in the short-term.
But as we look forward, when we do our year three-year projections of cash flows, we are certainly positioned that we would be generating substantial cash flows over and above the level that we are spending to grow our company and we would anticipate as such being in a position to repurchase shares.
So, well, those -- I’ll leave you with those few comments. I will hand over to Michael to talk about global manufacturing.
I’ll try to keep it short. Thanks, Bruce, and hello to everyone as well. Just picking up on a comment that Bruce made in terms of sort of the global nature of our business, this morning those of you who were at the plant site met both Janice and [Bryan Robert Penny]. So Bryan moved up here last year and will be moving back to New Zealand at the end of this year and Bryan will take over the site leadership of our facilities in New Zealand and Cliff will become the site leader here.
So just another example in terms of how we think about our business. So it is global, we move people around and try to give people experience. They also grow their talent through that process.
The visit to the plant site this morning makes the slide a little bit easier to talk about. So what I wanted to do is just focus on the chemistry for a minute and link that into a lot of the demand for methanol as well.
So for those of you on the webcast, unfortunately you didn’t get to visit to the plant but two are included, look inside the furnace which runs around 900 degrees centigrade and then a visit to the compression facilities and also close look at the different vessels around the plant site.
And the thing that I would stress is that the underlying chemistry in methanol really hasn’t changed. So what we do is we take, in our case natural gas. We add an oxygen to the carbon and natural gas, and that helps us also make hydrogen, then we compress that and turn it into methanol and then purify the methanol.
So it sounds kind of simple. When you look at the equipment in the plant, there’s actually quite a lot of equipment there and one of tricks in methanol was about heat integration and we talked about that a little bit at the plant site.
But for those on the webcast, a lot of the equipment we have is in relation to recovering energy and recycling it, and that means both cheaper operations, but also a smaller environmental footprint and we are very focused on that as a company.
So all of Methanex’s methanol is made from natural gas and the main component in natural gas is methane, which has one carbon in it and methanol has one carbon. So it’s a lot of capital to start with one carbon and end with one carbon, but the chemical process to do that is actually little more complicated.
If you look at the derivatives that come from methanol, many of the technology, in fact most of the technologies that use methanol to make other derivatives are actually purposed, built and designed to use the methanol molecule.
And the reason for that is that methanol is a cooperative molecule and chemically it's relatively easy to separate the different components and difference parts of it, and end up with a very reactive CH2 molecule or CH2, so that species even and join together and make other things.
And that's one of the main growth drivers and methanol today in China is methanol-to-olefins and effectively all that technology does is takes a methanol molecule, strips out of water and then joins the carbons back together, and that's why methanol-to-olefins is popular. You can upgrade any raw material through methanol into olefins and you can be quite selective about the olefins that you make.
So if you look at the chemistry of making methanol, what we're really doing is converting some form of carbon into species that’s easily transportable, environmentally benign and easy to make into other things and that's why you don't see a lot of substitution in methanol demand.
So this morning, Bryan talked quite a lot about Responsible Care and safety and so forth. And I just wanted to touch on that for a moment as well. Responsible Care is a program that was initiated by the chemical industry and was largely in response to the Bhopal incident, which many of you may remember, quite a disaster, a lot of people died as a result of a chemical release.
And this was a voluntary program by the industry and was really about trying to improve the reputation of the chemical industry and I’d say at Methanex, we use Responsible Care as really the glue that holds a lot of our business operations together.
So it’s not just about health, safety, environment inside our plant, it’s about product steward shipment, that’s a large part of our industry leadership, and it’s also about how we interact with the communities that we have around our plants and also thinking about new demand growth to methanol, so all of those things come together under the umbrella of Responsible Care.
I think from a business perspective, we see Responsible Care is not just a sense but also an investment where we get a good return and the fundamentals of it, from running a business is relatively simple.
If we care for our people and our people care for each other, ultimately that translates into caring for our equipment and caring for our plants means that we have higher reliability, and reliability is one of the key components in terms of profitability in our business.
And so we see Responsible Care being part of our global approach to how do we mitigate risk. And starting at the ground level thinking about safety, the housekeeping of our plants, the relationships with the community is all critical to that. And just in terms of, as we think about, all of our plants obviously have operating permits and permits from the government and so forth.
Our real license to operate that comes from the communities in which we operate. And if we don't have the support of our community and you’ve seen that in some instances and other peoples operations around the world. If we don't have the support of the community and they will find a way of disrupting our operation. So Responsible Care is critical to us in many regards.
So just on the theme of Responsible Care, in terms of health safety of our people, we measure all sorts of incidence and over the long-term the frequency of incidence is the line on this chart. And you can see a long period show the continuous improvement.
And just to give an example, we’ve had a couple of recordable incidence so far this year and they relate to things like some cuts where we had to have stitches and we’ve had one broken bones so far this year. So not huge incidents but you read about it in the newspaper. We’ve taken seriously because there lies opportunities for us to learn from them and to improve and ultimately to continue improve our performance.
So we think about the environment as well. I’d say the line is really a trend of continuous improvement and you might argue that the last couple of years, we’ve seen a little uptick there. But the reality is the last couple of years we’ve gone from three operating sites to five operating sites. And so the actual frequency of incidents has stayed pretty low. So I think again you see, sort of a theme of continuous improvement there.
In terms of operating plants, one easy metric for us is around reliability. And this chart shows reliability as well as years. 2010 and 2011, the reliability was a little bit below what we were looking for and that would predominantly saw equipment values in Trinidad. So we had a significant value on Atlas in 2010 and some values on the smaller Titan plant last year.
You can see year-to-date, our reliability is running little over 98% for this year. So I think it’s a significant improvement and we have a focus on all of our sites in terms of how do we improve reliability. And I think Bryan in his opening comments this morning really captured it well. He said reliability isn’t necessary about fixing things. It’s about avoiding downtime in the first place.
So we put a lot of asset into understanding our potential points of failure and proactively dealing with those as oppose to writing and doing reactive maintenance. So lot of our maintenance work is really focused on condition of equipment and then predicting and anticipating where we might have issues.
So just a quick run down of all of our plants. I think people have all of the numbers here. The only comment I make in terms of the nameplate capacity is which the slide shows about -- suppose Atlas and Egypt, we show our equity interest there in terms of the numbers. And obviously, the arrow there is the relocation of the Chile II plant down to Louisiana. And Ian will talk about that in a little more detail later on.
So just going through each of the plants, and I will talk about each of the plants in turn. The chart here is both reliability of the individual plant and also the capacity utilization. And so in terms of generating income out of that plants, reliability is important but obviously, we need about to run the plant as well. And the chief thing that restricts our ability to use our capacity is raw materials.
So the first slide here is Chile and you can see over the time we’ve had a progress of decline in the availability of gas in Chile and that’s why we are putting focus today on both Paul and [Annette] talking to us about gas activity in Chile and so forth. But obviously there is an opportunity there to improve asset utilization in Chile and that’s part of the relocation rather than bringing gas to a plant in Chile, we’re taking one of the plants to the gas.
So moving now to Trinidad, good reliability and I’ve mentioned before the reliability improvement year-over-year in Trinidad, the main reason for the GAAP and asset, use a little capacity utilization in Trinidad this year. Obviously, we took a 30-plus stake outage in the first quarter on the Atlas plant. So that explains a big chunk of it and some of you have been reading about gas curtailments in Chile rather than in Trinidad.
So let me just spend a couple of moments talking about gas in Trinidad. Structurally, we feel that the gas is in Trinidad and that what we are seeing in terms of the near-term interruptions is largely response from BP and the Macondo incident in the U.S. Gulf. All around the world, BP is taking more conservative euros how they are running their assets and so lot of the feedstock shortfall in Trinidad is a result of BP platforms being up.
September, October this year, we actually have a convergence of two platform outages both in BP and BG. And so there are number of turnarounds that are being taken by some of our competitors in Trinidad in methanol and some of the other industrial uses. And those turnarounds haven’t quite offset the amount of shortfall in gas delivery. So that’s why you are seeing some ongoing interruptions. But it hasn’t caused us to take the plants down.
In terms of -- there are some commercial issues we feel in Trinidad as well that there is a slight mismatch in terms of why their gas is contracted to the government and why that the government contracts gas to the downstream. We’ll spend some time working with government. We think that government clearly understands it now. And I was in Trinidad a few weeks ago and I’m quite comfortable that there will be sensible solutions to return in Trinidad to more dependable gas delivery situation.
So moving to New Zealand, and Bruce is going to talk specifically about New Zealand. So I won’t dwell on the gas there. The reliability in New Zealand has been great and you can see there a little uptick in the capacity utilization. So that uptick was a restart of the Motunui I plant in July.
And the rest of the capacity utilization gap is able to close through a restart of the Waitara Valley plant and we are working on both gas and physical aspects of that right now and Bruce will speak a little bit more about that. And we also have some deep bottleneck potential in Montunui. So we feel quite positive about New Zealand and I’ll leave it to Bruce to tell the rest of the story there.
Here in Medicine Hat, we have a plant that’s actually running about its nameplate capacity. And I think Bruce teases us a little bit in terms of manufacturing, that sometimes we’re little conservative in some of our views. What we show is the nameplate capacity of Medicine Hat is what we assumed when we did the economics of the restart.
So we got an economic payback in Medicine Hat within the first year. It’s been a great investment for us not just because of the gas situation but because the plant came out as we expected and it’s operated pretty well since then. And we have managed to squeeze some capacity out of it. So that’s a credit to the operating group here. So thanks guys.
And I think it gives us a sense of comfort going for through the longer term. Now, Tim Williams will talk about North American Gas a little bit. We’re actually adding some people to the Medicine Hat organization because they’ve changed our view from an opportunistic short-term operation to a tenure operation. So we need to sort of design the organization a little bit different for that and also for the deep bottleneck.
I should say that Bryan spoke quite a lot about the deep bottleneck project and some of you on the site saw some bits of the metal distillation trend early on the site here. We have spent some money to buy that trend and to dismantle it. We haven’t yet sanctioned the final investment to make that instillation. You can see on the slide that the team is getting almost the job of getting ready to do that.
So the only other plant remaining is Egypt and I’m please to say that Egypt is up and running today. We’ve brought the plant up early in the week. We have seen for the last week or 10 days, nice stable gas pressure in the gas grid. So that’s a return to some sort of normality for us.
Obviously, I think Egypt is still going through a long period of uncertainty and there is no assurances around the reliability of the gas supply in the near-term. For the longer term in Egypt, we are quite comfortable about the gas deliverability in terms of gas being in the ground and that the amount of investment that’s going into the upstream sector on the whole gas grid and so forth in Egypt.
So I think for the longer term, we feel quite positive about the gas situation there. We also feel very positive that how we structure that business there. We’ve deliberately had the Egyptian government being a partner in the asset. We’ve deliberately done a gas contract with a share in the upside on the methanol price. And we’ve deliberately done local marketing through the Egyptian Ministry of Petroleum so that they have a stake. And the Egyptian government is actually coming to us now and recognizing their dependence on some important energy to understand how methanol can become part of energy metrics in Egypt.
So, I think the light that we’ve structured our interest in Egypt is to ultimately embed EMethanex, which is the joint venture in a value chain that takes natural gas and puts it to work for the Egyptian economy obviously with some flowing into international market as well flowing quite deliberately.
One other questions I get about Egypt is around the state of play politically then perhaps has just a statement on that. We are currently on our fourth Ministry of Petroleum since the revolution. So there have been a lot of change is in government. What we see increasingly is our -- is a government that understands the future of Egypt is dependent on foreign investment. If any of you read the Cleveland phone this morning present and more see was that United Nation yesterday and is clearly taking at this territory one of the -- I think the important thing for the international community heard was Egypt suspect for international relationships and the contracts that they have so actually give us a little bit of comfort as well.
So, I’ll stop at that point. I’ll be happy and take any questions in the Q&A session later on.
Thanks, Michael. So, I’m going to update on what we see on the supply and demand side of the business. Few slides in the beginning here about our position in the marketplace, which has been enhanced in the last couple years and I’m offsetting at the question, why do people buy from Methanex. And I’ve listed a few reasons here, but Bruce mentioned it, the number one reason is reliable quality supply.
So, we’ve never declared first measure. We’ve had our issues with our production. But we’ve always been able to maintain our contractual relationships with our customers and deliver the product when they needed and where they needed it.
At the same time, I think we’ve always looked at long-term relationships and we’re global in nature. We’ll be the only supplier that’s global. And as we’re growing our production base, many of our customers are also looking to grow their businesses and I think they are finding it more and more difficult to find quality reliable supply around the world. So there is a lot of interest in Methanex.
I think we something don’t talking enough about our advantage with our own shipping company. We have the world largest fleet of chemical tankers. We’ve really developed an expertise in moving not only methanol around the world but other third-party related products. So we have a group of highly skilled individuals that run this water front shipping company and over the years we’ve learned very quite a bit about doing backhaul as well as cleaning different products as we carry them.
So today, what we carry on in our shipping industry fleet, sorry, about 40% is non-methanol related. So we have tremendous opportunities to do backhaul cargos from different parts of the world as we are delivering our methanol in the Southeast Asia, North America et cetera. As most of you aware the shipping market in the last few years has been terrible so I think there is some hidden value here as a shipping market is cyclical like many other industries or commodity in nature. There is quite a bit value here that we can unlock as we continue to do these backhauls going forward.
Not to belabor the point but in marketing and logistics Responsible Care is extremely important to us as well. We used it as a differentiator so when we think about Responsible Care of course it’s handing the product. It’s when we take it over from Michael’s group play through to in it sold to the end consumer. So there is a lot of points along that.
I think Bryan mentioned this morning the biggest risk is when you are transferring methanol from one transportation form or terminal to a ship, to a railcar, to a truck. So we spend a lot of time. I’m trying to make sure we’re benchmarking, learning best practices around the world from people that do this with other chemicals and petroleum products.
It’s also very important going to get into quite a bit of up my presentation about energy applications from methanol going forward. So as methanol find its way closer and close to the consumer help and safety Responsible Care become very, very important. And in China in the latest five -- four, five year plan they mentioned specifically about promotion of health and safety so it’s really occlusive that to the growth of that market as well.
So, little bit about the industry I think Bruce mentioned it’s about a 51 million tonne industry. I remind you then we will look at the numbers. We don’t include the integrated coal to olefins plans so once that are producing methanol that are immediately turn into olefin so we exclude that, that’s about 5 to 6 million tonne today depending on those numbers you look at.
You can see the industry structure is quite nice. Few producers make up most to the production so that five or six making up the bulk of the production. On that slide you will see as well where the only one of those producers that are growing in any sense at all over the next two to three years. So we plan to enhance earlier ship position as we grow our production base and our sales base at the same time.
And I mentioned earlier we’re the only global company that can service global players in all markets. And we’re one of the -- we’re actually the only company to actually post prices as well in all markets around the world so we post prices in North America and Asia on a monthly basis and quarterly in Europe.
So traditionally methanol as you know as found its way into what we called chemical derivatives. So methanol is a building block chemical for -- see the gadget for melt a high methanol et cetera. Today, that market represents about 66% or two thirds of the global demand for methanol. You can go back 20 years and you can track the growth of that industry based on some sort of average between GDP and IP and that’s how that industry grows.
So as countries become more middle class, you see the consumption of methanol increasing in those countries quite rapidly as the people start to have apartments and televisions and furniture et cetera lot of stuff which methanol goes into. So these are the World Bank numbers here forecasting about 3.2% on a GDP. And then China is somewhere around 7.5% and certainly as what the numbers are today out of China.
So fairly I would say modest growth on the GDP side compared to what we’ve seen in the last in that 2000 anyway. So we certainly think China will continue to lead the growth and certainly some of the other big countries will be strong as well. And his slide just showing you how China is growing representing about 80% of the growth through the 2016 period and Asia will be about 70% of the global demand by 2016.
So I think you can see here in the Atlantic Basin more modest growth projection 1% to 2% and that creates a fairly interesting situation for the industry, most of the new production that will be coming on in the next period as in what we called the Atlantic Basin and most of the growth is coming in the Pacific Basin. So there is going to have to be this movement of molecules from the Atlantic through the Pacific Basin to keep the world balance.
Now, this is the arbitrage that we’ve been looking at so if you believe in higher oil prices $80, $90, $100 plus and you believe that gas is going to be so for some point in the future here in North America somewhere between $4 and $6 now this is the opportunity that we see in front of us. So Michael described it quite well as how methanol finds its way into the energy industry and methanol are really good way to transport energy. So I think a lot of the energy applications that we’ve seen and are involving is because of this spread so as arbitrage opportunity between low gas prices, high oil prices which really are mainly liquid fuels.
So these are the various energy applications that we see today. These are making up about one-third of the global for methanol and growing at double-digit. So you can see that traditional one is MTBE, which has been around for many, many years. Outside the United States, this product is growing quite rapidly for obtaining, for clean burning and especially in China.
You’ve seen some recent production start up in the United States and U.S. is still the largest producer of MTBE, but it’s all for export. So this product takes up about 5.5 million times of methanol demand today and is growing quite nicely.
Fuel blending is, I have a few slides on fuel blending but that’s been mainly a China story, but it is staring to expend outside of China. Dimethyl ether, two applications to replace propane as well as substitute for diesel, and one of the new ones that Michael mentioned as well as methanol-to-olefins and quite a bit more talk, again about methanol to gasoline, and we certainly pioneered that in New Zealand and that’s the reason the New Zealand transfer build, originally was to made gasoline.
So the Department of Energy conduct asked MIT to conduct the study because of all this abundant gas in the United States. What was the best way to use this gas from an energy perspective? And they came up with liquid fuels, the most efficient and inexpensive product to producer natural gas would be methanol. So methanol prices competitive with gasoline, it’s very attractive. It’s a liquid, efficient clean burning and really no technical barriers to implementation of methanol in the fuel pool.
So, I will just make a little trip here. What are the current standards on fuel blending around the world? I think China, we know we have an M-85 standard and M-100 standard and the ever elusive M-15 national standard that has been talked about since 2009. We had some people there this week and they are telling me end of this year, early next year but until I actually see it, I will reserve judgment on that.
In Europe, it’s been allowed in the pool there at 3% for quiet sometime. And in the U.S., there is this Open Fuel Standards Act that’s in front of congress, obviously with what was going on in the U.S. today we don’t expect any movement on this bill.
And depending on how, who wins the Presidency and who wins the house, whether they are actually going to get anything done in Washington or not is to be seen. But there is this build that’s in front of the house. Basically it says that you should allow any blend of methanol, ethanol and gasoline to be used in the fuel pool in the United States.
So the fuel blending, I’ll start. It’s really a China story and you can see here that the traditional chemical demand is the blue and the green is the energy demand and that’s mainly fuel blending in DME and China today. What’s driving this in China is certainly to be more self-sufficient with their own energy as well as to use there coal to create energy products in the country.
This is the map of the various provinces and the M stands for methanol and the number stand for the percent blend. So even though there’s no national standard for M-15, you can see there is number of different programs not only in the Inland provinces where there is quite an abundance of coal, but also in some of the costal provinces where there is different standards in place by the provinces to used methanol in the fuel pool.
And in the various provinces there is 15%, which you can blend without changing too much of the infrastructure and then some of the higher blends the M-85 and M-100. So you can see, despite a national standard there is still quite a bit of activity in China for methanol in the fuels.
Outside of China, there is a lot more activity, a lot more traction. We see Israel most recently have an M-15 demonstration on the way. They’ve recently found quite a bit of large gas reserve of there close to -- obviously they are looking to be more energy self-sufficient as well. So they have a trial, two year trial on M-15.
Pakistan is evaluating it. Iran is doing trials. I think most people were Iran and imposed quite a bit of gasoline and looking to used there own methanol that they are having difficulty in exporting more and more in the country. Australia has a fuel demonstration program underway and have some tax advantages for using methanol in the fuel versus gasoline.
The U.K., Holland and Iceland are blending today. I think I mentioned earlier that the EU allows up to 3% in the fuel pools. So this is strictly economics, this is strictly substituting gasoline with, I think sales for somewhere around $7, $6, $7 a gallon and you can buy methanol for a $25, so it is strictly an economic substitution.
I mentioned the Open Fuel Standard as well, and I think the EPA is also very involved in heavy-duty methanol engines. And there is quite a bit work being done in China on these heavy-duty methanol engines for large trucks and especially in the coal industry where there is quite a lot of trucks used.
And the Department Of Energy is also doing work on methanol, so there is quite a bit of activity in the U.S. Politically, it’s a different story, of course the ethanol lobby and the ethanol producers are very strong in the U.S. and our view is ethanol is our friend. It’s an alcohol fuel that behaves very similarly to methanol.
Methanol obviously is not the solution to energy problems around the world. There is just not enough production, but we think its part of the solution and I think working with other alcohol fuels to get them more widely accepted around the world is good for our business long-term. And then Trinidad has had and evaluating a fuel blending program as well as they import gasoline product as well. So it’s natural to have so much production in Trinidad to look out after the country.
Just a few slides about DME, so the original development of dimethyl-ether was for replacing propylene in spray cans, CFCs were banned. So they had to find something new and dimethyl-ether is what widely used today. Then, there was this program in China and basically the substitute for LPGs, mainly propane.
In China, there is lot of cylinders used for cooking and heating, and you can substitute the DME into that application against strictly economics at around 20%. You don’t have to change any of the burner tips or any of the infrastructure to do that. So you see quite a bit of blending up to about 3.5 to 4 million tonnes of methanol equivalent in China today for DME.
Up, and there is also ongoing trials with buses and fleets of trucks in China to replace diesel. I think some of you that might be in cities in Canada that have taxes that run on propane is very basic the same idea that used substitute gas or diesel with DME in the same type of applications.
In countries like Sweden, there is a full-blown trial starting from black liquor, which is a byproduct. Would you make pulp and paper right through to the end use of DME and trucks in filling stations on the road, so that is a so called green energy in play. So you can see DME finding its way in different countries as well.
And then today not being used, but you can use it for power generation as well. So as energy prices continued to rise in the future, DME can play a role in the power generation. Just a little bit of, how the demand has developed in China and this is really some of the milestones along the way. And China has got in there 12 year -- sorry the 12th five year plan to get up to 10 million tonnes of DME by the end of 2015, ’16, so we’ll see.
The newest one and the one that’s getting a lot of price is methanol-to-olefins. So you can see here I think I mentioned methanol is a 50 million tonne market. Olefins are over 216 million tonnes. So over four times the size of methanol. Half the world’s olefins today are made from naphtha, which usually trades pretty correlated to oil. So this is really about a substitution for naphtha-based olefins.
Michael also mentioned that when you make methanol from -- olefins from methanol that you can just make propylene or you can really target the ratio. Most people seem to want more propylene than ethylene because propylene is growing much quicker than ethylene, so you can just do propylene or target the ratio.
In addition, the only byproduct really is water. So if you are making olefins from naphtha, you do go a whole bunch of other products that you have to deal within the mix when you have to find markets to sell them into.
This plant here that’s on the screen now is the one -- the first one is going to come up that’s solely based on methanol. So in our nomenclature when we say methanol-to-olefins, they are starting with methanol as the raw material. When you heard coal-to-olefins, they are starting with coal through methanol right into the olefins.
This plant is on the coast and it’s going to be ready by the end of the year, and they are planning on consuming about 1.8 million tonnes of methanol. It takes about 3 tonnes of methanol to make a tonne of olefins, although have about 600,000 tonnes of olefins production.
The ethylene cost curve there I think is familiar to most of you and this is not our cost curve, this is a third-party cost curve and you can see there where the methanol from olefins would fall on the cost curve. So, obviously, ethane-based olefins are still there, that they are cheapest, but this can substitute nicely for naphtha-based olefins.
So it’s a little bit of a busy slide, but what I want to point out is where the projects are in China and the ones that are operating today versus the ones that are planned. As usual in China there’s a lot of announcements about production.
But the ones that we are tracking are the ones that are starting from methanol-to-olefins. A lot of those were on the coast, whether all these get built or not, who knows. This slide is really to show that there is a rapid growth.
I was just in China a couple weeks ago and met with three or four different companies looking for 2 million to 5 million tonnes of methanol to satisfy their needs for olefins production. Again, whether this all happens or not, we’ll wait and watch but the first one will be coming up here shortly, that’s on the coast.
There is one plant in Inner Mongolia today that is methanol-to-olefins. They are now starting with the coal. Also our experience in the other three that are integrated when they are not running their methanol plant, they continue to run their olefins and they do buy merchant methanol from time to time if their methanol plant is not able to run for whatever reasons. So this is clearly a game changer, if all of this production comes on because you are going to need a lot of methanol production to meet the additional demand.
One of the more interesting things, we’ve been working on in this energy space is methanol and DME on board ships. So there has been some new regulations past in this region of Northern Europe where there is certain restrictions on emissions from the ships. So more ships traditionally have burned bunker fuel, which gives us fairly high emissions. So there is the new regulations in this part of the world, indicate that their bunkers were no longer going to be able to be use unless you put expensive scrubbers on the ships. So that’s certainly one solution that’s very expensive.
Another solution is to use LNG onboard to feed into the engines and a third solution which we are working with the consortium of companies on, which is called the SPIRETH project is to test burning methanol right on board the ships or converting methanol to DME on the ships and into the engines.
If this is successful, there is a 40 million tonne equivalent methanol market. So you can see just by getting a small piece of it, you are having significant demand here for methanol going forward.
So that’s enough about demand. Let’s talk about a little bit about the supply side. So you can see that, grey box there is the demand growth projections. I think those are the CMAI numbers that Bruce mentioned and then these are the capacity additions that are coming on in the same periods and most of those are our projects.
So you can see what’s going to happen here to keep the world balanced, if this demand slide is right because you are going to have to have marginal producers mainly in China, operate at much higher rates to keep the world balanced. So that would infer higher cost producers that aren't running today, will have to run in order to keep the world balanced.
At the same time, it is an excellent opportunity for Methanex who’s bringing on additional low-cost supply in the same period to be able to take advantage of these dynamics.
This is the cost curve today. The top yellow line or yellow bar is really the energy equivalency price of methanol at around $100 oil and that’s somewhere between $380, $390 of tonne depending on what application you're going into.
And you can see an interesting dynamic in the commodity industry is most of the production that’s been built in the last few years has been actually built at the high end of the cost curve. Most times when new productions build, it’s a lower to mid end but a lot of the production that’s come on mainly in China is at the higher end of the cost curve.
In addition, you can see our plants there are in the middle range of the cost curve and we have a blend of what I would call low-cost to medium-cost plants in our chain today. I know when we started up Medicine Hat, we were thinking it was going to be a medium to medium-high cost and certainly that has proven to be a very low cost plant for us, especially because of logistics.
So what can go wrong? I have painted a fairly good picture for the methanol industry, but of course things never work out as you think there are going to. So when I put my hat on, I don’t think about what can go wrong.
I think the number one thing for us that where we watch all the time is the oil price. I mentioned the energy applications make up a third of demand today for methanol. A lot of them are marginal.
Let’s say $60 oil or less, not them all but some of them. So you wouldn't see, if you saw $60 or $50 or $60 oil, you wouldn’t see the rapid growth that’s being talked about in some of these applications. So that’s one thing we watched certainly coal prices.
Coal prices in China have come down. It seemed to have stabilized at around RMB700, which is the equivalent around US$110 per tonne. Remind you, it takes about 2.1 tonnes of coal to make a tonne of methanol.
So we watched the coal markets as well. You can read some analysts. They have very bearish outlooks for coal. Some say, we are probably at the bottom but you make your own decisions, but it is something that we watch.
Certainly we’ve seen that the current prices, a lot of the U.S. production shutdown in some of the exports have been curtailed as well. So that’s something we watch. If MTO doesn't develop at all, I think there is some of the demand that’s been talked about is not going to be there, which will make things a little bit more negative.
Industry legislation, trade barriers, I mean each country or regions seems to have its own economic challenges. We are a global company, we trade globally. So any trade barriers are bad for us and then geopolitical instability whether it would be in our own geographies that we operate in or others.
So those are the things that we certainly think about everyday. But there is going to be puts and takes. Some of the demand that we are thinking is going to happen probably won't, but there will be some of the things that we are not thinking that’s going to happen that will. I think, overall, the supply/demand dynamics in this industry, Bruce has been in it for 21, I have only been in it for 12.
I have never lined up quite as good as they are right now. Again, the future is hard to predict but I think the dynamics at least illustrate to us that we are in for a fairly healthy pricing environment in the methanol industry while we are bringing on significant low-cost capacity. Thank you.
Good. Thanks John and it pulls me to talk to you about New Zealand gas. We know we have Harvey Weake, our Senior Vice President of Asia Pacific here to talk about that but he is deeply engaged in negotiating gas contracts. I know you’ll be glad to hear that and we thought he was better occupied doing that than he was talking to you.
So just a reminder of assets, Michael has talked about this briefly. On the left hand side, on the Motunui side, we have two plants there. Both of them are operating today. It gives us about 1.5 million tonnes of capacity. We have the debottleneck projects that’s we are working on -- on that site, which gives another 200-odd thousand tonnes of capacity.
We are working hard on Waitara Valley side. The Waitara Valley is a twin plant to Medicine Hat. That was built by the Alberta Gas Chemicals. You would have seen them on one of the slides today. So Alberta Gas Chemicals were once a shareholder in the Waitara Valley plant. I’ll talk about gas availability, so you will understand the risk and opportunities around that.
Then finally, there is a little opportunity to get some high CO2 gas into our sites in New Zealand. And when we last operated in that capacity back in 2002, I think maybe 2003, we operated the entire facilities at 2.4 million tonnes. That’s the ultimate potential of the New Zealand site and I think we’re getting very optimistic about our ability to get back to that level of operation.
So I’ve seen a couple of interesting slides here on gas. The other line here is the reserve to production ratio for the country and there is a couple of interesting points there. It is on a trend in an upward direction, roughly about 15 years of -- 15, 16 years of gas into the future.
If you look back at 2003, that reserve to production ratio got down below 10 years. And there was certainly a concern in the country. I think completely unfounded but there was a concern that the country was generally running out of gas and we needed to preserve gas to generate our electricity. And there was no -- not really enough gas to run methanol. So that was the environment when we reduced really down to one final operation.
This is a different way of looking at the same thing. The hard blue lines here is the future supply outlook for gas over the next 10-odd years. If you look -- look at the black line, that’s what this line looks like back in 2007. So it’s very -- it is very typical and small countries with the gas market to have an outlook of 10-odd years, not the 10 years gas stuff before the gas supply starts to fall off. And it’s only when the shortage becomes more imminent that people then begin to drill and gets supply as restored.
You can see on the hard yellow -- that the yellow line there, that is demand, I guess, in New Zealand without any methanol operating. So pretty clear, you can see there is a big chunk of gas there that is available for methanol manufacture for a quite few years into the future. So what’s changed, I think our behaviors have been helpful. The New Zealand gas industry has been cozy adeptly for quite a long time.
And I think some of our activity is encouraging new participants and also in investing small amounts of earned money in the upstream have tended to change the dynamics and create more competition and more gas supply. So that’s good for us as a consumer.
One of the good things about gas in New Zealand is, it’s mostly quite condensate-rich. So when people are drilling well, they are not really looking for gas, they are looking for liquids. And in New Zealand, they typically find condensate-rich gas. Once they find that, they have excellent motivations to produce this quickly as possible. So they need a home for the gas and we are that home.
I’ll talk about some mature fields in our later slide. Now, electricity is also interesting. I was talking to someone at the lunch that if you go back five or six years, the view was the demand for natural gas into electricity would grow in New Zealand. What actually happened, the -- there has been a number of geothermal plants built and quite a little wind farms built that have really displaced the plans for new thermal generation.
So most of the new thermal generation that exist today is peaking capacity which only runs for virtual periods of time when peak demand about electricity. And they will sell that electricity at the very highest price. So of course, peaking plugs used a tiny amount of natural gas relative to base load that will generate this.
So in short what’s changed is the supply has increased and demand has gone down in New Zealand for natural gas. So I think we are in a very nice position of being able to secure a lot of that addition of gas. So that strategy has been in the short-term to secure contracts that allow us to spend a capital that we need to get our plants up and running again.
And in longer term, we still think about what do we do in next 15 to 20 years and I think continuing to spend a little bit of money in the upstream is the smart strategy. And we’ll talk a little more on that in some following slides.
I think the deal that -- I think both the dam for us was the Todd deal we announced at the beginning of this year. So first long-term contract we signed in New Zealand in the last 10 years. We’d been living off really short-term gas and being very successful in securing small quantities of short-term gas. The challenge with that was we were never confident enough to spend capital because we never knew how long our thoughts are going to last for.
Now, that we’ve got a 10-year gas supply, we have a much higher level of confidence that allows us to spend capital. We know that we can get that capital back and make a decent return on it.
So as we know that there is a slide here that certainly the second contract underpin the startup of the second plant in Motunui with some recent meetings with, for instance, Todd. I know Tim was engaged in those and they are pretty much on target in terms of their expectations. We’ve had some discussions with them around further gas availability.
Some interesting stories around some of the old fields, the Maui field was a very large gas field, that was 4 or 5 Tcf gas field that was spend originally in 1970s and was really the genesis of the plant that we currently own today in New Zealand.
There was real concerns that gas field was running out in the early part of 2000s. It’s an offshore gas field, runs at the platforms. It’s quite an expensive infrastructure facility. If you own a facility like that, your incentive is to get as much gas out as quickly as possible and then shut it down. As the years have gone by, the owner of that field has become more and more aggressive in terms of exploring for new gas in the license area and been extremely successful of that.
So when there was an expectation that Maui met well in 2008 and 2009, that today we are still contracting Maui gas probably into the next decade. So it looks the life of the Maui field is going to be considerably longer than anyone anticipated.
Kapuni is another interesting story. Kapuni was discovered in the 1950s. That’s been producing gas for a long, long time. It has a very flat and delivery profile. It’s a quite low-type gas in that field that model technology is having brought to bear. Shell is one of the partners of that field.
There is a lot of optimism around the ability to deliver tight gas from Kapuni. Kapuni is also the field with high CO2 gas. So we used to get deliveries of high CO2 from Kapuni when we were running at capacity back in early 2000s. So again the existence of more gas in that field, I think is good news for our ability to secure high CO2 gas.
Kupe is an interesting field that was developed just in the years before oil prices went up. I think it was committed when oil was still $20 a barrel and is a great consumer that really didn’t make any economic sense at all. While there is onside, the onus of that field led to huge amount of money instead of developing oil $20 a barrel, I will give you a $100 a barrel. That field is again very liquid reach but has a lot of gas. They’ve been continue to upgrading reserves in that field and again the only whom for those incremental reserves of natural gas are Methanex.
So, just a few colors around at friend’s Kea. We have a relationship with Kea Petroleum that’s a small company. Most of their businesses dedicated in New Zealand. There is a very complicated mix. I will do my best to explain it to you. Plants are right in the middle name. Often though we watch our valley and they run on the coast line and the blue line there is the coast line of New Zealand and this is a picture of all of the exploration blocks. You can see on the far left hand side, the red Maui field is very large offshore field and then Pohokura field which another probably 2 Tcf field very close to our plans. And belief there is a play that runs right Maui up through Pohokura. You see lot of onshore, where all the red lines are natural gas fields and there is a belief that it continues onto Maui back to Mauku.
All the green on this slide is acreages owned by or controlled by Kea. So, they have a preeminent position in onshore gas in this very prolific region. I think it’s our motivation here is to see some drilling appear on this acreage in the next two to three years. So, we feel those acreage that will give us the 20 year life for plans beyond that current gas contracts.
We have agreed in terms to share some cost through around drilling the well in Mauku and that’s due to occur in Q1 next year. And I think it will be interesting to see the results of that, because I think the success up there, we can anticipate a lot more success in the other key acreage that’s further to the south.
So, the short message here is that there is a lot of activity. There is a lot of natural gas in New Zealand, where we have the marginal consumer natural gas. We are making very good progress. We have two gas contracts that we are dealing with at the moment, one secured from the Pohokura field. We are in the final stages of agreeing the terms of that contract and are hopeful to announce something on that in the next couple weeks.
And then we have a gas contract from Maui that would really underpin the startup of the Waitara Valley plant. And again, I think within the next probably month or so we should be in a position to make some announcements on that.
So with those comments I think we are exactly on time. We are running 2:05. We have a short break for refreshment and snacks and we’ll be back to start at 2:20 in punto as they say in Chile, right on time. Thank you.
Good afternoon, ladies and gentlemen. It’s 2:20 and we’ll recommence Methanex investor conference. My name is Paul Schiodtz, Senior VP Latin America and it’s a pleasure to be here with you and with the attendees of the webcast. It’s also our pleasure to see the interest that our company generates.
We have decided to share this presentation on Chile feedstock with Lisandro Rojas, an ENAP’s exploration manager that I will introduce in a couple of minutes. The first significant data point that I want to share with you is a relevant increase in the E&P activity in the basin, which has been on an upward trend since 2006. As we see in the chart drilling activity was almost in existent in the middle of the previous decade and actually on the previous 10 years before that for that matter.
Three decisions I believe has spurred this increase. First ENAP’s willingness to compensate with indigenous production of Chile, the Argentine gas curtailments, second the entry of GeoPark as the first private producer of hydrocarbons in Chile. And third, the decision of the Chilean government to open and to actively seek new participants in the business. Levels of annual investment reached about $200 million last year and we expect they will remain at those levels in the foreseeable future.
One of the conclusions of the work performed so far is that the traditional, conventional resources that have been developed in the basin since 1940s will not be the solution by themselves to increase in gas supply. Hence unconventional hydrocarbons must play a role. Well, there are some positive indications so far that which Lisandro will focus in his presentation they still need to be assessed.
We have identified several prospects but we have label game changers that are differently placed geographically and geologically speaking are also different. So that means that we have our diversification of targets. So, we are not assuming success based on a single concept.
Beside the obviously geological challenge that we face in the basin, the devoutness of where we are placed bring some difficulties to bringing service companies and technical resources in general. Of course not all is negative. Chile -- offering in Chile for foreign investment is actually quite easy. Canada place of institute just rank Chile 10 out of 144 countries in their annual economic freedom report, which is a good proxy for ease of doing business.
Clearly 2013 will bring a better view of the potential of the basin so stay tune with us. I would like to introduce now, Lisandro Rojas. Lisandro is a geologist by trade from the University of Chile. He also has some astroscience in geology from the University of London and has been working at ENAP for over 20 years. He has become the exploration manager in 2005 with extensive experiencing in Egypt, Columbia, Ecuador, Argentina and Chile. Without further ado, Lisandro.
Good afternoon, everybody. I would like to thank Methanex for inviting me to present you the current Chilean situation and you will get our view and our future view on first half.
First, let me introduce you with a current situation. This is what’s happening these days. Magallanes basin is a mature basin we have been producing gas for more than 60 years. So it’s mature. We are dealing with the natural resource. So we are running out of these natural non-renewable resources.
Since 2007, we have the burden of supplying gas to Methanex together with GeoPark, because Argentina cut mega supply to Chile. So, we are the only providers to Methanex and that’s placing a local supplier as well. ENAP is obliged to provide gas to the cities as well and the cities are increasing the consumption year-by-year. They are increasing consumption about 2% to sometimes 5% per year consumption and this is really placing the gas supply.
We are obliged to provide gas to the city first then to Methanex because we are state owned company. We pull, short in this light that we have habit, lot of activity in the last year. We have been drilling trying to buy more gas however we have to realize that our recent discoveries done by ENAP, an American Energy base and Argentinian Company those operating Chile and GeoPark have been relatively modest in terms of size. Most of the recent discoveries are end to a few hundreds of Bcf reserves and each well is producing one to two Bcf per well as reserves and that is modest.
So, we are realizing that we are literally running out of conventional gas. However, we have very good 10 giga support to stay that we have a very interesting potentially unconventional gas that has been discovering the last few years. And I mean we have been developing this idea. So I -- in my presentation I will show you those ideas and the potential we are seeing for the incoming years.
We are not doing these by ourselves. There is the number of companies and institution that are working with us and I will name them in the presentation. This is a map of division. Most of the activity has been centered in the Eastern part of the basin close to Argentina. This is basin that is shared with Argentina as well. So, this is where most of our current operation is located.
This is Punta Arenas City. Methanex plan is Mauku and in a Seismic land you can see this is a shallower area and there is a much deeper basin to the west that has been barely explored in years mainly because exploring Maui basin has been very easy, oil was discovered in 1945. We’ve very mentally tools so we stick with that easy and cheap oil and gas.
So very little was done in this deeper part of the basin. Now that we are running out of fair conventional resources the shallower part, we are moving to this deeper part that has been overlooked in the past.
This is current map of operators. There is -- as I mentioned, there is a number of companies operating with us in the basin. ENAP is still operating the main gas fields and oil fields in the traditional part in the western part.
And we have as operator, GeoPark, that is operating, PetroMagallanes, a New Zealand company that arrived to the basin a few years ago is operating as well and Pan American Energy, a consortium by an Argentinian company and British Petroleum, plus number of other partners that are collaborating as well, Methanex is a partner as well, they have a share on some of these blocks, and Wintershall, Germany company came from the chemical BASF, and plus Pluspetrol, an Argentinian oil and gas company.
And as you can see most of the new blocks are located in this deeper part of the basin with much less exploring that is just developing. So what I’m going to show you is concentrated in this part of the basin, the deepest part, oh, sorry, I forgot to mention YPF as well. YPF has just recently entered into the basin as well.
In the seismic section, don’t worry I’m not going to bore, get you bore, we did geological diagram, just to explain you that and here is at about 2000 meters what the traditional reservoir in Magallanes bring information.
In the last few years we have been finding a lot of convention, sorry, a lot of small fields of conventional basin the shallower part that with what we have been doing in Dorado-Riquelme Block altogether with Methanex.
And we have found between the traditional reservoir and these other reservoir in number of unconventional plays that can be gas producers if they are well explored and developed. So I’m going to concentrate in these two areas. First, I’ll present you the deepest most one then a shallower one that is important.
This is a low cost, one typical well of the basin, as I mentioned you the typical reservoir Springhill just under -- in the lower part of the stratigraphic column. To go through Springhill we have to go through the source rock and it was very typical of finding a lot of gas in this source rock as usual.
So every time we went into Springhill, we found some gas in between where the source rock is. However, Springhill is such a good reservoir that there was no need to go for difficult reservoirs. So we concentrated in Springhill sandstone, not much was done for other more difficult reservoirs.
As we move to the deeper part of the basin, this easy nice reservoir is getting not that easy and that nice. It’s getting a poor reservoir. However, it’s -- because it’s by the size of the source rock, we found in the number of wells that still has a lot of gas in it, in spite of having a poor reservoir still hydrocarbon, a lot of hydrocarbon. So we have being developing a Tight Gas - Shale Gas plays in this area.
The best example that we have -- the best way we have is Lago Mercedes. Lago Mercedes is a well that was drilled in 1989. This well found the reservoir, Springhill reservoir with lower porosity, lower permeability.
However, it had lot of gas in it. It was tested and altogether with supply of the basin, we produced it up to 400,000-cubic meter per day of gas. And additionally and this is very interesting we produced it almost 400 cubic meters of condensate per day from the same unit.
Additionally to this reservoir, we found gas in a higher reservoir just 200 meters on top of this that produce some gas as well plus condensate. And additionally, once we went through the source rock there was a lot of gas shale in it.
So what our think is we have tight gas play, some reaching and shale gas play, so because they are very close to each other, we are talking about 300 meter column, they can be develop it all together.
These well, as I mentioned was drilled in 1989, at that time there was no such a thing as a gas prices, so there was no need to put it into production, unfortunately these well is located in a top part of Tierra del Fuego that is a little bit far away from infrastructure. This last month see that if as the gas discovered in non-commercial at that time, so it was put into production for a few years in order to recover condensate and gas was flared. It still hurts but it was flared for a few years.
As ENAP we drilled another two wells in 2005 and they were less, not that good producers and they were considered an economic gain, so we left them ready for production in nearer future. Now I can tell you that we have partnered it with YPF and we are planning to reenter these three wells, hopefully soon, this summer, hopefully, in order to test this possibility.
We are not just testing the reservoir, because we know for sure that at least Springhill is a quite decent reservoir and its very well producer. The idea is to test this interval plus other interval that can increase production. So we are expecting a kind of significant liquid rich production from these rocks. This is important thing. In this case we have proved production.
Additionally, this is important we have found roughly the same in other blocks. This is a section in Dorado-Riquelme Block, the block that we shared with Methanex and we are seeing similar situation.
There is a geological feature called Dorado normal fault, every well east of this fault present a conventional behavior, hydrocarbon, gas, oil plus water. However, as we move west to this fault what we are seeing is overpressured gas, condensate, no water, again the same situation in Lago Mercedes.
So what we are thinking is this Tight Gas - Shale Gas potential has much large extension than just Lago Mercedes. So again partnering with Methanex we are going to try these prospects very soon in Dorado-Riquelme.
As an example, one of the old wells drilled by ENAP tested 90,000-cubic meter per day of gas condensate by less considered and commercial at those times, those old times we had plenty of cheaper shallower gas. So in this case again we have not that good test as in Lago Mercedes but we have tested gas in the area.
It’s interesting to know that at the beginning we didn’t think of shale gas plain Magallanes because we thought our source rock was good enough that was, while we did using our historical data.
However, a few years ago an American company Chesapeake went to Magallanes and they propose us to study these new shale gas project our source rock. So they did a much better chemical analysis of our source rock that we have done.
They ended their study, however they left the basin because you all know whole Chesapeake problem these days. However, we got the data and interesting thing is when we compared those data with normal shale gas producer or shale oil producer in other basins especially in the United States, you can see they are quite comparable.
So what we have can be a shale gas play, shale gas play probably as good as some of the American plays, interesting thing is, is not just this shale gas, shale gas some reaching between two tight gas projects. So in fact we have three different levels to try, with two of them having tested gas.
In the following months we will drill the first new well trying to test this idea, is called Palenque Norte 12 is going to be a deep well down to 4000 meters. This well will go through stratigraphic column. We’ll try this Tight Gas - Shale Gas project in close to Springhill. It will happen, as I mentioned fourth quarter 2012.
Additionally, we are talking about drilling second well probably first half next year in Dorado Sur that is will be quite similar to this one. And this is Dorado Sur 1 well that tested 9000, sorry, 90,000 cubic meters per day, so we are very close to really tested production.
Additionally, we can tell you that Pan American, sorry, PetroMagallanes have just drilled well offshore in this area and they get -- our operation get as well in Springhill. We cannot show you that information but we can tell you that again there is a new well that has tested this idea. So we are expecting in the following month to really test this idea to frac this well and to produce it.
The potential resources for Palenque Norte considered in just the structure is about 8,000 million cubic meters are in C2 as you can -- you may know in unconventional gas you get -- you recover as much gas as many wells you do, is not a like in conventional business where you have a kind of fact -- that already factored. In this case you drill more well, you get more gas, that’s why I’m presenting in C2 gas.
But is just considering the structure, reserves for Dorado -- resources for Dorado Sur are similar. However, if this is an unconventional play maybe is just a full area and not just a structure that’s the most encouraging part of the picture. We don’t know it at this time. The idea is to test it through wells that will be done in the following months.
This is map showing a basin. This is Lago Mercedes well that will be hopefully reenter it by YPF and us in the following months. This is Dorado-Riquelme area. PetroMagallanes with Methanex and ENAP will try another well that will be drilling during this following month as well, targeting roughly the same, overpressured gas plus condensate in the middle.
And as you can see in this one tested gas, this one tested gas, this one is still a question mark. If we demonstrate those three we are -- we can open a very large area, unconventional play. As you may know unconventional gas usually tends to work in large areas, not just small individual structures. So this is very encouraging for us and all of it will be tested either this year or first half of next year.
Additionally to this idea, we have another project that is in shallower. As I mentioned you Springhill is 4000 meter deep. But drilling through Springhill we found another unit called G7 that is tight sandstone that presented gas in a number of wells.
Remember at old time this wasn’t important, so we went through them putting heavy math, some of those wells were very tested, so it was demonstrated that this unit had some gas whether they weren’t properly tested.
Last year we decided that we study this unit and we selected the couple of wells to reenter them and frac them. These were the first unconventional fractures done in the basin, because this unit wasn’t important at all times we didn’t have much data from them, we didn’t have any coal, any full sweet of logs. So our idea was to frac them and to see what we get -- could get from them very simplistic way.
The good thing is we got much more gas then we thought. One of the wells started at about 60,000-cubic meter per day, the other well started at about 90,000 cubic meters per day of gas plus some condensate. This gas has about 10% of heavier hydrocarbon cement is 90% methane, 10% other hydrocarbon plus some condensate.
The interesting thing here is that we reenter it all wells. We did some fracs blindly and then we’ve got almost commercial production. The question here is what would happen if we do it in the right way, in the way that is being done like in Canada or the States.
The other good thing that we could see was that this unit can be beautifully seen seismic, you have to believe this parts of colors is what we think is a reservoir so we think we can see it.
The difference between these wells and other wells some of it is more than 1000 meter for gas column, this is not naphtha it’s a column of gas. However, this is very encouraging because demonstrated that this is typically a tight gas project, there is no water in the system, we have continues gas from 2500 meters down to 3500 meters. So this is really important for us because it demonstrate, this is a real unconventional prospect.
This is a calculation of 3D service that we have -- here we have four 3D services. This is done Coiron with Pan American Energy. This is done in Dorado-Riquelme with Methanex and this is done in Arenal, a 100% ENAP.
And as you can see the three of them can seen what we interpret somebody and some of them has been tested and demonstrated that this is gas. These are Cabaña wells. The well those that we fracked and they fit very well with this seismic attribute, this color patch.
Here we have another bunch of all wells demonstrated gas in this reservoir and again fits very well. And here again, we have other places where it fits very well. So according to our interpretation these color patches, seismic anomalies and seems to fit very well with some bodies with gas.
What’s our plan then, if we have something really on our hand? First, as I mentioned, we did the study to select the well. These two Cabaña wells were producers, excellent and we have develop a new drilling campaign of six vertical wells where we are planning to first collect all the data that we are missing, because we do not have good reservoir data.
We are testing our old data so they are here to have new wells. Three of those wells will be appraisal wells in Arenal, very close to Cabaña wells, producing wells. Three of them will be in Dorado-Riquelme with Methanex, one for each anomaly. So, finally, we will end up 15 four different anomalies.
Additionally, I can tell you that ENAP has being drilling normal conventional wells that will go through this reservoir as well. So we’ll have another additional 2 points of control from normal wells.
We are planning to do this second in the following month and we are planning to frac them and test them by the beginning of next probably February, March. If this is a success then in this case, because this is a kind of easy target shallower than Dorado-Riquelme, we are planning to start a second drilling campaign where we can start developing this new play very soon, this is an easy area to work, so it should be easier to start with some at least some production.
The interesting thing here is as I mentioned we have two producing wells right now, Arenal to have let’s say six by the beginning of the next year, maybe 16, 20 up to 20 next year, so this will demonstrate the potential of unconventional in this area.
When we think about these specific reservoir is that is between 50 and 150 meters, rough thickness, so its ideal for horizontal drilling, the production that I mentioned came from vertical wells, if we can drill horizontal wells in the same unit we can get much better production from individual wells.
So our plan is after we drill these six vertical wells, some of them, or maybe all of them can be used as pilot wells for horizontal wells. So the idea is to jump very soon into horizontal drilling, because, vertically they should produce much more than horizontal wells.
So this is sum up all with -- all the wells that we are going to drill in the following months. So I hope to have good news for in let say March, April, hopefully we’ll be invited to the next meeting to present the good news.
But, again, this is good -- this is the map of the whole basin, here I had highlighted the producer we are dealing with and we are seeing additional potential along this strength to the north of Dorado-Riquelme and in the southern pat of Dorado Sur.
If we take all this area in account we have considered conservatively calculated potential resources of up to for this year for the whole area if this works. We will start first year and in case of success we will extend to the north and to the south, but the potential of the whole area seems to get quite important for us.
Here we are not working along. We presented this project to the U.S. Geological Survey a few months ago. They loved this project and they will help us to assess it. The way the USGS assess resources is a kind of very specific, they take all our information and they produce a report by themselves, we do not intervene in it and this report will be public. So, hopefully, we will have an independent report that can demonstrate or deny the existent of resource in the following months as well.
So as a summary, what ENAP has found in the last years is that we have significant area, more than 5000 square kilometers that has a potential for unconventional in at least two different units maybe four units that can have gas. We are not working along. We are working with Methanex, Pan American Energy, YPF and PetroMagallanes all of them a company, oil and gas company exploring this place.
GeoPark is doing the same in their own blocks, so all together the area is to demonstrate this potential in the following months. The most promising for us seems to be G7 tight gas because it’s easier and it has demonstrated some production.
So we are expecting to have it drill it by next year, so early production can be achieved as soon as first half of next year. It’s interesting because in order to demonstrate the potential of unconventional you have to put your wells into production, all the way you don’t know how they behave. So in some way we are oblige to put this wells into production and obviously these production will be sent to our pipelines. So we’ll have some production in case of success.
As I mentioned you G7 potential resources can be as high as 4 TCF it can be less. We are talking about resources uncertainty risk. However, its quite promising because if resources are about this size can be enough for supplying us C2 that you have to understand this is our first customer and then to Methanex that is the second customer for us. So it would be enough for everybody.
Bruce presented a situation in New Zealand a few years ago when there was a lot of public concern of gas resource. We really hope that this would solve that concerning Magallanes as well and this will allow us to provide a Methanex the full gas supply we had with them. So hope to have good news in the following 12 months with some demonstrated production in case of success.
Once we have demonstrated the success of these plays our idea is to invite other companies to come to join us. Why? Because basically to developing an unconventional gas project is to do factory of drilling, finally, you have to keep drilling cheap and fast.
We understand that we have -- we don’t have exactly that expertise we are use at the conventional when that’s not the strategy. So we have been talking with the number of companies including some of the majors that are interested in this kind of projects.
So we expect from here to the next year to have a strategic partner that can provide us with the expertise in order to combat in a drilling much, drilling fast, drilling cheap in order to get this gas out of the ground and hopefully, into Methanex plant.
However, you are aware that unconventional gas projects have a lot of resistance from some of the stakeholders. Let’s have a look, with look on those resistances.
First of all the Dorado-Riquelme wells are very close to main pipeline, so they will be put into production very soon, not to worry about it. Tierra del Fuego we are little bit far away but it can take us few months to build the pipeline.
So, however, we have both projects, so we can start production sooner in Dorado-Riquelme and then later in Tierra del Fuego, is not that big deal to build a short pipeline like for Arenal 20 kilometers of that well.
It’s a little bit longer for Lago Mercedes but then we will see after testing those wells. So it shouldn’t be a problem of infrastructure. We are in there by the size of infrastructure or relatively close.
Services, you like it or not we depend on the Argentina market these days. So, currently most of our equipment and frac crews are coming from Argentina. Argentina is trying to develop their own unconventional industry, so there will be a lot of companies coming to this industry in Argentina. So there will be supply of services in Argentina.
However, we now know for sure that we cannot trust only on that source of services and now we are talking with companies coming from other places and I can now tell you that, for example, the next frac crew we are negotiating is not coming from Argentina but directly from the States. It’s a brand new frac crew where we hopefully can get it and keep it in the Magallanes Basin, instead of going through Argentina that is always a complicated step.
Drilling in Magallanes is still a little bit expensive. I can make sure we can get cost from $1,000 to $2,500 per meter. It’s expensive for a world standard. However, one of the main reasons for this cost is the limited amount of drilling. Here we, in our drilling between 20 and 40 wells per year and that’s a small amount of well. What I hope, once we increase the drilling activity and the number of rigs, we will get a decrease in the cost.
We are getting new rigs coming to the basin in order to help us to decrease the drilling cost. These new rigs will drip cheaper and faster that the current drilling rigs we already have in the basin.
And again, frac crews and frac sand are coming these days from Argentina. Hopefully, we can skip Argentina an import them directly if we had success and we can develop our own service industry in Magallanes. But it will depend on the success of our projects. Anyway, we have Argentina just in case.
What happened with environmental issues, probably you are aware that in Europe these are such big issues that can stop an unconventional project. What’s going on in Magallanes?
First of all, this area is flat, uninhabited pampa, quite similar to the location of Medicines Hat. We have been operated there for 60 years. The only activity there is sheep farming, so it’s not really intense significant agriculture.
There should be more significant feel of drilling rigs, as it has happened in other places. We have been there for six-year drilling. In fact, most of the projects we are dealing are in areas that already have a number of wells in them.
Regarding aquifer, there is usually this fear of aquifer contamination. There is one barely used aquifer in Tierra del Fuego, but apparently is not in the area where we have our projects. So there shouldn’t be a fear of aquifer contamination and additionally, this is barely used because there is very few people living there.
So we do not expect any conflicts for water contamination or water supplies, as in other places have happened. For example in Neuquen, Argentina, the water supply is going to be an issue because their companies are conflicting with locals with water use.
In case of Dorado-Riquelme, we do not have an aquifer. However, there are no water close to it. So we can have some problem supplying significant amount of waters to Dorado-Riquelme. However, this will be an issue once we start drilling tonnes of wells per year, not in this situation when we are just drilling a few wells. So we will have plenty of time to solve this situation, we hope.
And finally, there is a strong public concern about local gas supply. So at deposit of some places, the locals are helping us to develop this project. They are not against us. Paul told me that few days ago in the local place, there has been a lot of local concern about this and our authorities are supporting us in order to develop this unconventional place.
I have presented this same presentation to a number of audiences including our authorities and we have received full support to develop this project. So we do not expect any further opposition to this project. On the contrary, we expect full support.
So in finishing, this is a typical picture of a normal standard unconventional operation here in Canada. This small picture is what we did in Magallanes and we got almost commercial production from doing this. The big question is what would happen if we do this, that’s the potential I want to present you and we will have some answers in the following six to 10 months.
Thank you, Lisandro. Excellent presentation that I know will elicit very interesting questions from the audience. So on finishing, a couple of things. I don’t want to reiterate what Lisandro has said. He said it very well. I just want to conclude saying that the investments that we have done to date in Magallanes on the upstream, they have been able to generate positive cash flow for us, both the once that we’ve done in equity investment and when we have financed others and have helped us preserve all the optionality that we seek to materialize in the long-term.
On the short-term, we will continue having challenges and as usual, we will maintain a clear communication with them to investment community. The upside potential then of course is based on the unconventional, and we expect learnings to be shared during 2013. Many, thanks.
My name is Tim Williams. I’m the Vice President of Upstream and Feedstock Acquisition. I’d like to communicate to you, Methanex’s view on North American natural gas.
So our Board has approved moving a methanol plant from Chile to Louisiana. They have done that based on a solid conviction that natural gas in North America is going to be abundant, readily available and relatively inexpensive.
And that is a radical change in North America from a few years ago when we were expecting big imports of LNG, all of you have heard of shale gas and reality, this is based on a technology breakthrough in horizontal drilling and multi-stage fracking for shale and other type reservoirs. Other type reservoirs are becoming part of the story.
So, I’m assuming that most people have seen the EIA map of shale plays in North America. As of May last year, there were 48 identified shale plays in the U.S. and another 15 in Canada. A few new ones have been added since then and some of the ones that were yellow on this map as prospective shale gas plays, will certainly be pink on the next addition.
Sorry about that. The same technology that’s used for shale gas is being applied in tight gas sands like the granite wash in Oklahoma and Texas, and in-site carbonate reservoirs like the Mississippi Lime in Oklahoma and Kansas.
This slide again is from the EIA, annual energy outlook and they estimate the total U.S. gas resource to be 2,203 trillion cubic feet of gas. So at current consumption rates, that’s about 96 years worth of gas.
542 TcF of that or about 25% is shale gas. Most of the growth in production for the past six years was from shale gas, and most of the future growth is projected to be from shale gas.
Right now, the U.S. exports gas to Mexico, it exports gas to Canada and in the form of LNG, it exports gas to Japan from the Kenai Peninsula in Alaska. However, due to tiny amounts of LNG imports and significant gas imports from Canada, the U.S. is still a net gas importer. That’s expected to change by about 2022, when the U.S. will become a net gas exporter.
Canada’s level of exports to the U.S. has been decreasing for several years. The TransCanada pipeline from the Alberta border to the east is running now at about 50% of capacity.
So the basic message is there is a lot of gas potentially available in North America, though condensate and NGLs in the gas stream help the economics of gas production tremendously, ultimately they are not going to be enough. We are going to need dry gas production.
So this is a production history for the U.S. and you will notice that a really sharp increase, starting in 2006 that's the shale gas revolution, that’s when the Barnett Shale went from 500 vertical wells in 2005 to over 1,200 wells, most of the new ones being horizontal in 2006, a big impact on production.
So if you look at that six-year period, 25% increase in six years including 7.9% increase in 2011, and that rate of increase far outstripped the rate of demand increase, resulting in the price collapse.
So my message from this is that the E&P industry is capable of developing shale gas plays and bringing on very large volumes of natural gas production very quickly. One could reasonably anticipate that at acceptable to the producer gas levels, the supply response would be very quick.
Now, we need to talk little bit about the price of supply. This is a forward curve for natural gas from August 21st I have this presentation together. And I’ve shown it starting in 2015 and going out through 2020. I’ve shown it starting in January 2015 because that's when we expect our plant in Louisiana to start. So this curve shows gas prices between $4 and $5.85.
If you had shown me a forward curve, anytime before June of this year I would not have believed it. This one is reasonably credible. It is reasonably credible for two reasons. Number one, there was a continuous erosion in the forward prices throughout the year until May or June, and number two, this seems to be a regional provider, a reasonable margin above production costs and I will go over both of those points in a little more detail.
So this is a different look at the forward curve. Instead of looking at several months in the future, I'm looking at one month and it happens to be July, 2017. It could've been any month in the future, they all look the same. We see that sharp decline in price for month to month to month until you get to May or June when it starts to flatten.
If the forward curve is a reasonable representation of real future gas prices then I would expect it to start to flatten, which it has clearly done here. And it’s done that as the market has finally come to grips with the likely abundance and likely costs of future gas production in North America.
Little bit about supply costs. Firstly, sunk costs are totally irrelevant for the natural gas producer that means acreage costs. There is not a single significant shale gas player in North America who does not have decades, worth of drilling locations without acquiring another acre. So acreage costs does not necessarily to produce large volumes of gas and totally irrelevant.
Cost of supply and investments decisions are predicating upon a forward-look at economics, not a backward look at economics. And so if you are determining supply costs, it’s a question of what is the incremental cost to bringing on another Mcf of gas. To try to get at that number, it is very complex because everybody reports different numbers.
So take one of the big players in North America, Encana. They have very publicly announced that $3 per Mcf, their dry gas position in the Haynesville, second biggest gas fields in North America, will yield a 9% return on a point forward basis.
So it is an expectation of 9% return, likely to attract a lot of investment. I don’t think so, not in the oil and gas industry. So, I’ve done some back of the envelope calculations that show a $4, they would be getting well in excess of 30% rate of return. I think 30% would attract investment.
Now earlier this month, Mike Yeager, the Upstream Executive of BHP Petroleum announced that in a press release that they would need a gas price of $3.50 to begin to shift their expiration drilling program where their drilling program back towards dry gas. So we are having two big shale gas players indicate that somewhere in the $3.50 to $4 range, is something that they would find attractive to invest in drilling dry gas.
Another really important concept and I just lifted this slide directly out of Encana’s last Investor Day presentation. Again, they are the second largest gas producer, third largest gas producer in the U.S. and the second biggest gas fields in Haynesville.
What they're showing there is a 46% decrease in cost of delivering that gas over a four-year period. That’s brought about by decreased drilling time for the wells. The day rate for drilling rigs is going up. But the time to drill wells is going down faster.
In addition, they're doing much more effective completions and they are getting more and more gas out of each well. We have those two things together and they are more than overcoming the increase and the inflationary increase in the cost of services.
And a caution to all the analysts in the room, anytime you hear anything about supply cost for natural gas in North America, with that kind of rate of improvement we need to be very careful to pay attention to the advantaging of the information on supply cost. Supply cost as of when because not only is that going down quickly, it’s not showing any sign of flattening yet, ultimately it will. It can’t go to zero, but is not showing any sign of flattening yet.
There is a consensus and I think it's absolutely right that gas prices below $3 are not sustainable in North America. So what is Wood Mackenzie? In conjunction with their June, North American Gas Forum pulled their clients about what they thought a sustainable gas cost would be.
And interesting results, 25% of the people who responded thought it would be less than $4.25. 78% of the people who responded thought it would be less than $5 and 91% of people who responded thought it would be less than $5.75. So there is a near consensus that does an awful lot of gas and dry gas that can be developed at less than $6.
Now, where are we? Under most methanol pricing scenarios, any gas pricing less than $6 is going to generate positive cash flow for us in the U.S. Gulf Coast. At Medicine Hat, we are purchasing short-term forward strips and spot prices for gas.
The AECO discounting Henry Hub has varied over the last several months from $0.30 to $0.77, and we see Alberta -- Southern Alberta gas has becoming the market for dry gas, becoming more and more constrained over the next several years.
So we are very comfortable with the way we are procuring gas for Medicine Hat for now. We are, of course receptive to a long-term deal and we are not in any hurry to do one. We see no particular need to move in that direction for Medicine Hat.
For the Louisiana plant, we think there is the potential to secure a long-term gas contract and we are currently negotiating on that. Let me say that, we have talked to more than 20 companies and most of them we get the answer, we are not interesting in long-term contracts, we don’t sell on any basis other than NYMEX.
We have found some who have a very different opinion and are anxious to diversify their pricing away from North American gas, and are receptive to long-term contracts. So, I’m very optimistic that we will have a long-term gas contract in place for guys who are well before we start production.
And with that, I will turn it over to Ian.
Good afternoon. For those on the webcast, my name is Ian Cameron. I’m in-charge of Corporate Development and also the in-charge of Finance. I’m going to provide a brief presentation on each of the two topics, finance and corporate development.
In finance, I’m going to focus on capital allocation and the balance sheet. And in corporate development, I’m going to lever off a little bit of the discussion we’ve already had about our favorable industry structure, where we are heading as the company and sort of synthesize where we are heading in terms of being able to add capacity quickly and at a very attractive capital cost. So, I’ll be synthesizing that with focus on our new project in Geismar, Louisiana.
I thought I first just mentioned a couple comments around our philosophy, around our balance sheet and I think those of us view, I should say that have followed us will know that we are a pretty conservative company and we manage our financial situation very prudently. And what we mean by that is, we like to have strong cash balances, prudent leverage. Throughout the history of our company, we’ve had backup facilities, backup debt facilities.
We like to pre-fund our major capital programs and there is a lot of discipline around our capital programs and I think that capital discipline really starts with our strategy. The fact that we're focused on one product methanol, and I think right away that will focus you and how you think about, how you can allocate your capital.
I would say that notwithstanding the fact that we think of ourselves as a prudent conservative company, we are also very shareholder friendly and I think you can see that by the evidence of the cash that we’ve returned to shareholders. We’ve distributed a lot of cash through dividends and share buybacks.
So it all starts with the balance sheet and throughout our history, we’ve just had a -- it’s in our DNA and philosophy a strong balance sheet. And we think about our balance sheet, there’s two purposes for it. One, as a defensive mechanism is to protect against financial stress and we saw our defense, our balance sheet in action in 2008, 2009. And we came out of that period unscathed and that was the credit to having a strong balance sheet.
It’s also gives you the financial flexibility, for when you want to move quickly and take advantage of strategic opportunities. And I would say we are in that period today. We have the opportunity and we discussed this already. Most of that, about 2 million tonnes of capacity at attractive capital costs in a very, very short period of time. So it’s a period really around the two-year period. So we’ll have another 2 million tonnes, we hope by the end of 2014.
In terms of distributions as Bruce has mentioned already, we are really committed to the dividend. We introduced that dividend in 2002. We’ve increased it almost every year. The plus key around that dividend is we wanted to be meaningful, sustainable and we wanted to grow overtime and we’ve had a track record of doing so.
We also like share buybacks. Share buybacks for a company like ourselves, is a great mechanism and cash flows come in lumps sometimes and capital expenditures come in lumps. So it’s a great vehicle when you do have surplus cash in excess of our strategic needs to return that cash through share buybacks that share buyback vehicle.
Bruce had mentioned that today, our priority over the next couple years is to add this 2 million tonnes of capacity. So it’s unlikely that we will be buying back shares in the next couple years. But Bruce will show you a slide little bit later that shows what that additional 2 million tonnes means towards cash generation capability, and we should be able to continue our track record of repurchasing shares.
I want to just make -- give you a little bit of a snapshot in terms of how we expect to spend capital over the next couple years. So we have about a $1 billion of capital spend. We have the capital maintenance. The capital means, though we continued to spent little bit of money on the upstream in Chile and New Zealand, but I think that the numbers are really focusing on all the capital that’s required to de-bottleneck Medicine Hat, to add capacity in New Zealand and to execute our Geismar project. And if you add those numbers up, it’s about $700 million.
And if you think of that in terms of capital cost for per tonne, that would translates to about $350 per installed tonne. So that’s a very, very attractive capital cost when you're thinking about reinvestment for a typical greenfield plant today, which we believe would be in the range of $850 million per installed tonne, so really great opportunity in front of us.
In terms our balance sheet, lots of cash in our balance sheet and as I just mentioned earlier an undrawn offering line to support that. I’d also say that the investment grade rating is very important to us. It gives us lots of financial flexibility, but almost as equally important it gives us operational stability.
When we think about what John does in his supply chain in the value and flexibility of his supply chain, that's all dependent on the fact that we can move product around the way we like it, not having molecules attached to specific plants. So it gives, having an investment-grade rating really helps with operational flexibility.
When we stress test our balance sheet, we look at our balance sheet in terms of what capability, what capacity it has in it. We think there is more capacity available, debt capacity available and continued to meet our investment-grade ratings. And of course as we add there’s 2 million tonnes of capacity that adds more cash generation capability and that in turn, again would add further debt capacity to the company that help with strategic growth.
I also want just to give you a little bit of a snapshot on our debt structure. We have about $400 million of poor debt with a reasonable spread of maturity. So there’s a $150 million bond that’s coming due in 2015 and we have a $250 million bond that’s coming due 2022. We have project debt that’s attached to each of Atlas and Egypt projects and that adds up to about $350 million.
And when you put cash on there, the net debt is about $350 million and obviously very prudent net-to-debt leverage ratios, very strong credit metrics in general. When you look at EBITDA coverage ratios, I think that’s very strong credit metrics.
So I think the point that I really want to make is one, we have a -- we are very prudent company. We have a strong balance sheet. Our priority for cash over the next couple of years is to execute these really great opportunities we have in front of us and we have the capacity to do so. And so that’s the key message in terms of balance sheet and capital allocation.
I wanted just to make a couple of comments on a couple of ancillary financial issues. And I’m not going to go over the slide but just to make a couple of points. If you add up all those numbers in terms of what our tax rates at various jurisdiction, you’d probably come up with a number that’s higher than what we think our accounting tax rate is and the reason for that is we have a very efficient international tax structure and we do have some tax shelter that has been affected in terms of -- in our financial statement.
So I was going to update guidance in terms of how you should think about accounting taxes. We would continue to give guidance at the 20% to 25% range and I would buy that to the low end of that range and that is an outlook I think you can be comfortable with over the next three years. After three years, it’s really hard to predict tax rates. In terms of cash tax rates, think of cash tax and deferred tax as a 60, 40 slit. So 60% cash tax and 40% accounting tax.
The other issue I just want to make, so the issue is around accounting and a couple of issues that we’ve already mentioned in the last conference call but that’s a part of the relocation. There is a couple of accounting issues that we are going to be dealing within this next quarter, kind of unusual issues.
So there will be $60 million pretax charge and I would say those numbers are approximate. At this point in time, we’re still going through the finalization of those numbers. $35 million of it is a cash charge related to items that are not allowed to be capitalize under -- capitalized under IFRS. The other $25 million relates the bits of the plant that we’re not able to locate -- relocate to Louisiana and therefore have to be written off. So the pretax charge will be about $60 million.
So anyway, that concludes the finance part of the presentation. And I want to switch gears now in terms of really fund stuff which is the corporate development side and just to summarize today I think John and Bruce earlier in the day really provide the compelling case for really solid industry structure.
Great supply dynamics of demand dynamics, not new supply coming on stream and here we have a couple of opportunities to add $2 million in terms of ratio for the period of time to exploit that opportunity and in an environment where we should expect to see high pricing. I think that’s the thesis here.
So we’ve already talked a little bit about New Zealand. We’ve already talked a little bit about the Medicine Hat debottleneck. I’m going to focus on the Geismar, Chile relocation to Geismar, make a couple of comments there. To me, this is a little bit of a perfect storm.
This is -- in fact, could be instrument -- and up more industry in general, we have a very good structural fundamentals. We have changing debts fundamentals in North America which tends just reviewed and we have to have -- happened to have an opportunity to move our plant quickly. And I think that’s an important point to quickly part.
And I think that creates the perfect storm. In fact, I would say that I think you’ve done a pretty good job of reacting to this North American restructuring gas. It wasn’t too long that we are seeing on ELT table thinking about, being a first mover, we starting a Medicine Hat plant. We took that action quickly when we saw those changing dynamics.
We made a decision very, very quickly to aggressively pursue this Geismar opportunity. Now, we didn’t make a final investment since last July but we had a mindset that we are going to be successful in it and as we evolved our thinking over the eight month development process, it became more convinced that this was the right opportunity for us and we get more confidence from our natural gas dynamics in North America.
So I wanted to show you the slide. So this is the slide that you can actually get off. It’s a bit of an L-shaped site. It’s on the Mississippi in a place called Geismar, Louisiana. Lots of chemical and supply infrastructure around it, flat. It’s about the Mississippi flood plain from east side of the river which evidently -- the marketing folks tell me that’s a really good place to be on the Mississippi from a logistic point -- very low logistic cost.
So we feel really, really good that we are able to very quickly secure our plant at this quality. The other thing it’s really -- which is good about this side is that it can accommodate two plants and we’ll talk a little bit about it at the end.
So a little bit about schedule. It’s interesting. We’ve actually put a team together and met in this hotel for the first meeting that kick off this project in August of 2011, so just a little over a year ago.
So in just a little over a year, we secured land, hired engineering companies, done all the engineering but we’ve started to dismantle the plants, got the permits basically in place and all systems are gone.
So this has happened very, very quickly and I think the key point in this chart is that we expect by the end of 2014 that we’ll be up and running, producing on an annualized basis in tonnes.
So may be just a couple of comments on where we are at. So the permitting process as I sort of alluded too is substantially complete. So the Louisiana environmental authorities have given preliminary approval. It has to go through all the hearing process which is ongoing and that should be completed in the next 30 days or so and we should expect to secure -- have our permits in place by middle of November say.
So that’s all in good shape. Engineering as I said is already completed. We are -- look we have decommissions that the plant has been moved and we are starting to dismantling process. Shipping is -- we are arranging shipping and we would expect to start shipping the plant in January, February of next year and having it arrive in Louisiana, June of next year.
But the shipping windows, we’re still working through the exact details but that sort of high level. I have to think about it and we shall start construction June, July of next year. So that’s the timeline and so far what we’ve seen nothing impacting schedule. So things are going very well, having said early days.
Let’s say, this is a nice picture of Bruce with Bobby Jindal but it really a symbolic of the support that we received from Louisiana authorities. So it may just have really opened our arms to us and it’s a really good investment climate there.
Bobby Jindal met with us twice. He has an absolute fantastic team. He has an organization that reports called Louisiana Economic Development Corporation staffed with first class people, really support of and accommodate. So we really feel that we’re getting a lot of support and they really want us there.
So we really feel good about that, all the way from his level, all the way down to the parish level which is where our plant is in the Geismar in the Ascension Parish, where Geismar is located.
This is a photo what the boat is going to look like. This is going to take the equipments here. 70 meters by 160 meters, so it’s huge. Huge chunk of plant is going to be on this plant -- on this boat, so all the big pieces, pipe racks, polymer, all that will be on one shipment from Chile to Louisiana.
They can -- for example, just give you a couple of metrics, I think very interesting, the pipe rack, they are going to chop up in 60 meter pieces and stick on this thing. It will be a total of about 30 big pieces that will be on this ship and there will be a couple of other smaller ships that will take other parts of the plant up to Louisiana.
This is a sort of a little funny one. This is new core steel plant that’s actually going the other way. It’s going from Louisiana across the Levy onto the Mississippi that we ship to Trinidad. So just, sort of, an example that this has been done before in terms of moving big pieces of equipment over the Levi in the Mississippi river.
Obviously, we think this is a fantastic project, a million tonnes capital cost, 550 attractive capital cost, Levy cash cost very attractive, $200 a tonne, could be less depending how we get contracted. It structured -- last depreciation we’re seeing is very good. So it means that we won’t have any cash to access probably for the first few years in -- way to this project and short payback grids.
What do we mean by short payback grid. Bruce mentioned three to four years. So it always depends a little bit on methanol price but very, very short payback for an attractive project.
Tim has already referred to where we’re at in terms of gas. And I feel that we are making a lot of attraction on this. And I hope that we deliver that more quickly than it was really too by tenth. If we are not successful, I feel that we can de-risk this project by buying gas on the future markets out of two forward contracts or putting some kind of color structure in place that would assure very quick paid back period and de-risk the project.
Well, I think we’re in really good shape for this project. So a little bit of synthesis. We talked about this 2 million tonnes. This is all about New Zealand debottlenecking Medicine Hat at Geismar and executing on improving utilization of Chile asset. So lots of option value there as well.
So lots of opportunity and we’re now at the stage where we are also starting to think about it doesn’t make sense to go forward with the second relocation. And I would say that our thinking isn’t fully developed yet but that certainly is a bias in our company that this makes a lot of sense and there are few reasons. One we really believe in the fundamentals in the North American gas in North America.
We happened to have an ideal plant that’s available. So we can move quickly. We think that we move forward a secondary location we could have at operating first or second quarter 2016, so very, very quickly. So that certainly is fantastic and we can save a lot of capital.
It’s a bit of table top at this point but there is substantial capital in the range of $100 million that could be saved on a secondary location. So a little bit of work to do yet and no rush really to make a decision but we think that by first or second quarter next year, we’ll be in a position to decide whether we would go forward with a second relocation.
So that concludes my remarks. I hope you kind of get the sense that this 2 million tonnes is quick and with low capital is a fantastic opportunity for our company. With that, I’m going to turn it over to Bruce Aitken and he’ll provide some concluding remarks for today.
Good. Thanks Ian. I hope you’ve kept some of the enthusiasm from our team around the immediate future. So I’m going to repeat just a few of the slides just to really emphasize the really compelling point and this is -- there is nothing more compelling than this one for me. The demand continues to be strong and there is nothing much happening on the supply side that upsets the balance.
It implies that the price of metal has to be high enough to keep the high cost producers in the game which suggests that we are in a sustained environment of high methanol pricing. Another reminder of the methanol pricing is going up, improved pricing in recent years and if you believe in high crude prices, you should believe in high oil prices as well.
This is the chart, I think, Ian is referring to in the chart we are spending a little bit of time on what this is lightly. I think the middle column is the compelling column. It represents we describe it as growth project. It represents 2015 the way we think about the world unfolding. For this size, Louisiana project is under way.
I think we’re still being quite conservative around Chile by 2015. We’re -- only still with one plant. We could do better than that and just a reminder from Lisandro’s presentation, 1 TcF of gas makes 20 million tonnes of methanol. I know in one of the slides, I saw 4.5 TcF. So I got to a 100 million tonnes of methanol in Chile. So that seems like a very nice answer and if we get there, Lisandro, you can certainly come back to every other investor conference we have a hold to.
So going back to our chart here, the 7.3 million tonnes in the middle there looks like a very achievable result. We have all of the pieces in place. And then at the bottom like the price to methanol will be what the price of methanol has and we’re not -- we don’t want to make forecast. So we’ve given you a range of venues there. I think even in those venues we’re relatively conservative. We look at what people like CMII is still forecasting for methanol pricing in 2014 and 2015. They are closer to the $500 per tonne.
So they would be near to the bottom line rather than the top line. In their middle column there, between $800 million, $1.2 billion of EBITDA out of that production base. It’s really trading today at around $3 billion into price value, the company looks very cheap.
And then of course, if we are able to be more successful in Chile, on the far right hand side there, with these more relocation or greater capacity out of that Chilean assets that we can get ourselves up to $1.5 billion of EBITDA. So a lot of growth in earnings in this short period of time.
I think Ian is also referring to the cash flows that clearly -- the cash flows at this order overwhelmed are growth projects. So I think to the extent that we deliver on these, we would certainly be buying back shares within that sort of time horizon.
I think what’s interesting to us is consider valuation in relation to replacement cost. We think replacement cost today is around $800 per tonne. And really that had really to build the plant entitle with the right number. We’re a couple of metrics. We sell about $700 a tonne in Egypt and we completed that project back in 2005. So really before lot of the cable cost escalation occurred.
There was another project built in Oman, that was $900 per tonne of capacity. That flag was pretty much at the top of the boom in construction building. We think around $800, it’s probably what good numbers we’re thinking about. And again, depending on which assets we want to include or exclude, today we’ve added somewhere little over $500 a tonne. So on that basis, it still looks like we recently value it or very cheaply value it.
I think this is another instant chart comparing the Methanex stock over the last 10 years with S&P chemicals index. And then on the far right hand side, we have put the valuation, the latest valuation, 10, so the index is starting at 13 times PE. We traded 9 times PE and enterprise-related EBITDA, the index is 8 times and we are 5.5 times. So it looks relative to the index that we’ve outperformed over the last decade. We still very modestly value.
So I hope you’ve got a lot of enthusiasm from our team at what you’ve heard today. The growth opportunity is instead of the industry. I hope you agree with me that our stock is very cheap in the current market and represents a strong buying opportunity. So I’m sure you’ve got a lot of questions and we’ll do our best to answer those under next 25 to 30 minutes.
May we all access the chair here and share the questions around and we start to pull.
So I got a (inaudible) on the Louisiana project timeframe (inaudible)?
Right. Right. Okay. So I’m trying to look at closing timeline for the first minute and I’m assuming this is taking time on certain aspects of it. So we’re using from the permitting on this one, looks to be about 30 months, roughly speaking, so the timeline you gave is the same. I would assume that would be faster?
It would be faster. Yeah.
Mike, why don’t you comment on the recent forecast?
So the implementation that (inaudible) timeline, the (inaudible) reality is it’s on conservative schedule and we think we can do it by the first quarter of 2016. We have an (inaudible) that actually would close some of that tax unless we get to different decision and then apparently part and we try to optimize the schedule. So we haven’t tried to optimize again. But it’s not a very exact (inaudible).
So practically speaking, it will be in 2015 from (inaudible). Is that transparent, just comparing schedules together?
I have applied in terms of plant and cash flow that we will build I think the first quarter of 2016 has based on position we have today in our industry and when we make a decision, we will optimize the schedule (inaudible) we think that we are (inaudible).
In terms of the CapEx for the plant attuned focus than ever?
We think, table top again that it will be about $100 million or so or more than first one. That we think about what represent the plan, buildings, hook ups engineering people (inaudible) to get (inaudible) up and operating. So it will take long to see that (inaudible).
It’s a $450 million?
Thank you. I just wanted to ask about why you are looking for one long-term gas contract in the Louisiana to make a decision on moving a second plant. When I look at the second plant, you already have a three to four-year payback on the first one.
Obviously, the second one CapEx is going to be lower. The payback is going to be a little bit quicker as well. You showed a great chart there of demand outstripping supply over the next year now. High cost capacity is going to have to come on and that should support pricing as well. And so what other factors are there in play?
Can you give us an update on what happened in Egypt, maybe a week ago, week and half ago, you were intending to shutdown now as mentioned in past and it was restarted. What’s the situation there?
What you know about Egypt is what you read in the news. There is a degree of political cast and I think it’s fair to say if you work or cease not working particularly well. There is a lack of good relation between the ministries. There has been history of very hot summer. We expect an electricity demand. You probably (inaudible) in Cairo and other cities in Egypt.
So a lot of incremental gas flowed into electricity supply but at the same time, there have been some supply outages in the upstream which you could blame on poor maintenance or poor attention to [accretive] maintenance and slow reaction to repair situations.
And this is all disadvantage of cash. So the authorities began allocating gas and they have favored just the generation and favored domestic consumption. We’ve been in close coordination with them throughout the last three months. And I think as Michael has mentioned, they recognize the values of their definitive country. They know they are tied with us in the project. So they want to make money and we’ll make with them also. So the economic consumers are fully alarmed. So there is damages that come off a little bit and there is more gas available in the system. The issue on the pipeline has remained very stable and we stand and have plan to get it few weeks ago -- few days ago and it’s really the matter of 70% utilization.
What the future holds, one thing we know for sure is worth the gas. I don’t think there is shortage of results here. When I see everything that [President Mercy] has been talking about and the freedom of justice priority, talk about support the private industry, respective contracts, the need to improve the economy of the country, the need for foreign distance to support the development of country, the need to get tourism back in prospering.
So we are on the right side of all of those things and I think as the political situation there matures, I think we will get back to a much more stable situation where we can expect to receive all the gas closure contract but we’re in this situation at the moment where there has been a degree of cost that has some loss of production.
What is your outlook for the next year for utilization?
It is hard to say and when we’ll get 100%, I don’t know. I think if you assume that we will get 70% because of the year, it’s probably a reasonable assumption. We’re going to work hard to get 100% and we have a contract. There are obligations under that contract. We will be pushing hard to ensure that those obligations are on it.
All the maintenance are done out this year?
All the maintenance is done, yeah…
It runs on very good shape on the issues.
Any further thoughts on coal methanol that hasn’t been talked about for a while that was highlighted at one point…
… something that would, I think you have done something?
We did a lot of work on coal methanol field. We’ve learned a lot as a result of that. And result in Chile, So Chile, lot of them our coal resource in Southern Chile both convenient and located to our plant, and we felt that was only existing infrastructure we had there that coal to methanol might just not work in Southern Chile. What we’ve discovered is there is a lot of capital that’s required and it had to justify the economics. So we have lost a bit of enthusiasm.
We will testifying coal through that syngas to make methanol. What we still have to enthusiasm before as using coal as a fermi energy reserves and it does seem that the region of Magallanes is also paying a lot more attention to coal as an alternative to natural gas.
So, there is a project under way that we’ve been party to full that is studying synthetic natural gas from coal that would make gas available to the city, which then believe incremental gas is available to us. So any incremental supply of any energy into that region is helpful move to customer to gas supply.
Another question I mean hope you understand the economic methanol (inaudible) I think it turn methanol (inaudible) versus ethylene of course how you can deliver the China at the U.S. (inaudible) how those…
Well, I’ll start-up with John Floren has got a better answer to this but my number one answer is this cheapest way to make ethylene is from ethane probably in the Middle East and the second cheapest way to make methane in the U.S. Gulf today. The most expensive way to make ethylene is to make it from most of that is in Asia but 50% today of all the ethylene in world, you guys, I’m sure that has been a largest sale, I might have these numbers wrong. The naphtha crack is the high costs producers today.
If you look at the -- where in the costs good is coal relevance or methanol relevance sits, it sits nicely underneath the costs structure of naphtha cracking in Asia. So I can certainly understand why the Chinese is so enthusiastic about the process. And John, you have been there.
5.1 in the presentation has Bruce’s cost curve not ours. It shows clearly what Bruce has just mentioned. So there is quite a bit of capacity that will be higher cost in methanol for all them according to this cost curve and we’ve had just confirmed by other people like MMSA for example, but have a similar cost curve Mark (inaudible) who follows the industry quite closely.
Sorry, I point in that as well for instead ethylene is (inaudible) and that’s people obtained one propylene into the marketplace so unique, you need to catch it into the value chain right, we can’t give the pipeline income. If you want to get the ethylene we don’t chip it right, so the probably (inaudible)…
I guess the other way -- we are not -- the other way is certainly inherent change in the net book ethanol in China just if you just shipped (inaudible) economy get still to make it compatible. I certainly haven’t studied those economics, but certainly the Chinese want to make these products in China. So we haven’t really studied relative merits of making plastics from ethylene and the Gulf Coast to China.
What that implies of order ship that and all of the naphtha cracks in the world, which is have the ethylene capacity in the world. So, it seems like an extreme position where plastic pallets from U.S. Gulf like more sales than making the ethylene and propylene. We are probably the right people to ask perhaps not enough so. Jacob?
Jacob Bout - CIBC World Markets
So, I have a couple questions on Chile. So, I guess first thing is CFS spot right now as far probably one plan to the operational supply to government?
That’s great. Yes.
Jacob Bout - CIBC World Markets
And then as far as the strikes that could be paying for your gas going from the conventional to the unconventional, maybe this question over here, what would you be looking for your gas from a unconventional obviously its much more expensive?
In a very early stage.
So what we know for sure now is unconventional drive is more expensive and conventional. However, in order to define a specific break-even price, it’s hard because you need both cost of drilling and fracking and the initial production of gas plus liquids, we don’t have these data now.
We can speculate a little bit about ranges but it is the same situation down in United State that’s Tim mentioned this range, probably a range will be quite similar to the range here or the range in our antenna -- in a antenna, for example there is a number of tight gas project each one having its own break-even price is ranges there from $4 up to $7 that’s for million Mbtu but it’s quite similar to what Tim showed and its quite similar to our speculative calculation but we will now for sure that our figure after dealing the west, anyway what we can face is high grade done on the normal conventional customer.
And that was the case of U.S. to start share gas was more expensive to produce the conventional gas but where the evolution of technology improvements in operating procedures has got a little point where shale gas is cheaper than conventional gas. And so it’s a question of initially yes, shale gas will be more expensive than conventional gas in Chile. But at the (inaudible) and efficient since happened then I would expect it to be cheaper than conventional gas overtime.
When it would be safe to say overall that the development shale based gas is going to be more expensive in the U.S. just don’t have (inaudible)
It will be more expensive than in the U.S., absolutely.
The reason to talk in Chile that buying gas to the dollar per base price and ensuring about that clearly that is not what’s in their mind around gas availability in Southern Chile and the good news is we can afford to play a lot more and still like lots of money out of that facility. I think the coincidence of cost of funding with the value in methanol still likes an economic proposition where the gas supply and that sells can make money out of this business.
And maybe just to follow-on, how much money is Methanex willing to stand in the development of unconventional gas?
They earn $50 million for instant in that order. We are very happy to continue committing modest demands of capital when we target that to try and accelerate things would otherwise happen to bit slower. So our whole objective is try and make conception quicker.
I think the full agenda -- I have given you insight into that and why conventional has been challenging and the opportunity around unconventional and that the challenges around unconventional still the technology and environment of service contractors and there is a slow building of that resolve spirit that hasn’t had immediately and not going to have spontaneously. This will be a slow steady improvement I think…
Is it $4 million to $7 million pro forma to show this prospect?
$4 million to $7 million as well. Not necessarily when some of one of the most encouraging things about our G7 for yearly is 2005 meters instead of the one so it that would mean we have betting on cost initial cost of about $3 per well that can if lower as we improve efficiency of drilling that fracking. We realized that up to this moment we are dealing in the expensive way in Chile basically because of the scale, is it more scale compared once we get it in much larger scale.
Let’s say dealing tens of ways among we can get much cheaper drilling up to this moment we’re drilling some uptick but here important thing despite this program is very simple that we are testing a new design, very cheap design certainly could not the file a program just for production its kind of program for cost as well. Here we are trying to reduce the cost of the way as well. If it works or not, we can sell it after drilling, not in advance. So we are making the effort of working cheaper.
Thanks Bruce. Question around project management, you really ramped up your project development activity, run new location maybe two, coupled with debottlenecking projects that maybe restart Waitara Valley. Can you talk about give some color as to what you’ve done in the project management side just to be able to keep on top of all of the different development…
Let’s Michael go around to the question that he is responsible for all of that.
Yeah. Sure. Well, thanks, Bruce. So we have a core group in my function who’s responsibility is either say and pull together and coordinate really last project and that the same group that the Egypt project carefully as now moved into Baton Rouge and we’re just ship the contract.
So our strategy is to maintain a core group of expertise and then leverage a specific contracts that the each project that we have, and that’s what we are doing for the relocation. The contract we chose is Jacob Engineering, right side of its Baton Rouge office and Jacob also have an office in San Diego. So that’s foundation for us to build for the engineering activity that’s happening actually in Chile at (inaudible).
From a New Zealand expansion perspective, historically what we have done is use our own in-house resources to manage that contract when we restarted the Motunui II plant and then the Motunui I plant. Now that we have moved New Zealand to sort of the based load longest term view, we don’t want to distract their operating organization from running projects and so again a New Zealand we have a core group have done the project historically and now we are going to an EPC model execute the projects in New Zealand for the restart and like turnarounds and keep our baronets and vessels.
We had sort of not exactly the same approach to the Louisiana projects that’s -- both approaches are based on a core of the expertise is in-house and then leveraging the life contracting organization and strategy for each individual project that we have in front of us. And we run regular sort of quarterly project reviews to make sure things are on-track.
We share resources between the regions and we have con people from that plant side into the project organization to make sure that we are actually transferring the knowledge. And we actually already started hiring for Geismar to ensure that they leadership of their organization gets onboard early and that we are again able to take key positions in the new operating organization and embed them in the product in the project organization. So that they start taking ownership for the new plant even before it starts production. It is the bunch of interaction that happens on integration to optimize them.
Yeah. Liquid done enough projects there were pretty good at it. So I think we will continue to demonstrate I think it sound the middle idea…
Its quick I guess for John, just more curious kind of what was the leverage be to improvement in shipping. What will be peak earnings be if you see that coal rates improves and it gets broadly if those rates improves kind of PD impact to global cost curve just in terms of how methanol moves around the world would that be a benefit or negative?
If we tend to buy our ships at the low end of the curve and we have an average cost to ship that’s pretty competitive. I’d say today into the spot market you could probably do as good if not better than what we have. Because this spot market has been quite depressed for quite sometime. There is a quite an overbuild that happen is all that money was available 2006, '07 and all those ships we delivered in '09, '10.
So there has to be quite a bit of scraping. It happens its interesting because of the volumes of chemicals and petroleum products that are moving are quite good year-over-year increases but there has been so much capacity that’s come on, but there has to be some scraping and we are starting to see that we even redelivered one of our ships early in the year that the big millennium explored.
So, I think we could easily see spot rates or contract rates terrible or even triple from where they are today. So when we are looking at our backhauls that would obviously be highly revenue generating compared to what we see today. So every backhaul voyage you do does contribute to some of the, what we called vacant time or ballast time on the ship. It really depends over the markets and these things tend to be cyclical, but I think we need to see some scraping occurring in the industry so we’ll benefit from that.
And just historically I think your previous cycle how much earnings leverage could that translate as to spot prices double or triple and what would the lever be?
Yeah. We’ve never disclosed that. We embed that in our net logistic costs.
Just the impact from if your spot rates double or triple would that be helping you guys, you just think about you moving all around the world. I mean I guess you guys are probably short and generally are you completely bio-logistics is covered internally that you wouldn’t be -- you just would be making the money in the backhaul or do you…
We actually -- that took us a little bit long because what happen in Chile. We get up our shipping fleet to have four-plan operation in Chile. There are long-term time-charters so we don’t get to redeliver them or in some cases purchase them until those contracts come up.
One other things we haven’t talked about New Zealand as we get back to 2.4 million tonnes is a great backhaul opportunity that even in today’s market very financially attractive from Korea, Australia, New Zealand bringing back petroleum product. So more we can move to that market from New Zealand, we will have all of these backhaul opportunities, which is even in today’s stress market are quite attractive.
So we’re in Chile -- when we were in Chile, the backhaul opportunities were more to the West Coast to the U.S. or into Gulf not nearly as attractive as we have in some other markets.
Charles Neivert - Dahlman Rose & Co.
Yeah. Just to be clear, I mean in the presentation, say, you just very much sounded like you’ve got pretty -- I call it maybe a mild problem but its probably good one conversions of timeframe between Chile and gas work and your decision to move a plan. I mean what is this you are going need out of what’s going on in Chile, because they need change that and can they and I know its little too early make that coal but how much gas do you need in Chile to run three plant instead of two?
As the version on field as we have the time over again we lived with four plants in Chile. It’s too much capacity on that part of the world. And when you look today where demand for ethanol is, its growing most robustly in Pacific place and what the Atlantic place is. And Chile is probably more marking and shipping for both basins, its more favorite into the Atlantic basin.
So we would long-term see Chile if we can get a couple of million tonnes in Chile that supply Brazil and Chile and the South American, Latin American market and we are in a very favorite position and we will very good rebate tax and that would be a good long-term sustainable position. So I think in a perfect rule that’s pretty much rule when we’ll end up.
Charles Neivert - Dahlman Rose & Co.
So I want to make sure, I’ve got this. So assuming nothing onto it on cost side things of that nature give more right now and client sort of just an enormous gasoline in Chile to move a second plant at this point and again borrowing something really different from the scenario that’s being played out basically it would seem to go.
Charles Neivert - Dahlman Rose & Co.
Yeah. I’m thinking a little bit of right on supply response, I mean it’s been I think the industry shipping after the sort of lot of the industries believing in this and balance is forthcoming on demand versus supply. The suppliers want to pretty needed thus far and I think your point initially there is even the larger competitor haven’t really responded yet. Certainly seen, I guess, lying down some of these announcements only attributable but why not studies, why not ethanol know seems to be looking?
All of the couple of comments and I will ask John to comment as well. If you look around the Middle East, most of the sketch is a short of natural gas. So that more, compared to more (inaudible) wants to go downstream that even grow basic chemicals, runs a lot of gas, so that’s what (inaudible) Iran. Iraq has got a lot of natural gas. So that’s not so easy either.
So all of the Middle East tends to be quite sure. Malaysia, you’ve got a couple of methanol plants, they have landed in all sorts of trouble running them. They have got upstream issues and they tend to favor LNG as well.
So one of the answer is as well as LNG prices in Asia at 15, 16 MmBtu virtually today, our release of natural gas in the Asia Percand we do which we have today owners of natural gas in the Asia Pacific region, we’ll prefer to try and make LNG rising to make methanol. And that’s what we found that time and time again, every time we go and look in Australia, the owners of gas we prefer to make LNG as opposed to methanol. John?
I would just tackle what everything Bruce said, but one think in addition I think when we look at relocation the payback is four years with spot gas, so why haven’t people been running to build plans in the U.S. with seeing the dynamic that we are seeing. I think they can’t get a long-term gas contract, so we are spending $800 tonne on capital plus and that gives you a 10 to 11 year payback, that’s a little bit more risky than what we would have in front of us.
I think that’s why you seen ideal capacity, we start that for modest amount of cap $100 million. Here you can see payback shortly but to build new still and make that commitment which could be four years from start to finish not knowing through adding four years more to your gas uncertainty about shales and to potential re-explore the LNG. I think it just the risk profile is too great.
I think if gas suppliers starts signing longer term contract, I would expect more production of methanol in North America longer term, but until we see that break I think it’s going to be more of the same and then versus already highlighted the rest of the world well there is cheap gas those in big Nigeria, Iran, Iraq very difficult companies to bony up a $1 billion for world scale plan of those geographies.
You are talking to lots of gas suppliers, if we find attractive about it about us 2015 stock rate almost everybody else where talking to -- is talking about 2018 or own stock rate?
So its fair to say when you guys work a little faith in all the other new interest or new potential interest that based are talking about millions of plans to have got we know company background capital.
Most of them that exclude (inaudible) let’s take that offline, but there are great customer of ours and we respect what they are doing. But most of the others what I called projects to get something started to resale it to somebody else, there are kind of like almost tinctures capital in someway all of the others. So I think they find it carve all together something that maybe they can then on sale. So will that be successful?
Could be. I mean we discounted something that might have happen in Trinidad years ago when we were proven wrong. So I never discount things that are happening throughout is the question is why hasn’t it happen quickly and I think that’s what we see and if you see something different we interest in your opinion.
Okay. So just going to back Trinidad on Bruce’s comment made, you feel more comfortable that really governmental suppliers things are better work. Are you talking now it’s going to be more reliable supplier or are we talking fuller re-negotiation of contract, are we talking like Titans got a new contract. You’ve made comments since lot of moving parts here, what exactly I think must we made earlier talking itself better now that things are going in the right direction there.
Well, firstly, is I think that’s been a process of digestion in Trinidad in terms of downstream and I referred as a government being the midstream because they have monopoly on gas deliveries and that contracting party. And then it’s obviously the upstream. So there’s been, I think contractual mismatch which people now understand better and it’s paying an economic mismatch as well.
And as seen in terms of talking to the upstream and even to the government, there is gas behind pipe today. And the reason that is not flowing is basically, the contractual terms have decide that the government in the midstream and they haven’t been and then send to for the upstream to maintain some buffer gas, if you will let us know as buffer gas or surplus gas that has hidden by from outages in the past.
The upstream is no longer providing that free of charge -- thing times now willing to tie little more for incremental gas to ensure that deliverability. Those conversation, I think it is starting to get traction and make progress. I think through that the government recognizes that through their production sharing contract that they have the ability to redirect gas contractually but they don’t have the infrastructure in place right now with the LNG plant a lot of the gas is directly to supply will be at the government gas.
I think the government now recognizes but that needs to create a little more flexibility in the midstream to ensure that gas can be more powerfully I think a portion through the gas consumption. And the final commentary I make is that from everything I have seen in terms of talking to the government. The government want to have understand that’s value chain is important but they want to participate in the value chain and out of the way that can do that is by ensuring a gas flows to all the players along the game value chain.
I think there’s been a period of Kea valuation and now we are into the period of action and its all expecting that what comes out of that is much more predictable environment going forward. I think the other point -- Bruce if you wanted to add something is that even that we’ve bought high lot of gas to offline if we speak today, there is a lot more coordination today and that we’ve got more advice of this gas cut offline and therefore the industry have organized itself to plan outages because that’s the impact is in place to deal anyone player right.
But I think that’s a positive sign as well and reinforce the people actually talking about the issue and collectively turn the results of the issue.
Okay. We are running out of time, if there was any waiting last question, happy to take it but otherwise we get it return to get in (inaudible)…
It’s probably we’d probably not like to comment too much. It’s for -- there is some commercial sensitivity around this. I would say is that if you put $400 methanol into your model and calculate a gas price based on the guidance we provided the numbers of that right you get to the right number that you really quite really how our formula works but there is nothing inconsistent with what we have in negotiation with relative to gas contracts we have in Trinidad and Chile and New Zealand, but it produces a similar answer.
On the (inaudible), can you remind, my memory is (inaudible) just being 80% of full range?
Yeah. It’s roughly Q1, 2014.
Necessary, 80% of full range. What do you mean by, in terms of hardcore cash are going? Sorry, we set out a full rate.
We covered 80% during the winter months earlier in the year.
Okay. We’re again have to start with the incremental 100,000 tonnes because you bought…
It’s not. Okay. So that’s 475.
Okay. Got it.
Okay. Well, thanks everybody. It’s been a full day. So, Jason, what do we do next?
It doesn’t seem to cover everything.
5:45, right. There is little bit of time for some R&I. Thanks, everybody.
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