LyondellBasell Industries N.V. (NYSE:LYB)
Bank of America Merrill Lynch U.S. Basic Materials Conference 2013
December 11, 2013 8:45 a.m. ET
Douglas J. Pike – Vice President, Investor Relations
Kevin McCarthy – Bank of America Merrill Lynch
Welcome back everyone. I’m pleased to welcome our next presenting company this morning, LyondellBasell. LyondellBasell as many of you know has got a $44 billion equity market cap, producer of petrochemicals, leading producer globally of products like Polyolefin and Polypropylene and the company has a crude oil refining operation and makes some other chemicals in the portfolio as well. Representing the company this morning, very pleased to welcome Doug Pike, Vice President of Investor Relations. So Doug, thank you very much for making the trip to Boston. We look forward to an update on the company.
Thank you, Kevin and thanks everyone for joining us today. I’ll try to take you through -- quickly through the company, leave some time for questions and a discussion. As you know, the company is -- the very focus is in the commodity chemical space around a fairly tight petrochemical portfolio. We’re in a position now where we’ve been enjoying the benefits of U.S natural gas versus global oil. Most of our production costs are driven by gas-based pricing while our products are really driven by oil-based pricing, which have been a strong driver for the company. For us then it’s in a situation of taking advantage of that opportunity which we’re doing both through the focus on operations and a drive to expand these assets and move forward. So let me take us through a little bit of a discussion here. First of course we have a cautionary statement and I’ll skip forward through that. We will be using EBITDA and other non-GAAP measures in the discussion so just to give you a heads up on that.
But let’s look at a couple of company highlights. When you look at our earnings and EBITDA, the company has been moving forward and growing earnings. Income from operations over the last 12 months about $3.3 billion, bringing us to shy of $6 in earnings and about a little over $6 billion of EBITDA. One of the things I want to point on this slide though, when you think of a large commodity company, you might not think of the steadiness and stability that we’ve been seeing of earnings. If you look at our EBITDA or income from operations, you see pretty steady performance over time. There’s some seasonality in the company. You’re going to see that typically in the fourth quarter. You’ll see that as buying patterns slow down in some of our businesses for holidays of some of our customers, holiday time. You’ll also see it in some of our products where raw material costs tend to drive up in the winter a little bit. So you’ll tend to see that type of seasonality.
But beyond that we’ve seen a very steady performance and with that, very strong cash flows. So if you look across the company, we operate in five segments. You’ll notice the blue bar which is our Olefins and Polyolefins Americas generating about $3.5 billion of EBITDA over the last 12 months. You’ll also notice another area of the company that some -- that people don’t talk about maybe quite as much, our Intermediates and Derivatives business. I’ll talk to that a little bit today. This is a downstream chemical business where we operate proprietary technologies in Propylene Oxide and Acetyls, generating about $1.5 billion of EBITDA.
It’s a business that again benefits from a combination of things from a proprietary technology position, but also benefits from the same oil and gas opportunities in some of its products. Now where we do operate in the petrochemical space typically you see on the right hand side, we’re in the top five globally. So while LyondellBasell might not be a name that you hear in commercials or in the public space, it’s a name that within the industry typically operates one of the top positions where it operates and where we focus.
Now I mentioned cash and I mentioned cash generation. Now one of the keys for the company is the area of the cash deployment. With our cash generation and cash from operations running up in the $4.5 billion, $5 billion before CapEx, how will you put that cash to work? That $1.5 billion goes into our CapEx program with about half of that being near term growth opportunities and driving debottlenecking to take advantage of the market environment. That leaves us with significant amount of cash being directed towards our dividends. Over the past couple of years we’ve increased the dividend. We established first a base dividend, have increased that now to $0.60 a quarter so $2.40 a year to about $1.3 billion or so in annual dividends, leaving the company with again substantial free cash.
In our first years of being a public entity, we were limited in how we could use that cash and we used it through special dividends and paid two very large special dividends. Now we’re in a position where share repurchases is an open opportunity to us. We have an authorization for about 10% share repurchase. We’ve been working that since late May since the shareholder authorization in late May and since then have bought back a little over 3% of the shares through the operation. So that’s where you’ll see us really with moving our cash and where we’re moving forward with the cash deployment opportunities.
Let’s talk about the businesses. These five segments, each has somewhat different characteristics and with that, different strategy in each of these segments. In North America in Olefins and Polyolefins business, this is the business that has the strong advantage from natural gas liquids. We crack a lot of ethane, convert that to ethylene and into polyethylene and then into the world market for world market pricing. It’s a business where you have very strong margins today and where you have a cyclical upside. This is the business we’re investing in.
Now in Olefins in Europe, Asia and International, you’re in a different environment. Here your raw materials is a crude-based material primarily. So in the commodities there where we’re naphtha based, we’re restructuring. What we’ve been doing there is restructuring the staff in Europe. We’ve been closing some polymer assets over time and changing our approach to market and our approach to raw materials. So we’ve gradually been increasing the percentage of our raw materials that are advantaged from a standpoint of their end becoming more and more NGL-based. But this is a business that also has strong differentiation. People tend to associate the business with Europe and with naphtha cracking, but a large percentage of the profitability is generated from joint ventures in regions like Saudi Arabia and Asia where you have a raw material advantage. So about two thirds of our EBITDA generation comes in this business from a differentiated platform and I’ll show you that a little bit later.
I spoke a little bit to Intermediates and Derivatives. Again this is an area where we’re investing and where we want to grow that type of product, that type of base off of our proprietary technology. And then a fourth area of the company is we do own one refinery. We own a refinery on the Gulf Coast. It’s a heavy refinery that can process heavy crudes out of South America or Canada and this is a business really where we’re now in a position as the crude market and the crude transportation markets evolve where we anticipate we’ll be seeing more advantaged crudes.
It’s been a difficult business for us frankly over the last year, but it’s a situation we think is emerging and moving forward. And then we have a business that maybe people don’t associate with so much a technology business where we license our technology, where we produce catalysts for those technologies. It’s in the Polyolefins area with typically about 30% market share. This is a strong business. It generates a couple of hundred million dollars of EBITDA annually with about a 45% EBITDA margin. So it’s really a specialty business hidden really to some degree within our commodity company.
So let’s talk about the background. Really the driver as I said has been crude oil versus gas and what you’ve seen is a fairly steady situation since 2010. Crude oil has been around the 100, 110 mark. The key is Brent crude. That’s what the competitors around the world are producing their ethylene from. And then in North America it’s about natural gas and the natural gas pricing around the $4 range. On the right hand side of this chart to take a quick look at how ethylene produced is around the globe and what the cost curve looks like. And what you see is about 40% of world ethylene is produced from natural gas liquids. That’s really the Middle East and that’s the U.S where you’re producing products for $0.10 per pound or less. But 60% of the world’s ethylene continues to be produced from naphtha so a crude oil based material.
And the production costs in these facilities typically around $0.50 a pound. So what you find is the Middle East, North America have become price takers, selling their products based really on about a 50% production cost elsewhere in the world and benefiting from the profit, the differential margin difference of about $0.40 a pound. This really comes from the shale gas and the value chain across shale gas. And if you look over time, what you’re really seeing is there’s been a shifting range of where the value in the gas market is. Chemical companies such as us become natural beneficiaries. What we’re really doing is we’re taking a regionally priced raw material in the form of ethane -- little ethane in particular or natural gas and we’re converting that to a world price material based on crude oil. And if you look -- as you look across time, across from 2005 forward, what you’re seeing is the profits have gradually shifted downstream to the point now where the chemical companies are sitting in the enviable position of having that benefit.
This really just shows you the same trend a little more specifically. What I’ll draw your attention to is the cost of ethylene production on the right hand side of this chart relative to the U.S ethylene price. I think it shows you very clearly how northeast Asian, the high cost producer in the world really has been setting the price and setting the price in North America, while you see our raw materials butane, propane and ethane have been declining as the shale gas development and the infrastructure has come forward in the U.S. So this is really they’ve set the basis for that profitability in our EAI division.
Now is that going to stay? We’re going to see that going forward. We feel increasingly comfortable that the shale opportunity has really developed to a point where you’ve seen ethane availability, our key raw material, has been increasing and very strong supply. I think you’ve seen relatively an evolution of thinking here. A year ago or so the thought might be these with expansion plans by 2017 or 2018 we’re going to be consuming the available ethane, but the strength of the shale development, the strength of the technology progress in that area I think is increasingly getting people more and more comfortable that this is a trend that’s going to continue on, that there’s ample ethane supply in North America and we’ll see that continue to support the company’s advantage.
Now, ethylene business is when you typically consider cyclicality is really the key thought. When are you in trough? When are you in peak profitability? You typically need operating rates globally to move above the 905 effective operating rate level. Somewhere in 90%, 93% tends to give you pricing power. This is an area of some confusion for some investors because they look at the strong profitability and you tend to assume the ethylene industry in the U.S is really operating more in peak conditions, while in reality what you are is on a global basis, the high cost producers in a trough is a barely breakeven standpoint. But when you look forward you see supply demand beginning to tighten up and we’ll see how it lifts. We’ll see whether we get that cyclical lift that we’ve historically seen within this industry. It remains to be seen, but it looks favorable to us right now and we’ll see how global economy develops, whether it pulls us forward to that level.
So what are we doing around it? What we’re doing around it is we’ve been shifting our raw material mix. If I stood here four or five years ago, I would tell you we were cracking naphtha in the U.S for about two thirds of our production based on naphtha or crude oil. Today as I stand here, about 90% of production comes from natural gas liquids and off of the shale gas opportunity. We’re also expanding our assets. We’ve got about a 20% expansion program underway and this is a little bit different approach than some other people. We’re expanding our assets through debottlenecking. This allows us to bring those on over the next two years and bring them on at low cost. So we’re a little bit ahead of what we see as a tightening construction phase in the Gulf Coast of North America and around these. So we’re ahead of most of that tightening scheduling, meaning we can move faster and at lower cost.
Lets’ switch. I talked a little bit earlier about our own PEIA division and I talked about that really you should think of it in two different types of businesses. There’s a differential component of this business which I represented here in the darker blue and you can see profitability there has been pretty steady, pretty stable over time, independent of trough or peak conditions within the industry. And if you look at 2012, 2013, you see that’s been a pretty steady performance. That’s around $500 million plus or minus of EBITDA generation coming out of joint ventures in the Middle East, coming out of differentiated polymer products. Now the commodity piece in Europe has been a tough business and you can see that, although we’re generating positive EBITDA and positive cash flow out of those businesses. I don’t think everybody in Europe could stand up and say that today. It’s been running roughly around breakeven, slightly above breakeven for many.
So how have we done that? Our effort’s been really around restructuring our costs, restructuring our asset base and more recently, restructuring our raw material base. In the area of raw materials, over the past two quarters we’ve been able to swing our raw material base from being naphtha, almost 100% naphtha generated to now about 40% of our ethylene is produced from what I would call advantaged materials such as propane or butane. Now the advantages there aren’t to the scale that you see in North America, but they bring forward that extra penny or two and that’s what generates profits when you’ve got a 4 billion pound industry. A lot of this is about can you operate well and generate an extra penny or two because the multipliers are great. So we’ve been able to operate our assets in Europe over the past quarters about 5% ahead of industry average and we’ve been able to shift that raw material mix. And it’s really a focus on operations and restructuring for us.
Now, the I&D business is a business I said includes both proprietary technology and also advantaged raw materials in terms of NGLs that you convert into crude-based gasoline type of components. Really drives primarily off of Propylene Oxide, this PO business. And what you see on the bottom left is the profitability within this segment. Essentially all the profitability benefits either from the proprietary technologies or it benefits from a combination of proprietary technology and this natural gas advantage. Propylene Oxide being the key product, we operate two different technologies here. On the upper right we’ve tried to put the different technologies used to make Propylene Oxide into perspective. We operate as I say where we produce a co-product with Propylene Oxide. In one case, it’s tertiary butyl alcohol. To make that complicated chemistry simple, ultimately we convert it to high octane gasoline. So we’re taking natural gas, converting it to high octane gasoline. In the other process, we produce another chemical. We produce Styrene from that business. But we think these are two of the lower cost ways to produce Propylene Oxide.
On the lower right in this, you see a history of -- about a five year history of margins in Propylene Oxide and one on the Propylene Oxide derivatives. In the industry structure, the technology based on it has enabled it to stay as a very steady strong profit over time. So what you see is the profitability in I&D benefits from the steadiness of the profitability here from Propylene Oxide and its derivatives. But then because of our production of other chemicals and then the co-products in this segment, we’re benefiting from natural gas to oil opportunities. On the bottom left you see the spread for those oxyfuels, the gasoline components that we generate. You can see how the shale opportunity as it’s lowered the cost of your raw materials and you’re selling into a gasoline market has seen a significant improvement in profitability. We’ve seen that going forward.
And then also we’ve seen methanol, another product that we have in this business in the acetyls chain where that profitability has moved forward also in that way. What are we doing to capture this? We’re in the process now of restarting a methanol facility that had been shut down when natural gas prices were high. We’re bringing that forward now. That startup is underway as we speak and it’s part of our overall capital program to quickly capture the value between crude and natural gas.
Now refining, the fourth segment I spoke about, refining has been in a pretty tough space over the past year, but it’s a space where we’ve spent the last year and a half really preparing for change. Much like in the natural gas area and in the shale gas area, the bottlenecks have been around transportation and infrastructure development to a change in hydrocarbon environment. But you’ve seen a much similar thing in refining. We have a refinery that can process heavy crudes. So most of our raw materials has been derived out of the South American producers. Venezuela, Columbia, Mexico have been our primary source of raw materials. What we’re looking forward to now is as pipelines from Canada are coming in to completion, we’re gradually moving crude down to the Houston Gulf Coast area where we can begin to take advantage of the discounts that you’re seeing today. Canadian crudes are heavily discounted. Selling prices have been $55 to $60 a barrel. Transportation costs are about $10 a barrel to bring that to the Gulf Coast and we’re again sitting where we’re a natural processor of these materials.
So we’re looking forward to an infrastructure that’s moving forward rapidly, bringing to a completion the ability to access and process more of these in the Gulf Coast. Of course the refining industry in the U.S has become a large exporter. Sitting on the Gulf Coast you have the opportunity to export your again North American sourced materials off of North American priced raw materials into a Brent pricing world and a Brent pricing environment. And so that’s really where we see things moving forward and what we’ve prepared for at the refinery. You’re not seeing those opportunities quite yet. I think we’ll see that as we move through next year those will develop strongly.
So I spoke a little bit about cash deployment. When you look in the company, our base CapEx needs are about $700 million to $800 million. Above that now we’re spending another $750 million a year for growth CapEx for debottlenecking for bringing on things like the methanol plant. Dividend is about $0.60 a share per quarter. It’s about $2.40 a year. We’ve moved it up to that level. We feel like that’s a very comfortable level for us through ups and downs within the industry. And then the balance of our cash flow has been really moved back to the shareholders, back to our owners as I said in the past through special dividends, now through share repurchase.
The growth opportunities and improvement programs within the company, we think based on conditions that we’ve seen over the past 12 months, I’m not trying to forecast a change in the industry and in the profitability within the company, but just looking backwards and applying that to the growth programs we have, we think we can add about $2 billion to EBITDA or to our pretax earnings. We can do this really over just the next couple of years. So we’re not talking a program that you might see in five or six years. We’re talking about a program you’re really seeing now.
These are some of the projects that are underway and what you see here is thus far we’ve brought on about $200 million in pretax earnings of projects, mostly through logistics, mostly through improving and increasing how much ethane we can process within our plants to capture that differential. Now we’re into a phase where you’re going to see expansion of capacity coming online. As I said today, it’s the methanol plant that’s starting up. At current spreads in margin, that should be worth about $250 million annually in EBITDA. The next steps is middle of next year we’ll be starting up an expansion of our ethylene capacity of about $800 million pounds. That will be followed in six months later by another ethylene expansion of about 250 million pounds and then followed at the end of 2015, in late 2015 by a third capacity expansion of another $800 million pounds of ethylene capacity. These are all great projects, very high return. Really what we’re doing is we’re debottlenecking existing assets.
This capital program maybe has a little different cash profile than those that are taking the route of building new ethylene plants. New ethylene plant complexes typically take five to six years to build and complete. They typically are in the $5 billion plus range is the estimates that you see versus our program. What it really means is within our program as we’ve picked up our capital expansion, our capital program, the earlier projects that we did are now generating cash and those are beginning to support the spending the $750 million of spending today. So we’re in a program that really is a cash flow positive capital program.
So let me just wrap it up a little bit. So how do we look at the company? How can you look at the company going forward? We see ourselves at current market conditions as a company that can generate approximately 35% increase in our EBITDA at current market caps. And if you apply that at current multiples, we see that type of growth potential in our earnings and our share prices. But we’re doing it, at the same time we’re generating additional cash. So it’s a combination of cash and earnings growth at the same time. How will the cash be utilized? At this point in time the program really is through the dividend, through the yield that you get through the dividend. Over and above that we can generate two -- up to say $3.5 billion, $3.25 billion of cash above the dividend after tax which as I said right now we’re in the share repurchase program with a 10% authorization and moving forward where we’ve moved forward with a little over 3% share repurchase over the third quarter and ending month of the second quarter.
So strong cash generation. At the same time an ability to grow earnings. This will enable us to grow earnings from the $6 range to over $8 range and that’s that turn industry conditions. So that’s before you consider the typical things you think about in petrochemical industries of cyclicality and earnings growth and the leverage of a system that is about a 17 billion pound ethylene system overall around the globe.
So with that, I’ll stop talking for a while and take some questions.
Great. Thank you. If anyone has a question, please raise your hand and Wendy will bring a microphone right over to you. Just to kick things off, I thought I’d ask you about methanol. That market has been extremely strong lately. Perhaps you could comment on (NYSE:A), what is driving that in your view? (NYSE:B), where exactly you stand with the restart here. Is it running or is that still on the come?
Sure. I want to talk about methanol a little bit. The methanol market has been strong and really it’s -- the end market is being driven by methanol use in gasoline through various ways. One of the ways is MTBE, which we produce methanol, convert methanol to this oxyfuel and a blending component. So you’re essentially changing gas to gasoline. Operating issues have helped strengthen things in very near past months, couple of months. But it’s been a strong margin situation even prior to that. So it’s a well-positioned product for us and for the industry right now. In terms of our startup, we’re in the process right now of startup.
We convert -- we turned the project over from the project group into the operating group just a few weeks ago. So they’re in their normal startup process. As we go forward, I think you can anticipate that this plant will be started up and running this year and we’ll phase it in in the first quarter and really step up operating rates and move forward for that business. We’ll be moving the product really into the merchant market. And of course the U.S has been a strong importer. Most of our methanol is through imports at this point in time. So we’re really in a system where it will be displacing imports with our production.
Can you talk about the status of the permits for your projects? Are there any projects where you’re missing a permit or you’ve experienced delays?
Sure. Thank you. The question was around permitting for these new projects. We have work permits for all our projects except one. Our Corpus Christi ethylene expansion we approached a little bit later. We started out a little bit later. So we’re in the permitting process for that at this time. Typically what we’ve seen is our permits have received in about a 15 to 18 month period. That frankly is within what we had expected when we started the process. So we applied for typically -- our permits were applied for very early and we were able to receive those and be pretty high up on the order, pecking order as the EPA has gone through the permitting process. So we’re under construction really in all the projects I showed you with the exception of Corpus Christi at this point in time. and I think what that’s doing for us is it’s putting us ahead of the labor squeeze that we anticipate in the Gulf Coast and they put in the shops ordering the equipment early and ahead of any squeeze in shop availability. So we feel pretty good that all our projects are on schedule. Costs have moved up a little bit because labor rates are up in the Gulf Coast, but I think we’re going to finish those before you tend to see a 2015, 2016 peak in the demand for crafts and labor in the Gulf Coast.
Doug, with regard to Europe, you mentioned a bit about how your feedstock mix is changing. I think you said 40% now from propane or butane. I guess couple of small questions there. Can that number continue to move higher? Or is this about it for now? And just on propane in general, we’ve started to see rising exports from the US. Does that make any sense for your locations where you’re really bringing it in from elsewhere like northern Africa?
I think you’ll see that concentration of advantaged raw materials gradually increase. Really what we’ve done over there is I think our folks have been able to shift their mentality from consuming what’s on site which is the typical operating process of a European producer. So typically it will be a refinery based raw material. You consume it on site in the ethylene plant. We’re really more mixing the flexibility and the approach towards flexibility that we’ve utilized in the Americas for years and bringing that to the facility, particularly our facility in France. We have a cracker in the South of France that sits on the Med. That gives you waterborne access to raw materials which I think brings us the propane question of where do you source propane and where do you source these materials from? Now you’re really talking a commodity. The availability of the increase in propane supply out of North America is increasing the global supply. Typically we’ve sourced actually from North Africa, but the pricing of whether it’s U.S based or North African based propane is going to really be the same. So here again it’s the U.S resource putting some pressure on a global market and us being able to take advantage of that at the site.
So five years ago North America was shutting down crackers. Today we have NGLs as far as the eye can see and I wonder in five years whether we might be able to say the same thing about condensate and naphtha. What do you think about that?
We are seeing growth in condensates, the doors coming off of the same wells and the same shale play. Part of what we’ve done is we were a company that five years ago was importing roughly 65% of its raw materials from North Africa. Those have been replaced really completely. Most of the replacement has been with NGLs, but also we do crack liquids in our system. About 10% of our ethylene is still produced in North America on the liquids from these condensates. So what we’ve done is we’ve moved from imported condensates to North American based condensates. There is a cost advantage to doing that. There’s also significant logistics advantages. You’re not shipping. You don’t have that waterborne movements.
And basically we’re just taking Eagle Ford condensates and bringing those into our plants in Texas where we do need liquids. How is that going to evolve? We’ll have to see. I think you’ll see increased availability of condensates. You’ll see some find their way into gasoline streams. Some find their way into Olefin plants. But really the most advantaged raw material in North America has been and we anticipate will remain ethane. With it pricing near its natural gas value. So if you think about our expansions expanding roughly 20% in North America, it’s really all based on an ethane based expansion for us. So that’s been our focus and I think it will continue to be.
Can you just talk about the refinery position? What are you taking as byproducts off the refinery? How important is it to your overall system? And do you really need to own the asset with an issue of you don’t need the cash really so what are you going to do with it? Do you continue to run it or can you help us understand that?
Sure. Our refinery has been generating over the last four years on average about $500 million of EBITDA. So capital needs are a couple of hundred million dollars. So it’s generating cash for us over time. It’s an asset that we’ve been making a significant amount of changes to, an asset in which typically you process heavy crudes as I said out of South America. We’ve made modifications to improve the flexibility to process lighter domestic crudes if the economics drive you in that direction, increased our sulfur handling capabilities, increased our NGL handling capabilities there. There are interactions with the Olefins business. A refinery like this is a large hydrogen consumer. An ethane cracker is a hydrogen producer. There’s a natural fit there and we’ve got a number of pipelines linking our Olefins system to our refining system. There’s also streams that periodically go the other way, from the refinery over to the Olefins. It’s really an optimization of what fits best and how do you go and we do that typically on a regular basis with LP models between the facilities. You also find gasoline streams go from your chemical operations into your refinery.
So there’s certainly an interaction there and the skills to operate a refinery. Again it’s about large process equipment, instrumentation, et cetera. So there’s a lot of interactions and connections with the facilities. Having said that, does that have to be accomplished through ownership? No. I think we have flexibility and it’s a value picture for us. What’s the best value for that refinery? Is it our ownership or is it through other ownerships and opportunities? But our focus, let me be real clear, our focus and the focus of Kevin Brown who runs that unit has been to open up the flexibility of the refinery, open up the operating window and position us as the industry changes so that we can do much like we’ve done with the ethylene space, take advantage of the raw material opportunity, operate it well, strong operations and generate cash from it as a cash generation for us. And we’ll see how things develop over time. But it’s really to maximize the value. That’s really what our job is as the management of the company.
Just a follow-up on that in the final minute that we have. Can you just address how your crude slate is changing? You referenced the pretty heavily discounted Canadian crudes right now. It used to be we'd look at Maya 211. I think that’s maybe getting a little bit more spurious. So how much Canadian crude can you crack do U.S --?
Our crude slate used to be and it was designed, if you go back a decade it was 100% heavy Venezuelan, 17 gravity Venezuelan crude. What we’ve done in opening up that facility, we can probably process 30% or so of the crude. It could be Canadian crude. We could probably process to about 50% light crudes in the refinery through blending. So we will take advantage of the changes in the North American market. Now, today where are we really? The Canadian crudes aren’t widely available in the Gulf Coast. There is some. So we are processing typically 10% plus or minus of that crude. Heavy crudes and light crudes are going to compete with each other. So what we’re going to process is going to depend on how that competition works through and how heavy crude suppliers price themselves versus light crude. Once pipeline networks move forward to the next step, and I’m referring to really the Enbridge system, Flanagan South, and then below that you’ve got Keystone South and Seaway bringing material from Cushing down to Houston. As those evolve and emerge, we anticipate we’ll be picking up the percentages of Canadian crude that we’re running and begin to take advantage of some of those discounts that you’ve been seeing recently.
Great. Thank you very much for the attendance and the presentation, Doug. Appreciate it very much.
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