Good morning, ladies and gentlemen and welcome to the Suncor Fourth Quarter 2013, Conference Call and Webcast. I’d now like to turn the call over to Mr. Steve Douglas, Vice President, Investor Relations. Mr. Douglas, please go ahead.

Well, thank you Catherine and good morning everyone. Welcome to the Suncor Energy Q4 shareholder call. With me here in the conference room are Steve Williams, our President and Chief Executive Officer; Steve Reynish, our Interim Chief Financial Officer; and Jolienne Guillemaud, our Vice President and Controller. Please note that today’s comments contain forward-looking information. Actual results may differ materially from expected results, because of various risk factors and assumptions described in our Q4 earnings release as well as our current AIF and these of course are both available on the website. Certain financial measures referred to in our comments are not prescribed by Canadian GAAP and for description of these, please see the Q4 earnings release. After our formal remarks, we’ll open the call to questions first for members of the investment community and then to members of the media. Given the name distribution in the room, I think, I can probably assure you that all your questions will be answered by Steve. I will hand it over to Steve number one to kick off, Steve Williams.

Good morning and thank you for joining us. I’m going to begin with a review of our operational performance and provide you with an overview of our results in the fourth quarter and for the year as a whole. Then I will talk about our key priorities as we turn to page on 2013 and look to the New Year. Our Oil Sands operations produced record rates once again in the fourth quarter and which is almost 410,000 barrels per day. With strong reliability from our upgrade in complex, we were able to produce over 300,000 barrels per day of synthetic crude oil and set an upgrade in record for the year. And that’s particularly encouraging; we’re making steady progress on our operational excellence goals. We set a target to consistently exceed 90% utilization in our upgrade in complex and that would result in an average synthetic crude oil production of over 315,000 barrels per day. And I’m confident that we can reach that target in the near future. Throughout the quarter, our Oil Sands operations coped with ongoing natural gas curtailments as a result of third-party pipeline issues, this reduced production from our Firebag in Situ projects. However, thanks to the recently bottlenecking in our extraction plant, our mine was able to produce at record rates and partially offset the gas interruption impact. We continue to experience slightly smaller natural gas curtailments and we’re working closely with the pipeline operator to resolve the issues by the end of the first quarter. So as I look back on 2013 at Oil Sands, I’m pleased with our Oil Sands operational performance. Production was up 11% for the year, despite major plant maintenance and significant third-party pipeline outages. With no scheduled turnaround maintenance until 2016, we’re looking forward to an extended run…

Thank you. Good morning, everyone. First, let me say how pleased I am to be here today. As EVP of our Ventures group for the past couple of years, I've been part of Suncor's senior leadership team and I'm pleased to bring my perspective to this quarterly call. So the final quarter of 2013 had a number of similarities to the fourth quarter of 2012. Once again we saw strong global oil pricing and wide price differentials for North America Inland crudes. At times, heavy Canadian crudes approached record discounts as refinery maintenance and logistical constraints combined to sharply limit demand. Suncor's tightly integrated midstream and downstream assets enabled us to maximize our margins and generate strong cash flows. So, here are some of the financial highlights. Our operating earnings for the quarter came in at $973 million and our cash flow from operations was 2.35 billion. This is the 10th consecutive quarter in which Suncor's cash flow has been at or above $2.25 billion, quite an achievement given the volatility of crude price differentials over the past couple of years and an indication of the strength of Suncor's business model and the reliability of our operations. At Oil Sands, we faced headwinds in the form of third party pipeline outages but did reduce production. We also encountered unfavorable crude pricing differentials throughout the quarter. As a result, our average realized price for Oil Sands production was just over $71 per barrel. Our refining network was able to run at more than 90% capacity and take advantage of discounted feedstock to generate strong profitability once again. With a solid fourth quarter, the refining and marketing groups surpassed the $2 billion mark in earnings for the second year in a row. In E&P, we benefited from continued strong Brent pricing to…

Okay, thank you Steve, and I share that confident as well. As we begin a new year we're well positioned to make 2014 a great year for Suncor. We have no major turnaround maintenance planned at Oil Sand. Firebag production has fully ramped up. Oil Sands logistics have been debottleneck to support increased production and sales. Our market access strategy is unfolding as planned with the start of the Keystone South pipeline an additional rail capacity. Our Montreal Refinery will benefit from cheaper Inland crude feedstock. Finally in E&P, with the sale of our natural gas assets, we are focused on high return oil assets and we're moving the project forward to ensure we maintain and even increase our very profitable offshore production. In short there’s a lot to look forward to in 2014, we're excited about the path forward and we’re intent on delivering on our commitments. So with that I’ll pass it back to Steve Douglas.

Well, thank you Steve and Steve, and just before we go to questions, I should note that we have made some adjustments to our guidance. Is it updated on our website, but the key changes are the removal of Libyan production and an adjustment to reflect the weaker Canadian dollar, so a lowering of the exchange rate to CAD$0.92. One thing I do want to note is we will no longer be posting monthly Oil Sands production numbers. With our growing operations and a changing product mix, a single monthly production number simply doesn’t reflect Oil Sands overall performance; it's not a good indicator. As such we will discontinue the monthly posting of production and we’ll focus on quarterly operational updates. A few more notes. With crude prices falling in the fourth quarter and product prices falling we had an after-tax expense in the LIFO/FIFO adjustment of $142 million for Q4 largely hitting our refining and marketing results. For the year it was actually a positive after-tax impact of $80 million. On the stock based compensation side of things, with the share price rising throughout the year at 15%, the after-tax expense was $67 million in Q4 and $304 million for the year. Finally going back to the FX impact, with the Canadian dollar falling, our American denominated debt carrying expense rises and it was $259 million after-tax expense in Q4 and $521 million after-tax expense for the year. With that I am going to turn it back to Catherine to take questions. Catherine.

Thank you, Mr. Douglas. We will now take questions from the telephone lines. (Operator Instructions) Our first question is from Greg Pardy of RBC Capital Markets. Please go ahead.

Yeah, thanks good morning, and I do have a question for Steve, just a couple of actually. Just in terms of the gas outages right now, you mentioned in the quarter it impacts production rates by about 15,000 barrels today. But is it having a material impact then on the split between synthetic sweet and any other blends that you’re producing, that’s the first question. The second one is, just with respect to your Oil Sand operating cost, you noted the impact of maintenance, what would that have been in a dollar per barrel amount or can you give us an idea hedging knocked on the maintenance, thanks very much.

Hi, Greg, Steve Williams, yeah let me give you some answers for those. So, I mean firstly not a significant impact on the mix, it's slightly affecting upgraders but not anywhere near the 15,000 barrels a day we’re talking about overall. And if anything those impacts although we’re still seeing occasional curtailments, the mitigation specks that TransCanada have taken are improving the situation. So the impact is diminishing and not increasing. And of course as the weather starts to improve then we’ll see a further improvement because the gas supply -- the common gas supply to the municipality of Wood Baffalo as well as to the industrial gas consumers up there. So overall the impact is starting to drop off and no we’re not seeing significant upgrading impacts. In terms of the op-cost effects, I mean it's sort of good news and bad news. We’re a bit frustrated back to our absolute trend we were seeing in operating cost hasn’t continued; that’s the bad news. The good news is that the majority of it we can attribute to one-off events which you’ll not see being repeated as the year goes on. So I think Steve highlighted just briefly, some of them may not give you the numbers in approximate dollars a barrel. So the ones-off maintenance on the mining trucks we decided to do and get ahead off to position us well for this year was the equivalent of a bag a dollar a barrel. Both the combination of the planned and a small amount of unplanned maintenance on the upgraders was about $0.50 a barrel. We also had a one-off back payment which is a negotiation with our union employees and paid the backdated element of that and that was the equivalent of about $0.70 a barrel. So the three of those get you up with sort of $2.25 a barrel. It's a lot of that seasonality in there as well. I don’t like to over place these now, but with a very cold spell up there, gas demand was up and gas prices went up so there was no element of gas prices in there. And I think what I would say just to close on the cost is, Steve said and I would underline it, we are very confident in our guidance, so that gives you a feel for what we’re expecting for 2014.

Okay. Thanks very much.

Thank you. Our next is from Arjun Murti of Goldman Sachs. Please go ahead.

Thank you. I have just a few midstream-to-downstream questions. You mentioned the rail going to Montreal, is there an update on the timing of Line 9 reversal is the first question; and then I believe you’re able to now bring in some cargo’s from the Gulf Coast, can you just talk about the quantities and maybe the differentials that gets you excited to go for that option going into Montreal? Thank you.

Good morning, Arjun. I mean it's very difficult to be absolutely specific about these market access issues just because the science and the economic is clear. The final decisions are still in political realms. In Line 9 case it's actually with the NAB, so it's a little bit simpler. Our expectation is that we will get results on Line 9 reversal in this quarter probably by the end of February and we're still optimistic in expecting a positive response. And of course a lot of the potential investment we talked about in Montreal is conditional almost getting low cost feedstock into that refinery. So we remain cautiously optimistic that we'll see that approval in the next four to eight weeks. Cargoes coming to Montreal, I mean really to put it in context, we've had three, four cargoes gone into Montreal and we really do that on an opportunity basis. So if we can see the material available, it is material but it's not subject to the export restriction because we're allowed to move materials from the U.S. into Canada. So we will take opportunity as those differentials are available and we have good logistic facilities to be able to – to do that. So we're taking considerable advantage of that at the moment.

That's great, Steven. And just one follow-up on refining. I think you mentioned debottlenecking – correct me if I am wrong, was about 4% over the last two years which is somewhat typical 2% one can do in the refining business. Is that how we should think about your refining growth plans will be continued debottlenecking activities or in terms of primary distillation, are there the potential to have more meaningful expansions than that? How are you thinking about the refining side?

What I would do is I'd say the first place we start and you've seen it right away across our businesses is to make sure we operate the assets we have as well as we can possibly operate them. And that's a piece that we call operational excellence. We've seen the refineries first of all come up (indiscernible) best practices and then we've been able to reliability and safely operate them. We've been able to redefine the capacities of those facilities and that's the 4%. And we've been doing very similar things. We're doing that across the businesses and in the sense that's what's happening in Oil Sands and that's what starting to happen with debottlenecks. There are then some real integration projects particularly our Montreal refinery where we can take advantage of low cost, some of it maybe capacity like primer distillation, but more of the investment there is around how we get better conversion or better coke in, lower than Fort McMurray-type cost coking facilities in there to take full advantage of the Inland crudes we can put in. So you see us doing that is the second stage. The third piece of our strategy is we've been – the integration has worked very well between Oil Sands and refining. And as you know, we've been able to get up on average up in the mid 90s type levels of Brent related price because of that integration. We actually sit in the fourth quarter, the low watermark because of the way that integration works on our logistics there and we're actually starting to see it come out now as the market exit strategy is kicking in. So the next strategic question for us then is, do we want to – as we start to expand the Oil Sands and our upstream production, do we want to proportionally increase the integration. And we look at very refining opportunity that comes onto the market on this continent. We don't have any immediate plans but we'll continue to look at that as part of our integrated strategy. And some of that depends on your view as to what happened on the continent. Our long-term view is that demand and refining capacity is probably peaking on the continent and therefore as market access becomes available, that profit will start to migrate back to the upstream. But we keep revising that review and we look at very refining opportunity to see if we want to do any further integration. So the simple view is the first focus is on operational excellence getting the best we can. The second focus is on these low cost debottlenecks and the third one is whether we readjust then the refining Oil Sands split.

That's great. Thank you, Steve.

Thank you. Our next question is from Guy Baber of Suncor Energy [ph]. Please go ahead. Guy Baber - Simmons & Company International: Thank you. Guy Baber of Simmons. Your underlying refining earnings this quarter were very strong relative to what we could track from a margin perspective in your primary regions. I'm just wondering if you could discuss any adjustments you had made with respect to crude slate in any of your refineries just across the portfolio or anything else that you might call out that may have contributed to that strong performance? To go back to perhaps shipping some of the Gulf Coast barrels as you mentioned up to Montreal during 4Q, just trying to get a better sense of how and where the numbers came in so strong in refining?

I would say it really is a reflection of the strength of the integrated model. There was nothing particularly exceptional. The Denver and Edmonton craft spreads were very positive for us but really it's just a reflecting of the integrated model that we're able to move around. So there was nothing – we're constantly trying to optimize. I mean one of the – we've always got to try to be very transparent. One of the advantages our integrated model has is we have a trading shop that works alongside it. So we're able to optimize the continental feeds into those refineries and take advantage of times when the Oil Sands or the differentials are significantly advantage to us. So nothing particular happened other than we optimized where we took advantage of those craft spreads. Guy Baber - Simmons & Company International: Okay, that's helpful. And I was hoping you can just provide some commentary around the dividend, just what went into the decision on the dividend raise, why was 15% increase the right number? And then are you targeting a specific payout ratio and if you can, to what extent if at all the decision to maintain some level of buyback and then balancing it to influence the ability to raise the dividend?

Okay. Let me start with we've had a compounded average gross rate on our dividend in excess of 35% over the last five years. So as we've been saying, the business is generating more cash and we are distributing that cash to shareholders. I like to think of it very simply in terms of the regular – the ratio approximately, the dividend to earnings and that's why we adjusted our timing in terms of when we make the recommendation and then when the Board who has the approval for dividends approves it. So trying to create the relationship between adjusted earnings and dividend. We want that dividend to be competitive. You heard Steve say we wanted to be reliable and sustainable and that's our plan. You will continue to see us raising that dividend as we grow the net earnings, adjusted earnings of the company through time. When we look at it, we have talked about capital discipline, so you see that Exercise A got some capital discipline around the 15% and I know there have been a number of commentators in the market. We're talking of 25% and some even talking as high as 40%. Our commitment is to be competitive, reliable, sustainable and grow that thing through time and that's where the 15% comes from. Now when you look at our balance sheet, we still have some significant cash and liquidity capability in there and that's why we've come immediately on top of the dividend with another NCIB or share buyback program. And if you look at the last couple of quarters, you've seen us buying stock back. Third quarter was just over $425 million and in the fourth quarter, we bought back $550 million of stock. You will see us continue through this year at approximately that rate. So to summarize that, the dividend – we don't hardwire it to a ratio but you can see we're aiming for in that 25% to 30% adjusted earnings range and you'll see us – and it's an interesting problem to have. You'll see us trying to get the cash on our balance sheet in the position we want it by continuing these share buybacks. So we're going to be continuing with a relatively aggressive program for the rest of this year. Guy Baber - Simmons & Company International: Very helpful. Thank you.

Thank you. Our next question is from David McColl of Morningstar. Please go ahead.

Hi, Good morning, everyone. Thanks for taking my call. I just like to switch back to differentials for a minute. So giving your marketing refining divisions, interest in Syncrude and Suncor’s production of sweet SCO, I’m wondering if you can comment on Canadian crude prices for the quarter or I guess, maybe put differently, are you seeing better pricing for Canadian lights and sweet SCO in your refineries and are you seeing weaker prices for the Upstream tied to this? Of course I’m really interested in your long-term outlook given the strong light oil production we’re seeing in the U.S which could down the road have an impact on Canadian light prices and differentials? Thanks.

Okay. Well, I will start if you like with the longer term and strategic view and then we will just give you a few comments on some of the short-term numbers. If you go back to when we made the Voyager decision, we started to revise our point of view as the information was coming in about the tight oil bloom that was going on in the U.S. Our view in the long run is that there was going to be considerable length in light sweet crude or you can read across that’s equivalent to synthetic crude. And that the -- as access to market become available then the discounts on the heavy crudes, particularly WCS would start to be reduced and that price would come up. And that was the reason we moved to what we shut the Voyager investment down because we believed that there would be a length in light sweet crudes. That starting very much to play out as we expected and what we’re seeing there is that the Voyager tight investment, it’s very difficult to justify doing that. However, we do have some cheaper alternatives. So projects like the Montreal coker, much lower cost in terms of coking capacity compared to Fort McMurray can start to look very attractive in that world. So we see that trend continuing and there will be some bumps in the road. This market access has not gone as smoothly for the industry as it might have done. For Suncor its playing out much as we expected and we taken the opportunity to contract inter pipelines to protect us through our growth program, so that none of these market access projects -- no single one of them was critical to us and that’s playing out very nicely. However, we’ve seen these differentials move around and the power of the integrated mobile where we’ve been able to attract these very high proportions of Brent related prices rather than these discounted Midcontinent crudes has really played out. I mean, Steve mentioned that we’ve -- that the power of the model is that we’ve produced at or around CAD$2.75 billion cash a quarter for the last three years. And we think this was the moment to have the integrated model. There is some debate and we’re involved in that that is how important is to retain exactly that sort of values between refining and the Oil Sands in the future. But this was the time to have and take advantage of those differentials. So we’re really quite neutral to what they’re in a sense that if the Oil Sands prices are high, great we take it in the Upstream. If they’re low, we simply take it in the Downstream. I don’t know if you wanted to add a comment Steve on particular differentials in the fourth quarter.

Well, thanks Steve. Just David some of the specifics, I mean, we saw sharply a drop in crude prices. It’s a widening differentials beginning at the start of the fourth quarter. I mean, if you look at OSA synthetic upgraded, you saw it moving from par at the tail end of the second quarter, par to WTI and it bottomed out at about $14 or $15 discounts to WTI in early December and that come back and its now trading at a modest premium. Sour synthetic likewise, I mean, typically trade somewhere in the $8 to $12 range below WTI and it bottomed out about $25 below WTI and then came back here at the beginning of the year, and finally bitumen. Now neither of those hurt us because we’re fully integrated on those and we’re able to capture the uptick. Where we did see an impact was, we had higher bitumen sales than we typically have over 100,000 barrels of bitumen daily and we weren’t able to capture the entire upgrade there because we weren’t able to process that all internally and our access to global markets was somewhat limited. We’re seeing a change in that as Steve mentioned already because of course we’re shipping well in excess of 50,000 barrels a day to the Gulf Coast now. So the only real impact for us was bitumen pricing and we’re seeing that come back now.

Okay. Just a quick follow-up on that. If you’re shipping well over 100,000 barrels per day, can you give any indication, down the Gulf Coast -- any indication as to how much of that is going on the Gulf Coast Connector or Keystone South as is called? Just trying to find out whether you’re well over that 50,000 barrels a day capacity you have?

Yes, we’re up in the 70,000 barrel a day, right.

Okay. Thank you.

Thank you. Our next question is from Bob Bakanauskas of ISI Group. Please go ahead.

Hi. Good morning, guys and thanks for taking my question. I was noticing with the U.S. dollar appreciation here, but I was wondering to what extent the profits in the quarter and if you have any breakdown as to what percent of the operating costs are denominated in Canadian dollars versus U.S?

Yes, so Bob we’ve seen obviously a dramatic move at the beginning of this year of the Canadian dollar against the U.S. dollar that is broadly favorable to Suncor as an entity. So we will see that -- that should continue through this year. We will see a beneficial effect both on earnings and cash. What was the second part of your question, Bob, can you just repeat that for me?

Sure. In terms of the actual operating cost, labor cost and everything else; what percent would you say is the nominated and Canadian dollar versus U.S. dollar?

I don’t have an exact percentage Bob. I mean, the majority of our costs are denominated in Canadian dollars, so certainly all of the labor and as well and that would take it something like 80% plus I think in Canadian, but we do -- we buy equipment denominated in U.S. dollar. So we have some exposure there, but the overall balance, say depreciating Canadian dollar is favorable I think to Suncor for both U.S. investors and Canadian investors.

Got you. And just a follow-up on the overall operating cost. Obviously, you’ve had a lot of progress over the past couple of years which has largely been a function of the SAGD ramp up. Can you talk about mining and upgrading costs, especially in what direction they’re headed? And I know there was -- this quarter may have been an anomaly with the increasing maintenance, but just generally, I know you stopped disclosing mining cost specially, but can you talk about the trends there over time and what you expect sort of over the long-term?

All I would say is that a very similar trend, if you like, that we’re now hitting record levels in the mine, record levels through extraction. There are approximate numbers because it depends on the mine and the part of the mine we’re operating in, but you’re up at 75% plus type fixed cost. So as the reliability has been coming up we’re seeing a steady trend down in both mining and extraction costs.

Got you. Great. That’s all I have. Thank you.

Thank you. Our next question is from Jason Frew of Credit Suisse. Please go ahead.

Yes, hi. I’m just wondering supposing there’s a favorable differential, is there anything that logistically holds you back from being more aggressive with running Gulf Coast crude through Montreal in the near-term?

No, I mean the only thing is shipping availability and we haven't seen a problem. So now that the differentials are there, then we think we have the access and the logistics together there.

Okay. Thanks.

Thank you. Our next question is from Menno Hulshof of TD Securities. Please go ahead.

Yes, thanks and good morning. I just have one quick one. It sounds like you recently made the decision of pullback on delineation activity for your Montney assets. So what was the thought process there and what is the go-forward plan for those?

Yes, let me -- I’ll talk about LNG and that Montney asset we’ve up there. And if -- for those who don’t recall, we sold our North American gas business largely and that was relatively high cost, relatively low return with a bit of big environmental liability coming out of, so we were very pleased to do that there. That left us then this LNG resource which approximately is in that 7.5 billion, 8 billion barrels. So it's a sizable piece of gas. We've retained it primarily for the optionality it gave us in the future and we did some work early on to delineate it. And what I would say is we finished the delineation work we needed to do to retain it. We know it's a very high quality piece of resource. Our plans are that in the next couple of years probably, I mean you can never be absolutely specific but we have no plans in the next couple of years to do any further work on that. The optionality we still like. So we could retain it relatively cheaply as an option against our gas price movement in the future. That's a possibility. It's big enough that it could go into an LNG project and be a sizable piece of an LNG plant feed. We have no plans on our books at the moment to do that but we've retained that option. And as that asset is going to start to go acquire and we will take a strategic look at the choices we have forward. But we quite like the status quo where we're retaining optionality. Whilst I'm on that, it's probably worth saying just in terms of other major inorganic pieces of growth, it's probably worth commenting on those as well. We had a number of questions asked at the Investor Day and probably a bit of clarity would help. Again, probably in the next couple of years we have no plans for large non-core acquisitions and we have no plans for any significant exploration outside of our existing theaters where we operate in the North Sea and off of the East Coast of Canada. So, it's not to say we will never do any of those things but there are no plans on our books either for LNG, large non-core acquisitions or exploration outside of our existing theaters.

That helps a lot. Thanks, Steve.

Okay.

Thank you. Our next question is from Chris Feltin of Macquarie. Please go ahead.

Good morning, guys. Just a very quick question here. It looks like we're getting to pretty much the end of the Firebag ramp up here and I know that it's 180,000 for a nameplate. Just kind of wondering where we should be looking at that in terms of the ongoing reliability? Are you guys comfortable with the 180 looking forward here on a sustainable basis? And just any color I guess in terms of what we should be looking at in terms of that particular project. It sounds like a pretty close to full capacity out of Phase 4 here already?

Yes, I've got a very proud – Mark Little sat next to me here and we actually had it yesterday up to 175,000 barrels a day. We're confident we can get to that nameplate capacity. I mean of course the next challenge we have now is to reliably produce at those levels. But the offset is we consider it to be largely producing what we expected and this is the year. We now have to start to get it up to those levels and keep it at those levels. So I'm very pleased with the ramp up, very pleased with the quality of assets. And now we're in the game of fine-tuning it.

Okay. That was it. Thanks.

Thank you. (Operator Instructions). Our next question is from Mohit Bhardwaj of Citigroup. Please go ahead.

Hi. Thanks for taking my questions. My question is on adjustments. What milestones need to be accomplished before the final decision is taken by the partners? And what happens if say one of the partners Total or Occidental of Suncor doesn't agree to the findings of those milestones? Thank you.

Okay. I'll let Steve Reynish give you the answer.

Yes, so the Joslyn project is obviously operated by Total and it remains in that – still in that engineering feed stage, so we're still working on the configuration of that mine. So there is still a ways to go before we would anticipate any sanctioned decision on this asset. I think we think we'll have an update on that position probably in Q3 of this year and that will depend on the progress we and the operator have made in completing that work, but there's still a ways to go I think is the answer to that one. On the more technical issue or contractual issue on the partners, obviously there are four partners involved in this project and as it currently stands, certainly Total and Suncor would need to agree on the path or the majority of the shareholders would need to agree on the path forward. So that's what we're working towards but no real update other than there's still a ways to go on this one.

Thank you. And if I could just ask a follow-up on Montreal refinery projects, Steve, it seems like your inclination is more towards Western Canadian integration for the refinery and not so much for getting advantageous crudes from the Gulf Coast. I was just wondering if you guys have the run in crudes from the Gulf Coast and what the capacity for that is. Thank you.

Yes, I wouldn't say it's quite that clear. I would say we want to configure the Montreal refinery so we can optimize a broad basket of crudes going into there and that basket will include the full range of western crude from the upgraded synthetic crude all the way through to diluted bitumen. It will also include the opportunity to take discounted Mid Continent crudes in there as well and it will also include the ability to import crudes over the water through the marine facilities we have. And that flexibility is the most powerful position for that refinery to be in that we can actually optimize all of those. The assets on the ground there are quite complex. They're very capable of handing a broad die [ph] of crudes. And with the potential addition of coke down the road, it would give us full range flexibility across those crudes. So, we like the refinery, we like the flexibility and we'll take advantage of whatever crude is, is the best crude on the day.

With that operator, I'm going to ask that we wrap things up. What I'd say is thank you, everyone, for participating. As always both the Investor Relations team and Controllers team will be available throughout the day for detailed questions whether by email or phone and we look forward to talking to investors and analysts further. With that, thank you very much. We will sign off.

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