Good day, ladies and gentlemen, and welcome to Imperial's Fourth Quarter 2018 Earnings Conference Call. At this time, all participants are in a listen-only mode. Later we will conduct a question-and-answer session and instructions will follow at that time. [Operator Instructions] I would now like to introduce your host for today's conference, Mr. Dave Hughes, Vice President, Investor Relations. Sir, you may begin.

Good morning, everybody. Thanks for joining us. Just before we get started I'd like to introduce who we have here in the room. We've got Rich Kruger, Chairman, President and CEO; John Whelan, Senior Vice President of the Upstream; Dan Lyons, Senior Vice President of Finance and Administration; and Theresa Redburn, Senior Vice President of Commercial and Corporate Development. I'm also going to start by noting that today's comments may contain forward-looking information. Any forward-looking information is not a guarantee of future performance, and actual future financial and operating results could differ materially depending on a number of factors and assumptions. Forward-looking information and the risk factors and assumptions are described in further detail in our fourth quarter earnings release that was issued earlier this morning, as well as our most recent Form 10-K, and these documents are available on SEDAR, EDGAR and at our website. So I encourage you to refer to them. Rich is going to start making about 20 minutes of remarks or so, and then we'll turn it over to Q&A. And as we've done before, we did offer the opportunity to folks to submit questions ahead of time. We did get a couple of questions. So we'll probably go through those first and then switch over to the live Q&A. So, with that, I'll turn it over to Rich.

Good morning. Before I detail the fourth quarter and the full year Imperial results, I'd like to offer a few comments on the overall business environment. Stepping back, if you look year-over-year, we saw WTI increase by about $14 a barrel. It was $51 a barrel, round numbers, in 2017. It was about $65 a barrel in 2018. WCS or Canadian heavy on the other hand was flat in both years, at $39 a barrel. So set differently, the differential increase to the full extent of the WTI growth, a really sovereign phenomenon for Canadian heavy oil producers who haven't enjoyed that, what you've seen in terms of the global price growth. I'll come back to us here in a moment. Now more specifically to the fourth quarter, I would characterize it by even higher price volatility with the largest WCS/WTI differentials that we've seen at $40 a barrel. And also Canadian light differentials blew out with MSW trading in the quarter, $27 below WTI. Now all that said, given the differentials, Imperial -- our corresponding financial results illustrate the competitive advantage of operating under an integrated business model with a uniquely balanced portfolio across the value chain. Balanced in terms of roughly 400,000 barrel a day Upstream production, 400,000 barrel a day of refining throughput and some 500,000 barrels a day or so of petroleum product sales. With widening differentials, our Downstream benefits from price advantaged feedstocks, while our Upstream realizations with lower -- absolute prices are adversely impacted. However, we partially offset that by a series of advantage logistics. Now, of course on December 2, the government of Alberta took an unprecedented action of intervention in a free market, by imposing mandatory Upstream production curtailment effective January 1. The order to artificially withhold production resulted in the immediate…

Okay. Thank you. As I mentioned at the outset, we did provide the analysts an opportunity to pre-submit questions. So, we do have a couple here and we'll start with those and then we'll go over to the live Q&A. So, the first question was from Mike Dunn of GMP FirstEnergy. How was mandated curtailments in Alberta impacted Imperial's previously stated plans to ramp-up crude by rail volumes in 2019 from approximately 125,000 barrels a day in Q4 and your hopes to eventually use all of the terminal's 210,000 barrel a day capacity?

Mike thanks for your question. The -- our Edmonton rail terminal utilization -- maybe step back context. We -- the industry saw crude by rail increasing dramatically at the end of the year with the incentive to move crudes to the U.S., in particular, Texas, Louisiana, Gulf Coast, highest-value market and we're -- for the last several months, we're exceeding 300,000 barrels a day. We were a big part of that ramp-up after the first nine months of the year where we averaged round number 75,000 barrels a day in facility utilization in October. We bumped it up to 117,000 in November, we were at 153,000 and at December, we were at 168,000, a full likely a bit -- around or a bit more than half of the full industry crude by rail utilization. We averaged -- doing the math on that, 146,000 barrels a day for the quarter and that was above what we had communicated earlier we thought we would achieve. And that was all good because of the big differentials and the tremendous incentive to provide takeaway capacity by rail. We were also on plan for the first quarter. I think we had said something that we expect in the first quarter 170,000, 175,000 roughly. We were on plan on track to achieve 180,000 to 190,000 of the facility's full utilization 210,000 barrel a day capacity. So, all that was unfolding perhaps a bit better than we said. Today, the differentials have collapsed and the incentive to move crude by rail has been erased. It's negative. It's uneconomic to move crude by rail at this point in time. So, unfortunately, we are ramping down rapidly in the month of January. I anticipate -- I think our average will have been about 90,000 barrels a day, half of what we had targeted in February. With current conditions as they are in differentials, we expect to be at or near zero. I think this is a great -- the implication is that crude by rail should be helping to alleviate this situation in the province. But now because of the drastic, dramatic, manipulation and impact and differentials takeaway capacity is now being idled. That is a sad state. A very tangible example of what we believe is ill-advised, ill-informed negative consequence of this curtailment order. I can't say it and describe it any other way. So, thanks for your question Mike.

Okay. The next question is from Phil Skolnick of Eight Capital. Were you one of the only seller of crude to Valero in the U.S. Gulf Coast by a rail in Q4? And are the Venezuela sanctions making you look to increase your rail efforts today?

Well, I take that kind of the reverse, and the heavy crude demand in the Gulf Coast is high. And if you look at their traditional supply sources whether that's Venezuela or other sources, there is less supply from traditional sources. And that makes Canadian heavy highly valued. And that is the optimum, the best market for Canadian producers to strive to get their crude to. So we have contract pipe commitments that we've talked about roughly 100,000 barrels a day that allows us to get there. And then, of course, our rail terminal was the other major mechanism to get to that market. So that still remains the best market. We want to get there all, but we need to get there in an economic manner. And I just commented on rail. So that we've kind of had one leg taken out from under us on that, but still getting barrels there is the right thing to do. Now rather – specifically to who we sell to, we typically don't talk about the commercial dealings of who we sell. We give prices and volumes, and see I think you know who they -- the big consumers of heavy are in the Gulf Coast. And any and all of those parties are, customers are but we typically don't detail specific customers and certainly not volumes to any particular customer.

Okay. So now we're going to turn it over to the operator to initiate the live Q&A.

Thank you. [Operator Instructions] Our first question comes from Manav Gupta from Credit Suisse. Your line is now open.

Thank you guys for taking my question. A quick question on Aspen. You guys planned clearly well ahead. And by 2022 you should have KXL and you have capacity on it. So and should not be issue at Aspen at all. But just in case that there are some delays at KXL again, what's the back up plan to get to the Aspen volumes out of honesty?

I appreciate your question. It's very timely question. And just reflecting on Aspen, it was five years in the making from a regulatory review and approval standpoint. We're excited about the technology, the economic and environmental benefits that come with it. We like a bit of a countercyclical investment timing, when investing, when there is a lot of industry capacity and things. But I will tell you that as we funded Aspen last year, the uncertainties around pipeline market access were there. Of course, Line 3 was progressing. If there were still some issues to be resolved, Keystone XL has to prevent -- the challenge in Montana and the case in front of the Nebraska Supreme Court. But those are moving. They're difficult to guarantee or predict outcomes on it. But we knew eyes wide open that we have uncertainty around material new expanded market access via pipe. And underpinning Aspen, our ace in the hole was our rail terminal. It was we were using less than half of its capacity with our base business in the normal operation. I commented on the first half of the year. So, the rail in our – in the wide range of scenarios that we look at before we make major commitments. Rail was our backstop, or you've heard me describe it as our insurance policy for future growth that went with Aspen. At Aspen, at 75,000 barrels a day with diluent, it's roughly 100,000 barrels a day at dilbit and that's – we had spare capacity on the order of that amount. Now the curtailment order, it's introduced a new risk and a new uncertainty. And we can say, well, yes, but in short-term and things like this. Let's see. Is it short-term? I don't know. So what we're doing is we…

Thank you so much. I have a very quick follow-up. Do you have any insights or any color you can provide on Enbridge Line3? What are you seeing over there? Any possibilities of delay? And the reason is I'm asking this is, because I -- we agree with you that government should not pick winners and losers here. And there's a possibility that, if Enbridge Line 3 is on track than the government might fully rollback the cut. So that's why I'm asking the question.

Yes. I think you bring up a good point in it. Get to Enbridge Line 3, but if you're -- what we're looking at right now in the marketplace to give us confidence in whatever expenditures are growing. Well, certainly the curtailment situation how it unfolds. And we're literally only a month into this. You saw differentials collapse from well beyond rail parity to now differentials are at pipe clearing in rails not economic. Do we start to see as the government relaxes curtailment? Do we see those differentials move back into where rail incentive for clearing by rail now is incentivized again? That could happen. So let's -- we'll see that over the few weeks. The political situation, just the workings of -- intervening pre-market is not an easy and as definitive as we thought. Do we see further intervention? Do we see less? Do we back out of it? Line 3 is a key one. The approvals are largely in place, but it's not across the goal line yet. There's a lot of construction in -- certainly Wisconsin, the Canadian side, a bid in North Dakota bid, we've got Minnesota that were -- is the last piece of that puzzle and then Keystone XL. So all of these things are the things that we're paying very close attention to, so that as we develop our business plans, not only short term but longer term we do that with eyes wide open and the best understanding of what risks and uncertainties and value is there for us. So Line 3, a lot’s been public on what is going on, on it, it Enbridge I think the latest we’re talking about is the target of having an operation at the end of the year. We are certainly supportive of that. Line 3 will help in this with the incremental capacity nearly 400,000 barrels a day. And I don't have anything that I would add other than what Enbridge already says. So I think that's the current target. But they're not out of the woods yet, in getting some of the final resolutions they need in the state of Minnesota. Some construction permits and some things, I believe after the Public Utilities Commission has provided the necessary approvals, there are still some other things they require before they can start laying in well and pipe. And we'll pay very close attention to that. And it will be a real good barometer of the timing of a material new addition to market access capacity above and beyond what the potential of rail is.

Thank you so much for taking my questions.

You’re welcome.

Our next question comes from Emily Chieng from Goldman Sachs. Your line is now open.

Thanks Rich. My first question is just around Syncrude. It delivered a very strong quarter production in the fourth quarter. I guess how sustainable is this going forward? Can you talk a little bit about, what were the past cultural changes that took place that drove that strong production? And just on a slight tangent but still on the Syncrude, there were reports from Conoco yesterday around same on perhaps looking for alternate sources of diluent this year. Has that got any impact on the way Syncrude needs to market its product?

Emily, I look forward to the quarter when I can say was there. And you can expect this from Syncrude each and every quarter. And so many times over the last several years when have had strong quarters which we have I've been tempted to say that. And I've learned that, it's a never-ending challenge. Now that said, there is no question that we are seeing fundamental structural improvements in Syncrude over time with the introduction of best practices, the support of Imperial ExxonMobile and now increasingly Suncore. So the identification and addressing what have been some of the root cause challenges in many cases particularly associated with the upgrading, the cokers. So we both -- we continue to believe we're on the right path. And we see a quarter like the fourth quarter. That does give us a lot of confidence going forward that things we are collectively doing, the ownership we're doing are the right things. But then I go back to June 20th and the power outage we had and we didn't see that coming also. So it's hard to make promises and all. But our -- what we have seen and what you said is we see Syncrude as -- our share 75,000 to 80,000 barrel a day kind of an annual average as they have varying degrees of turnarounds and maintenance work that continues to be what we expect. And as we look to the New Year 2019, that's when we have in our business plan. And I think all the actions are supporting that progress. Now, specifically, the marketing of the product, again, it's kind of like the earlier question. I don't tend to get into that. What we do is we're always looking to get the highest value for any production. And on the Downstream side, we're looking to get the most prized advanced feedstocks, so if there are opportunities here in the market with you mentioned ConocoPhillips with some more or others. And that affects what we can do or provide to maximize value of Syncrude, that's exactly what we will be doing. But I'm not coming in specifically on that one. One, I don't know enough about it right now, but we're always looking to get the highest value wherever we can in the marketplace for anything we produce.

Appreciate the color. And just one follow-up, on the share repurchase program in light where the macro environment is today. And then coupled with the spending levels that are associated with Aspen. I guess, what is a reasonable run rate to think of going forward, knowing that you guys are still -- when you sanctioned the Aspen project that was -- you guys can think that it was in conjunction with the capital allocation program that you had?

Yes. Emily, fair question. And what I've said before is, we would not -- a year-and-a-half, almost coming up on two years, we would not have reinstituted a share buyback program if we thought it was going to be something that would be short term in nature. Now we've also said that, if you look at our capital allocation strategy and kind of that pecking order I described about paying -- strong balance sheet, the dividend, quality investment, sustaining CapEx, we've always looked at the share buybacks as kind of the flywheel to go up and down if and when we have surplus cash. But now, if I get -- and I take the environment today, this year we generated about -- just shy of $4 billion. WCS was $39 a barrel. I'll get to differentials in a minute. Last year, at 2017 WCS was $39 a barrel. And we generated just shy of $3 billion. So, the storyline in the year were differentials and what that did on our Downstream in 2017, the differentials, the heavy-light differential -- excuse me, the Canadian light differential was $3 or $4 a barrel, the WCS was $12 or $13. That was 2017. And we generated $3 billion. In 2018, those differentials were much bigger, we generated 4. Whereas if I look today, or literally yesterday, WCS $44 a barrel. The Canadian light differential about $4. The Canadian heavy differential about $10. So all of that is about where we were in 2017, when we had strong Downstream performance we had strong Upstream cash generation. WCS is a bit higher today. So it's hard to predict for the year, because we're looking at a snapshot in time. But the dividend, roughly $600 million a year, we've released that kind of the capital guidance, 2.3, plus or minus $1 billion including some $800 million in Aspen. And so, you march down from the dividend, the CapEx. I think the share buybacks, it will be dependent on the macro environment, what it does and how our true spending unfolds. Our intent is that we will continue at a ratable level, but it will depend. We also have $1 billion cash on hand and that we typically don't carry a lot of cash. So I think we still have a great deal of flexibility to do all those things that are important to us. Strong balance sheet, reliable and growing dividend, fund attractive growth projects and a sustaining capital in there, and then continue to return surplus cash to shareholders if and as available. And I still see that as a part of our 2019 business plan. Absolute quantum is difficult to say. It always is difficult to say, because it depends on a number of things. But I don't think my earlier comments, including with spending on Aspen. I stand by my earlier comments. I think 2019 will be much the way we've described it in the past.

Appreciate the commentary. Thank you.

Thanks, Emily.

Our next question comes from Prashant Rao from Citi. Your line is now open.

Hi, good morning. This is Joe on for Prashant. Two questions. First, I'd like get your thoughts on Canadian light pricing and expectations for the differential through WTI. Seems to be back near WTI now as we head into back half of the year and IMO 2020 related incremental demand on distillates, is it reasonable to expect that Canadian light pricing and the market could take a premium to other light benchmark, specifically to WTI?

Okay. Well, I think, first of all, if you start with Canadian light, you've got to start with Brett and you've got a start with WTI and kind of the global macro-economic. On the Canadian light side of things, broadly, we -- the -- we're selling at a bit of a discount from WTI, of course. The differentials have come back in. So, on an absolute level, it's a tough question because it depends on first kind of global activities and then it comes back. Now, for us with -- when we have a growing differential with Canadian light that net-net is a benefit to us because our refining, we tend to be a heavy oil producer a lighter oil refiner. But also with where differentials are right now that's where we -- 2018 was kind of the anomaly year and it's back to kind of where we were in 2017 or beyond. But I'll go beyond what I usually do in forecasting and I'll give you a few thoughts. For the curtailment strategy to work, I think a healthy rail takeaway capacity needs to be up and running. And with where differentials have led to now, that's not happening. And so you've seen reports of inventories dropped down in the month of January, well that's why rail was still providing a level of export capacity. Although the incentives may not have been there throughout the month, folks were unwinding and I described us, we have largely unwound our rail terminal. So, half of that capacity that was there in December supporting -- reducing inventories and clearing the market here has evaporated. So, what I think you'll see here now is -- and I hope you see because I hope you see differentials start to move into the range where…

Thank you for the comments. And the second question like past Line 3, any thoughts on potential alternative logistics or transportation solution into the U.S. Gulf Coast other than Keystone XL perhaps maybe involving a series of connections, including the current top line reversal plan?

Well, I think you -- the kind of the foundation of your question is getting heavy crude to the Texas, Louisiana, Gulf Coast. And it's a no-brainer in terms of this is largest confrontation of heavy oil processing facilities in the world. There is a large and growing demand for it and supply sources have either been choked of or diminish over time. That's the winner-winner. That's where we want to get as a producer. That's where we want to get heavy all too. Obviously U.S., Midwest provides some strong markets too and we want to do that. But for growth opportunity and long-term for the industry it's getting it to the Texas, Louisiana and Gulf Coast. And it reminds me of an old movie, Planes, Trains & Automobiles. Anything we can get there in the light market conditions make sense. We've invested in contract pipe, we've invested in a rail terminal, we support Keystone XL, the contract commitments for expanded access. We're the -- I think we remain the largest shipper and the average mainline today, and there are some further tentacles that go down beyond the mainline that gives you Gulf Coast access. So any and all of those avenues, I think you'll find the Imperial Oil quite supportive of because it gives us the long, a long-term market access capacity to advantage of the strongest market for heavy oil. And I'll have my hand up on any or all of those to help with the long-term growth of our industry and our company and get into the highest value markets. And the Line 3 and KXL are the two furthers along on the drawing board. And I think I can safely say that any pipeline sponsors are proponents are looking at any and all ways that can continue to enhance capacity whether it's new and/or existing lines to get production to those markets.

Thank you. I appreciate the color.

Our next question comes from Dennis Fong from Canaccord Genuity. Your line is now open.

Hi, good morning guys, and thank you for taking my question. The first one is just a bit of a follow on to the share buyback program. From what you were essentially outlining there is it safe to assume that when -- or at the timing of the announcement back last June for your 40-odd million share buyback and you guys being about halfway through that right now, should the assumption still be despite we’ll call it the volatility in the current market both on a WTI business as well as differential basis that -- your attention is still to complete the first half or the second half of this NCIB? And then reevaluate the go forward, well, call it levels that you can renew the NCIB at June at the time of renewal?

Yes. I think when you get to June at the time of renewal and things; that gets a little more difficult. I'd like to have a few more months under our belt and see where things lie. But as we sit here today and what we're continuing to do is quite consistent with the renewal of middle of last year and as we look at sources it uses of funds. A lot can change in one month or two. And we saw that here in the last month or two. But our execution of that, I would -- certainly would never describe it as we're blindly executing that. But where we are today, we are continuing that and I expect that we will continue. On the renewal, itself, I really need -- Dennis I really a few more months and just seeing what kind of transpires in the market to be able to have any really -- offer you any comments with any degree of confidence. But I go back to the year before when we institute this thing. We wouldn't have done it if we thought it was something we would turn on and turn off, but we've -- for the first -- largely for the first almost year of that program, we were at a lower pro rata rate, about $250 million of quarter round numbers. So, we bumped that up last year with improved performance and higher cash flow to something that has averaged more recently kind of $400 million to $500 million a quarter. And moving up and down at a consistent averaging ratio is kind of -- that's kind of the way we want to do it. I don't see us going all-in in one quarter then slamming the brakes on in the next quarter. So, we'll look at continuing it, but I think the next several months will give us -- it's -- hold that question, ask it at the end of the first quarter call, give me a few more months of financial performance, and I'll be in a little bit better position to kind of speculate with you looking ahead.

All right. I will do that. The second question here is just at your Investor Day, you highlighted the view for the debottleneck projects at Kearl and frankly fairly strong capital efficiencies. How should we think about potentially these projects in light of not just your current view of the market, but kind of how you're thinking about the project in aggregate here as well?

Yes. I think you hit on a well there. We're very attractive from a capital efficiency, capital intensity. And to describe it as something on the order if I recall, round numbers 40,000 barrels a day of incremental capacity potential above and beyond the post supplemental crusher. So, from John Whalen did a good job of articulating how we go from 200,000 to 240,000 and then describe what a pathway to 280,000 could be. And with a series of enhancements debottlenecks that we would think of in aggregate would be quite capitally efficient. So, near-term, all eyes are focused on getting the supplemental crusher in the flow interconnect, done, complete by the end this year and then up and running. And at the same time, we have a set a really smart folks that are working on these supplemental debottlenecks that could get increment-by-increment. When we get supplemental crusher up and running and determine are we truly at 240,000 is it something other than 240,000? Is it 245,000? Is it 250,000? Then we'll be able to sharpen the pencil on the true value of each increment. But I do think it's safe to say that given the overall capital intensity attractiveness of that basket of opportunities, those will be things we will be looking to pursue. And if we're -- if the performance of supplemental crusher were off by a little bit, I don't think that's going to take these opportunities and say they're not attractive. This is going to help us determine how attractive. But first things first, supplemental crusher flow interconnect this year and those things -- and I think John describe it as kind of they would unfold over the following few years. And the next time, we talk at either at an Investor Day or somewhere else this year goes on. We'll probably able to get more definitive on those. But everything we've outlined in November remains true to form in terms of kind of what our expectations are for Kearl over the next several years.

Okay, perfect. And then just kind of the last follow-up there. Just given, will call it the potential operating cost impact of being able to expand production at Kearl for fairly low cost, how should -- and I don't want to make it sound like it agnostic frankly to market egress situation. But, how should I be thinking about those potential just influencing factors on deciding around the potential of this project or projects?

I'm sorry. Just not sure I have -- how market access would play into further expansion?

Exactly.

Yes. I think it gets backed to a lot of the conversations that we had either on Aspen at all. Clearly, we're going to need to be able to move this stuff and with -- if you look at the timeframe out of the 40,000 barrels a day, the supplemental we're working on now in today's world, it would compete for a pike space like others. We have some -- we have strong position with the production that we've had, with the Downstream take away capacities we have. I hope, as I've said that, we get back into -- well, rail makes economic sense. But as you keep adding increments, whether that comes at Aspen at 75,000 barrels a day, or another two increments of 4D at Kearl you got to have confidence you could be able to get it to attractive markets in that. Now the benefit of that second 4D at Kearl is kind of like Aspen. It's a little bit further out there in time. And we'll have the time and the benefit to see how the dust settles on the current situation we're in. And I know I'm repeating, but Line 3, Keystone XL, rail and any other way to get crude to market. So, you can't say, we're indifferent, or oblivious to expanded market access. But I think in Kearl, we'll have time to see how these things unfold. And those potential investments debottlenecks, I would expect with market access, would be – incrementally would be quite attractive.

Great. Thank you.

Thanks, Dennis.

Our last question comes from Greg Pardy from RBC Capital Markets. Your line is now open.

Thanks. Thanks. Good morning. Thanks, Rich for doing the call, again. I'd probably suggest that your indication on the ramping down rail is going to have a pretty immediate impact on the market. But I did want to come back and just ask you little bit about that in terms of what your cost structure is then in terms of crude-by-rail call it Alberta to the Gulf Coast? And then, how you think about ramping-up or ramping-down? Is that thought process in the context of fully loaded cost or is that -- do you also think about a variable cost just trying to get your thinking there? And then, how fast can you ramp-up crude by rail than if the differential does blow it again? Thanks very much.

Thanks, Greg. Welcome your questions. What we've said before that with the efficiency of our terminal. The direct access we have to markets and just kind of all the component parts that have built-up crude by rail. And it's more than a terminal and it's more than having access to tank cars. It's having the power and people agreements and rail service provider. It's having the offloading capabilities with customers. So, you don't put a rail deal together overnight. And we've been working on this for several years. And feel that we have a rail facility that is on the low end of the cost curve in terms of rail. And numbers we said before is kind of round numbers, $15 a barrel roughly, fully loaded cost. But we do look at, just as you say and you rightfully say it, is when we're making decisions on economic optimizations, that's the cost that will be in it, but we're looking at variable cost. And the variable costs is $9 or $10 a barrel, and that's more attractive than what a differential is. We'll move it by rail and that -- so with current differentials of what's happened, for us, I would say, that it's on a variable cost basis, we're kind of -- we're close that, right now at full cost rail doesn’t makes sense, variable cost for us, it's close to it. And the question you ask about ramp up, that's one that we -- within our interactions with the government, I think, has been really important, because as you redeploy things because they're no longer economic and we in our rail terminal, we put together a quite an attractive deal there with the relationship with ExxonMobil and access to railcars. We can we deploy them. We can pull…

Okay. Thanks very much, Rich.

Yes, you're welcome, Greg.

So that takes us essentially to end of our time. Did you want to offer some closing remarks Rich?

I'd just say we talked a lot about reflecting back on the quarter and the year. I think it was -- we've got a lots of very strong things here. And now the questions here we're largely on, okay, that was interesting but where are we today? And we're in a very dynamic situation today and then my soon to be 38 years in this industry. I'm kind of hard pressed to say whenever I had a period of time that wasn't dynamic. That is the nature of the oil and gas business. But as I sit here with Imperial Oil and I look at the level of integration we have, the balance we have, Upstream, Downstream, Logistics, I think we are designed and built to deal with and address and prosper in most any business environment we operate in. Differentials go up, differentials go down, heavy, lights. We've got a lot of tools and levers at our disposal. And we will do exactly what we've always done in particular what we have been doing of late to find ways to capitalize, make money, do all the things that are important to us for our shareholders and the current situation we're in is no different, the issues are bit different, but the challenges are the same and I’ll put my money on Imperial Oil to operate and address those challenges today just like we've done in the past. So, I think I'll conclude there.

Okay. Well, thank you everybody once again for calling in. As always if you have any further questions please don't hesitate to reach out to the IR team here at Imperial. Thank you very much. Thank you, operator.

Thanks folks.

Ladies and gentlemen, thank you for participating in today's conference. This does conclude today's program and you may all disconnect. Everyone have a great day