Earnings Call: Q1 2018

May 2, 2018

Good day, ladies and gentlemen, and welcome to the Suncor Energy First Quarter 2018 Financial Results Call. At this time, all participants are in a listen only mode. As a reminder, this conference call is being recorded. I'd now like to introduce your host for today's conference, Mr. Steve Douglas, Vice President of Investor Relations. Please go ahead. Well, thank you, operator, and good morning to everyone. Welcome to the Suncor Energy First Quarter Earnings Call. I have with me here in Calgary this morning Steve Williams, our President and CEO Mark Little, our Chief Operating Officer Alastair Cowen, EVP and Chief Financial Officer and also Trevor Bell, who is our current Vice President of Tax, but the incoming Vice President of Investor Relations with my imminent retirement. I'd ask you to note that today's comments contain forward looking information. Actual results may differ materially from expected results because of various risk factors and assumptions, and these are described in our Q1 earnings release as well as our current AIF, and both of these are available on SEDAR, EDGAR and suncor.com. Certain financial measures referred to in these comments are not prescribed by Canadian GAAP. For a description, please see our Q1 earnings release. After the formal remarks, we'll open the call With that, I'll hand it over to Steve Williams. Good morning and thank you for joining us. I would like to start by taking a moment to recognize the contributions of Steve who is taking as he describes a well deserved retirement after almost 28 years with Suncor. I mean Investor Relations has clearly been a genuine strength here at Suncor and Steve's leadership has been greatly appreciated. I'd also like to welcome Trevor Bell who is transitioning into relations role and I know that he'll provide equally strong leadership as we continue to tell the Suncor story to an expanding shareholder base around the world. So turning to our results, the Q1 of 2018 featured the highest average oil prices since the Q4 of 2014. The combination of positive supply demand fundamentals and global oil inventories finally moved into balance has begun to shift both industry and I think investor sentiment. In Canada, the story is complicated by wide, light, heavy differentials as a result of increasing market access challenges. And just as an aside, I will cover those differentials later in more detail, but for Suncor, it has no impact. Amid all of these developments, I think it's important to come back to the guiding principles that underpin the Suncor story and to remind everyone of the unique advantage that continues to enable our outperformance. And these are constants that will not shift with oil price cycle or investor sentiment. And as I've said many times, it starts with capital discipline. As rising production and higher oil prices drive increased free cash flow, we will maintain our focus on rigorous allocation of capital. We'll meet our commitments on reduced capital spending. We will avoid growth for growth sake and instead focus on growing free cash flow and returns for shareholders and we will deliver cash back to our shareholders through competitive dividends and value based share buybacks. Our tightly integrated business model is a critical part of the Suncor Advantage and one that is very hard for our competitors to match. Our upgrading and mid stream assets and expertise combined with our industry leading refining and marketing network enable us to maximize the value of every oil sands barrel that we produce. In the Q1, the WCS WTI price differential averaged dollars per barrel and that versus just US12 dollars per barrel in the Q4 of last year. So that near doubling of the light heavy differential had absolutely no impact on our earnings or cash flow. And let me repeat that, the near doubling of the light heavy differential had absolutely no impact on our earnings or cash flow. What we lost in realized pricing at oil sands, we completely recovered through our midstream and downstream operations. Our integrated model and strong logistics capability fully shielded us from the significant market access issues and pricing differentials. We didn't lose any value. We simply realized it elsewhere in the value chain and that's exactly what the strategy was designed to do. Operational excellence is another key element of our business model and unfortunately the operations at both the Suncor base plant and Syncrude fell short of Suncor's high standards in the Q1. We need to do better and be assured we will. We will continue to work in a disciplined manner to improve safety and reliability, reduce costs and ensure the sustainability of our operations. We'll also continue to bring technology and innovation to bear across the entire business in support of our operational excellence. And let me give you an example. After several years of comprehensive testing, we've begun to roll out autonomous haul trucks across our mines, a global first for soft rock mining. Our North Sea Bag mine is already operating with a fleet of automated trucks. The implementation of this technology will result in safer, more productive mining operations with improved fuel efficiency and lower associated emissions. And this is just one of a host of technologies that we expect to drive operational excellence across our business over the next few years. Finally, we continue to focus on profitably growing the company and the successful ramp up of Fort Hills and Hebron production combined with continuous improvements at Syncrude will lead to a 10% production growth this year, a further 10% in 2019. And we've certainly been pleased with the progress on both our major growth projects so far this year. Despite the Fort Hills start up being delayed by exceptionally cold weather until the last week of January, we were able to hit the midpoint of 1st quarter guidance, effectively delivering 3 months of production in just February March. And with the start up of the second solvent extraction unit on April 22, we've now successfully run the plant over 150,000 barrels per day. So with the start up of the 3rd and final extraction train now planned for later this month, we expect to be producing at capacity well ahead of our original schedule. We've had a similar experience at Hebron where the second production well came on ahead of schedule in the Q1. We were anticipating average net production for this year of about 10,000 barrels per day at Hebron with a third production while now in operation, we've already seen volumes exceed that target. So our immediate growth is ramping up ahead of expectations and of course we laid out a series of low capital intensity projects that we believe will grow our free cash flow by more than $500,000,000 annually beginning in 2020 and of course that's irrespective of oil prices. Many of those projects involve the application of technology to reduce costs and improve environmental performance. And examples range from replacing our coke fired boiler system with cogent units to the use of advanced analytics to reduce maintenance costs and optimize facility throughput And to more simple measures like employing remote sensing technologies such as drones to generate real time flare stack diagnostics and calculate overburden removal. So we have a great deal of confidence in that suite of projects and we believe that they'll increase our annual cash flow by more than $2,000,000,000 by 2023. So the real strength of our growth plan for the next 5 or 6 years is a high level of certainty and it's not constrained by market access issues. We have existing pipeline access to accommodate all of our oil sands production including our Fort Hills barrels. Again, let me repeat, we have existing pipeline access to accommodate all of our oil sands production, including our Fort Hills barrels and our growth from 2020 to 2023 is largely about increased productivity, efficiency and margin enhancement. Now that said, we are fully supportive of all pipeline projects to increase market access for Western Canadian crudes. And we believe it's important for all Canadians that new pipelines are not just approved, but constructed and put into operation in a timely manner following the well defined Canadian regulatory processes. I have to say I've been encouraged by the strength of the recent support that the Alberta and federal governments have expressed for the Trans Mountain expansion and I look forward to seeing their plans unfold over the coming weeks. In the meantime, Suncor is making strong progress as we execute on our growth and returns strategy. I'm now going to ask our Chief Operating Officer, Mark Little to provide some color on our operational performance in the Q1. Mark? Great. Thanks, Steve, and good morning, everyone. As Steve mentioned, we dealt with some operational challenges in the Q1, which reduced production at both our oil sands base and at Syncrude. However, strong performance from our offshore projects and record refining and marketing results largely bridge the gap. I just wanted to go through a couple of the details here. Total Oil Sands production averaged 572,000 barrels per day, which was down about 3% from the Q1 of last year. At our oil sands base plant, a leak in a water line damaged electrical equipment and led to a power outage, which shut down the plant in mid January. This event was complicated by extreme cold winter weather, which extended the time required to restart the plant. We returned to normal operations in February, and I just wanted to acknowledge the terrific job done by the team to safely return the plant and manage through this event. At Syncrude, we experienced a partial blockage in the pipeline that carries bitumen from the Aurora North mine to the upgraders. As a result, the Syncrude plant was short bitumen feed and forced to operate below capacity. To reduce the impact of this event, the planned Syncrude turnaround was advanced by approximately 1 month, so that the issue with the prop line could be resolved during the turnaround window. This issue has been fully resolved and the line is back in service with several mitigations implemented to prevent a reoccurrence. We expect Syncrude to complete the turnaround and return to normal operations in the next couple of weeks. In situ operations continue to be extremely reliable as Firebag and MacKay River combined to produce 241,000 barrels per day of bitumen equal to 100 percent of the nameplate capacity. As Steve mentioned earlier, the Fort Hills ramp up is proceeding ahead of schedule and I'm very pleased with the performance trend. The strong results reflect the high quality of construction and the dedication and teamwork of thousands of employees and contractors and our unique phased approach to handover commissioning and startup that leveraged all of Suncor's infrastructure in the region. We conducted several pre winter test runs on the front end of the plant prior to starting up secondary extraction. And then we started up the first two secondary extraction plants in a phased manner in the 1st 4 months of the year. With preparations ongoing for the final secondary extraction train to come on later this month, it's too early to declare victory. However, I'm very pleased with our progress to date and I'm increasingly confident that we'll be able to achieve full stable operations ahead of the previously announced timeline. In the E and P group, production exceeded our guidance range as the faster than expected ramp up at Hebron production helped to offset the expected natural declines elsewhere. As Steve pointed out, the second and third production wells have come online already this year at Hebron. The drilling activities were also conducted in the Q1 at Terra Nova, Hibernia and Whiterose as part of our investment to mitigate natural declines going forward. In the downstream, strong wholesale and retail product demand enabled us to run our refineries at record rates for the Q1. Crude throughput averaged 454,000 barrels per day, which equates to 98% of nameplate capacity. Building inventory for the 2nd quarter refinery turnarounds also helps support strong utilization rates. A key element of operational excellence is strong cost management and we've been working successfully to steadily reduce our operating costs across the business. Our Oil Sands operations costs came in at $26.85 per barrel in the Q1. The higher unit costs this quarter largely resulted from the reduced production and the incremental maintenance associated with the outage that I talked about, as well as preparation for the U1 turnaround that started at the beginning of April. Of note, our all in in situ cash costs averaged $9.55 per barrel in Q1. That's in situ's 3rd consecutive quarter of sub-ten dollars per barrel cash costs. Syncrude cash costs rose to $50.75 per barrel. Once again, the increased costs reflected the reduced production and incremental maintenance expenses. We anticipate a return to more typical cost levels at both Oil Sands operations and Syncrude once turnaround activities are completed later this month. And we maintain both our production and cash cost guidance unchanged for the full year, which reflects our confidence in the safe, reliable, low cost operations for the remainder of the year once we complete the current turnarounds. In E and P, we continue to see exceptional cost performance as the UK North Sea came in at just $5.36 per barrel and the East Coast operating costs fell below $10 per barrel for the first time in a year at $9.70 per barrel. Finally, with record Q1 throughput at our refineries, we're able to reduce operating expenses to just $4.90 per barrel. Looking forward, our immediate focus is to safely complete our major turnaround work and to start up the final secondary extraction train at Fort Hills. Success on those two fronts will set us up for a strong operating performance in the second half of the year. And with that, I'll turn it over to Alistair Cowen to provide some color on our financial results. Alistair? Thanks, Mark, and good morning. With an average WTI price of $62.90 and the New York Harbor 3/21 refining crack of US15.50 dollars per barrel. The business environment in Q1 was stronger than we've seen in some times. Now as Steve mentioned, the WCS price was heavily discounted in the quarter, but our integration completely shielded us from the wide WCS, WTI differential. And just as a reminder, when looking at our results, we use market prices to transfer our production from our upstream to our downstream refining operations. So the realized pricing for oil sands crudes net of transportation expense range from CAD76.85 per barrel for Syncrude SSP than to CAD27.57 for in situ bitumen, reflecting the unusually high Western Canadian light heavy differential. Fort Hills higher quality PFT bitumen realized a premium of approximately CAD5 per barrel over in situ bitumen. In the offshore, our production realized very close to Brent pricing with East Coast Canada averaging CAD82.78 per barrel and the North Sea averaging CAD81 per barrel. Our refineries benefited from running significant volumes of the discounted Western Canadian heavy and sour crudes and downstream achieved an average refining gross margin of CAD 30.25 per barrel versus the New York Harbor 3 21 crack of CAD19.60 per barrel. With the strong realized margins across the business, we delivered strong financial results again in the quarter. We generated $2,160,000,000 in funds from operations and $985,000,000 in operating earnings in the Q1. And our return on capital employed improved to 7.8%, excluding major projects in progress. Our funds from operations for the Q1 significantly exceeded our sustaining capital plus our dividend, leaving $755,000,000 in discretionary free funds flow to invest in growth and return to shareholders. I should just note there's a couple of unusual items in the quarter that reduced our funds from operations and our GAAP cash flow or cash flow from operating activities. Both metrics were reduced by approximately $335,000,000 due to the annual payout of stock based compensation, which we accrue to earnings on a quarterly basis, but it only has our cash flow on the annual basis in the Q1. Also cash flow from operating activities is adjusted for changes in non cash working capital. Now you'll have noted that the working capital increased by $1,400,000,000 in the Q1. And that's really a result of an increase to accounts receivable on an improving price environment, a substantial build product inventory in advance of major turnarounds and the payment of deferred 2017 taxes. Now obviously some of this build in working capital will reverse in Q2 and later in the year. As everyone is aware with the start of our 4 hills at Hebron, we have reached the end of a period of intense capital spending on large growth projects. So in the Q1, our total capital expenditures were $1,200,000,000 with approximately 2 thirds of that expenditure being devoted to sustaining our business. The first quarter spend puts us right on track to meet our annual capital guidance range of $4,500,000,000 to $5,000,000,000 a significant reduction from our $5,800,000,000 capital program in 2017. With increasing production, reduced capital spending and the disciplined cost management driving structural increases in our free funds flow, we are comfortable returning more cash to our shareholders. During the Q1, Suncor's dividend increased by 12.5%, marking the 16th consecutive year of dividend increases. And we've invested $389,000,000 to repurchase approximately 9,000,000 shares. That brought the total since we launched the current program last May to an investment of just over $1,800,000,000 to repurchase over $42,000,000 Semcore shares. That's roughly about 2.6 percent of our outstanding flow. The average repurchase price for the program to the end of Q1 is $42.77 That's more than 12% below our current trading levels. Later this week, we will begin executing on a new 12 month, dollars 2,150,000,000 share buyback program. We finished the Q1 with our balance sheet in robust health, including cash on hand of approximately $2,100,000,000 and approximately $4,800,000,000 in liquidity after funding approximately $1,000,000,000 of acquisitions. Our net debt to fund from operations was 1.7 times and our debt to capitalization was 28%. And of course, we continue to attract a strong investment grade credit rating. The heavy turnaround activity currently underway will obviously have an impact on our 2nd quarter results, but that has been factored into our guidance. All things considered with growth projects ramping up ahead of schedule, reduced capital spending programs on track and major turnaround is expected to wrap up later this month. We should be well positioned for a strong back half to the year. And with that, I'll pass it back to Steve Douglas. Well, thank you, Alastair, Mark and Steve. Just a couple of things to note before we go to questions from the phone. We did have rising crude prices through the Q1. As a result, we had a FIFO gain after tax of $53,000,000 Stock based compensation was a net cost to us of $82,000,000 after tax. On foreign exchange, the Canadian dollar weakened by $0.02 from the end of the year to the end of the first quarter, resulting in a $329,000,000 after tax charge. But that, of course, has no cash impact. That's a balance sheet item on our forward debt payments denominated in U. S. Currency. We did reference our guidance for 2018. There are no changes to production, cash costs or capital, but we have adjusted the business environment to reflect actual pricing in the Q1 and forward curve pricing through the end of the year. The only change that that results in is an increase to our cash taxes. With that, I will turn the call back to the operator to take questions, first from the analyst community and then if time permits from the media. Thank Our first question comes from Phil Grech with JPMorgan. Your line is now open. Yes, good morning. I would be remiss if I didn't start off by congratulating Steve Douglas on his retirement after 28 years. You're definitely going to be missed. So, first question, Alistair, a couple of questions on the quarter, if you don't mind. One would be, if we look at obviously, there are some transitory effects and you guys kind of went through all those. But if you could just maybe quantify for us how you think about the headwind that came from the loss production and the OpEx headwinds in the quarter? And secondarily, just on this working capital that you briefly mentioned, how do you think about how much of that will reverse as we go through the year? Just thinking about cash balances and the balance sheet. Yes, that's a good question, Phil. Thanks for asking that. I would say the headwind from the lost production, we estimated roughly $270,000,000 from a cash flow perspective. And then on the working capital, let me just kind of highlight, I mentioned some of the key things, I'll just give you quantification around those. Price related because of the increase in price of oil from December to March, really is about $450,000,000 of that $1,400,000,000 Now if prices stay where they are, that won't reverse. We had some timing of receivables. We sold the cargo towards an offshore cargo towards the end of March. So that was sitting in receivable. They're always lumpy as you know. That's about $225,000,000 We did build up the inventory as we talked about in the script. So that's about $200,000,000 as we progress in Q2 as we draw that down. And then on the payable side, our annual incentive comp gets paid out, that's a working capital movement. And then we paid the final installments of the 2017 cash tax. So that was about $570,000,000 So at the $1,400,000 I would say about half of it will reverse during the year. Okay. All right. And the rest is related to price. So if it goes price goes down, you'll see some of it reverse. If price goes up, you'll see more going into AR. Okay. That's very helpful. Thanks. I guess the second question would probably be for Mark, just around the ramp up here at Fort Hills. You gave some color about why that is, but it sounds like you didn't want to declare victory yet. So what are you looking for to get more confident that, I guess, in the run rate through the back half of the year? And if you could just update us on your latest thoughts around what the long term cost structure of this asset would be from an operating cost perspective? I think in the past, you've talked low-20s, but just based on what you've seen so far, if you have any color. Hi, Phil. It's Steve. I'll just start and then quickly hand over to Marcus and run us through his views. Overall Hebron and Fort Hills coming up very well. I mentioned it in passing, although we didn't put it in print, we are in excess of 150,000 barrels a day at the facility as we speak. And just to context it before Mark goes into a little more detail, I mean remember that we've got the vast majority of that plant up. It's only the final parts of secondary extraction, which need to come on and we've started the first two of those up. So we've got a pretty high degree of confidence. So whilst not stealing Mark's thunder, we'll be bringing the third one on in a couple of weeks. And if history is anything to go by, we'll be hitting full run rate on this thing well ahead of our schedule. So let me hand over to Mark. Great. Thanks, Steve. Yes. Phil, it's interesting that with Fort Hills, part of the challenge with secondary extraction is parts of it are fully on. We have 100% of the capacity, the flare systems, the solvent recovery systems and such. So what will happen as we bring on the 3rd train is we will end up running into ultimately the constraints of the facility. And so then is there debottleneck beyond that will be determined by exactly where the constraint is, which is true in any facility. It's exactly what we saw at Firebag. And as Steve mentioned, because we're in the process of bringing on the 3rd train here in the coming month, we expect that we will be seeing this and seeing stable rates likely by the end of Q3 here as we go through it. And but it's never over until it's over and that's the word of caution in it because you never know where the constraint is going to be and whether we're going to find some issue through the startup. But so far, it's going extremely well and we're very optimistic about finishing this off. Great. If I could just sneak one last one in for Steve. You continue to find small bolt on opportunities as we look at the portfolio. How do you feel about the rest of this year? Do you still see opportunities ahead? Or is it more business as usual from here, from your perspective? It's from I mean we talked, Phil, about that 500 $1,000,000 a year adding up to $2,000,000,000 a year in cash flow between now and the early 20 20. You've seen our track record over 10 years. We understate and over deliver. That's our plan. You've not seen us change guidance with any of the operating challenge we've had and that's because we have a high degree of confidence we will deliver through our operational excellence for the rest of the year and that includes continuing some of these projects. So the Fort Hills is, as Mark said, he's going to get there 2nd, 3rd quarter. We won't change guidance. We'll report once we've actually achieved that. Syncrude is moving ahead very well. I mean, Mark sort of said it fairly quickly in his update there. But we've already addressed that pipeline sanding issue that we had. So we're fully confident we're past that. So we got to be realistic, but we're cautiously optimistic. We're going to hit and beat the big guidance this year. So yes, you will see some continuing improvements. You'll get a chance to see what we're capable of in the 3rd Q4 as we unconstrained these operations. Okay. I apologize. I was just referring to M and A both times. If you see further opportunities ahead or if it's just operating the business as usual. I would start from we love the base case. We got 10% growth this year, 10% growth next year and then the $500,000,000 a year. We keep an active look in the market and we're in a great position where the base case is so good, we're not chasing anything. There's still a lot of sellers in the market. We keep looking. We've got nothing imminent now at the moment. Okay, perfect. Thanks a lot. Thank you. And our next question comes from Guy Baber with Simmons and Company. Your line is now open. Good morning, everybody. First off, Steve Douglas, congrats on a great run, Matt. I hope your future is filled with a lot of golf and a lot of really fun places. I'm sure it will be. Thank you. And then for my questions, I wanted to talk a little bit more about the resilience to the light heavy differential here. So you all highlighted no impact to cash flow during the quarter. Can you maybe talk a little bit more about how you are outperforming relative to the framework you gave of the 25,000,000 sensitivity? Maybe some examples of what the midstream and marketing team are doing there, which is pretty impressive and whether that's sustainable through the rest of this year? And then can you talk about maybe at a high level, how you see that sensitivity evolving over the next couple of years, and the extent to which your team might be putting plans in place to continue to mitigate some of those spread headwinds? Yes. I mean, I'll start and I'm sure the guys will jump in and help me with some of the details. I mean, first of all, it's as we designed it, not because we're clairvoyance and can see it, but because our strategy is an integrated strategy and we balance with the bitumen we produce in Canada upgrading and downstream. We don't do a perfect balance. So we're about 70%, 80% of those ratios to the upstream, which is why we never say we have no exposure forever going forward. But you can assume, we already purchased that as part of the strategy, the long term access to pipeline to accommodate the Fort Hills production. So it's not 0 exposure to differentials going forward, but you can see with the physical asset integration we have and the management in the midstream, we were able to be completely immune from it in the Q1 and we put a it's an impossible number to give exactly because it's so market specific on the day, but we put in what we believe is a very conservative number into the IR deck which is the one you're talking about. But we don't expect to see any significant exposure to the light heavy differentials through the piece. One of the questions as we look at M and A is, are we prepared to accept more exposure to that? And if we when we look, we factor that into the economics. So we look at what we think those differentials will be and for how long they will be. We've seen some just a few comments and then the guys can jump in after, we've seen some spikes in that differential over the last few months. We expect as rail contracts start to get negotiated that the spikes may not be quite as high, but we still expect there to be a large, light heavy differential until pipelines get built because rail is more expensive than pipelines. And of course the IMO 2020 regulation start to put a pressure in there too. So we like our position. If we do any M and A as we go forward, we will factor in potentially more exposure if that's heavy without the corresponding downstream integration and we think they're going to remain modestly high for a number of years until the pipelines get built. I don't know if you guys want to add anything? Yes. The only thing I would add to that, Steve, is we've always been ramping up for Hill in the quarter. We have been moving product down to the Gulf Coast. So, therefore, on our existing Keystone access, obviously we're not exposed to the higher differential. So, we're getting Gulf Coast pricing for our products, so that's part of it. But that's helpful. And you've seen the premium that we talked about in getting for PFT, bitumen of CAD5, not significant over a CAD27 sort of in situ bitumen price to get a $5 premium for Hill bitumen. So it's an attractive bitumen commanding a strong premium exactly as we thought it would do. Very helpful guys. And then my follow-up is with oil prices where they are right now assuming that holds, I mean once you guys get through some of this turnaround activity, the back half of the year does look pretty good. So you guys should be generating a lot of free cash flow. I really like Slide 11 in your deck where you lay out the fundamental priorities for the free cash over time. But as we think about the back half of this year, specifically, can you maybe walk us through how you're thinking about the usages of excess cash? And specifically, could we see CapEx begin to creep a little bit higher as you put more into business or how do you think about a little bit more CapEx versus more buyback? Would appreciate any color there. I'll just make a few comments there. I mean we really mean what we've been saying in terms of capital discipline. Our capital budget this year, irrespective of crude price is expected to be $4,500,000,000 to $5,000,000,000 You won't see us taking any sharp left or right hand turns. We've got a well established capital expenditure program. We've got the projects being developed and the sort of CapEx profile we've talked about covers that. So if you look at this year with the free cash, because I wouldn't disagree with your analysis, We use share buybacks to handle that short term cyclical variation that we see on cash flow coming in. And then generally, we aim to adjust dividends annually as the underlying fundamental cash flow profile is coming up. So clearly dividends are a board decision, but you can expect to see dividends continuing year on year to come up as the earning power of the company comes up and you'll see us using share buybacks to take up that slack. Thanks very much. Thank you. Our next question comes from Greg Pardy with RBC Capital Markets. Your line is now open. Yes, thanks. Good morning and happy trails Mr. Douglas. Really a lot of my questions have been answered, but maybe this question is more for Mark Little. Could you dig a little bit into the Syncrude turnaround? And then specifically, I think it's what 1 of 3 cokers or 1 of 4 cokers that are down right now. So how much is Syncrude actually down at this stage? Yes, it's one of the 3 cokers that's down. In fact, this is an annual event. So we have this every single year. The plan is to take one of these down. And so this is a planned turnaround. And the only thing that was adjusted was we moved it forward a little bit to deal with this pipeline restriction. So we take the coker offline and clean up the assets and take the coke out of the and kind of replenish it and get it back online. So this is the maintenance and work that we're doing is very routine. The only thing that was different than planned was this restriction. And our view was instead of limping along and then go into a turnaround, we might as well take the asset offline and because we weren't fully utilizing the assets anyway. Okay. That's great. And then just a quick one for me. I mean your exploration expense in the Q1 is really small, like $9,000,000 or so. Are you what are you doing on the exploration side, whether that's North Sea or whether that's East Coast to Canada? Just curious there. Well, it's interesting, Greg, that one of the things we found and one of the joys of our organization is we have this massive resource space. And so you saw our transaction as an example, when we went into Rosebank, our view was is, but we can go and buy resource substantially cheaper than people's finding costs in commercial quantities that then we can commercialize and generate a commercial return for the shareholder. So at this stage of the game, we've had very limited exploration. In some cases, the work that we're doing is around existing assets or improving the 3 d seismic and those sorts of things. So we're very minimal on exploration right now and that's intentional. Okay, great. Thanks very much. Thank you. And our next question comes from Roger Read with Wells Fargo. Yes, thanks. Good morning. I guess maybe one of the things that wasn't really talked about on the opening area, and I know it depends on the pipeline access, but the replication, your target to get to $50 WTI breakeven, Just where do you think you are at this point? What do you think the biggest hurdles are to get there? And quite obviously, let's assume this is a post 2020 event given going on in the pipeline world? Yes. I mean if you look at how the schedule pans out, it's looking to the schedule works very, very well for us. So we're still continuing to work on the details of the replication and the design, but it's looking very promising. We're already starting to get into the ranges where we could approve these projects. But as you say, our plans would be, we don't see major the industry. And one of the big pieces of that is market access. We then have a number of projects which it is possible for us to fruition. And some of these pipelines get nearer to fruition. And as I said in my opening remarks, we are reassured by the provincial and federal governments standing up and being prepared to take these pipeline challenges on there. And we look forward over the next few weeks to see what exactly what those plans look like. But it's working really well. So as I said, we got about 10% growth this year, 10% growth next year. We got these $500,000,000 per year building up to the $2,000,000,000 by 2023 and then we've got this set of projects coming in. So that whole sequence is looking very strong now. Yes, no doubt. Really good visibility on that front. I guess my follow-up question, what are you watching here in terms of the pipelines? What do you want to see coming out of the both governments, provincial and the federal? And what do you see as more likely the access due south or the access to the West Coast in order? Yes, I mean, first of all, we need to see particularly the Alberta government and the Prime Minister himself came over to look at Fort Hills. We spent some considerable time with them going through the competitive challenges the industry has and what we would look to gain confidence to be able to start to allocate capital into the region. Clearly, one of those was pipeline access because we don't want these new projects to have to bear the burden of some of these differentials. So we've been looking a simple measure will be we want to start to see shovels in ground and pipelines being built. Degree of confidence, I don't think in the last 5 years I've had a higher degree of confidence that these lines are going to be built. I think TMX will be built. I think Line 3 will be built. And I think the other lines to the south will be built. So I'm greatly encouraged. Okay. Thanks. And Steve, I forgot to mention at the beginning, but congratulations to you and I hope you do have a good retirement. Thanks very much, Roger. Thank you. And our next question comes from Paul Cheng with Barclays. Your line is now open. And again, our next question comes from Paul Cheng with Barclays. Your line is now open, sir. If All right. Our next question comes from Neil Mehta with Goldman Sachs. Your line is now open. Hey, good morning. And Steve, congratulations and looking forward to celebrating with you in person next week. I guess the first question I had was just around IMO 2020. And you alluded to it, Steve, in your comments about the impact it could have on the light heavy differential. But I want to talk about how you see it both from a macro standpoint for the light heavy for the refining margins, but also just talk about your business because in theory you should be a net beneficiary of it given your downstream business? Yes. I mean, let me start and I'll hand it over to other Steve. I mean you're right from a macro point of view Suncor, we think net net we will actually gain by the IMO 2020 and that's to do with the diesel yields off of our average barrel across the company and the fact that we think demand and prices will be relatively strong there. So overall, the impact for Suncor is a positive one and Steve can talk to the trends. Yes. I think there are kind of 3 things to look at. 1 is light heavies are expected to be wide and we've already talked about the fact that we're really well cushioned against light heavies because of our integration and because of the amount of our bitumen that we actually upgrade or refine. The second piece is not often talked about and that's that sweet synthetic crude or upgraded synthetic actually has a very, very good distillate yield. So I would expect that it will be in demand and will price well versus say tight oil, which is more of a gasoline crude and doesn't have the same distillate cut. And then the third thing is we produce far, far more low sulfur distillate from our refineries than we do bunker fuel. And so while there will be a heavy discount for high sulfur distillate, We produce a great deal of low sulfur distillate and we should benefit from the wider margins. So we're actually looking at this as a net pretty significant positive for Suncor. I don't know if you can comment on this either of the Steve's, but for your planning purposes, what are you using in the early 2020s from a differentials, light heavy differential standpoint TI versus WCS as a result of IMO? I think we have $25 in the plan in that 2021, 2022 period. And that's gone, I think, an $80 crude. Okay. That's great. And then the follow-up question is just how you're together thinking about the cost side of the equation. And we've been every quarter for the last 4 years, we've revised down our cost per barrel. Crude prices are actually starting to move higher here. Are we getting to the point where we should start thinking about cost inflation on a unit cost basis for your portfolio over the next couple of years? I mean just a general comment. I mean in the real world we're not seeing cost pressure as we speak at the moment and if we look at the cost reductions we've done, we've always talked about it being in the 60%, 70% and in some cases 75% depending on the business. The costs are largely systematic, so they're not reversible. So we're not expecting to see any significant increase. We have still got some more to deliver from our program. So if you think of the automation, when the automation of the truck fleet is fully finished, we think that that's worth about $1 a barrel to us on those barrels. So we still got programs in place which are putting some downward pressure on costs. We haven't updated Fort Hills because it's too early, but clearly we'll get a much clearer line of sight as we start to come up to full capacity. And all I would say is that the first signs are very encouraging and between you and me, we won't mention it to many people, the target we've set for the business is $20 a barrel. Okay, that's great. Thank you. And that's right the way across that oil sands business. We still see $20 a barrel is a possibility. Still have some work to do to get there and that's around the reliability, but we still see that as a possibility and the equivalent for Syncrude is we still believe with the work that Mark team are doing now that we can get to 90% reliability and $30 a barrel by 2020. That's great. Thanks guys. Thank you. And our next question comes from Amir Arviz with Cormark Securities. Your line is now open. Thanks. Good morning guys. Just a few questions for you. The $500,000,000 of increased funds flow, Steve, that you mentioned from your operating and margin initiatives that you're undertaking, The just curious how much capital would be required to achieve that? I understand it's over 3 years. Yes, Harry, it's sorry, it's very minimal capital. We're really looking at minimal capital, low intensity spend to achieve lots of technology. But we're really within that sort of $4,500,000,000 to $5,000,000,000 capital targets that we'll lay down. Okay. And is that it seems like it's from a lot of little projects. Is that lumpy or it is just linearly will come in over the 3 years in terms of the improvement in Yes, it's a lot of small projects. So we would expect it to be relatively straight lines. Okay. Sounds good. And then at Fort Hills, the production number again coming in strong just shy of 30, but the sales volumes were only 8. Is that just a normal startup as you do tank sales and line sales or are you actively holding back production based on the bitumen market? No, no. It's exactly what you said in the beginning. It's we start production, you got to fill your lines and fill your tanks. So, we started production and then we started selling at the beginning of March after we filled lines and tanks, exactly that. Okay. And then the price realization at Fort Hills specifically, it's better than your average bitumen realization in the other oil sands. Is there a difference in quality or is there a difference in that bitumen grade, that Fort Hills versus your other bitumen? Yes, that's a great question, Amir. And one of the things we do with Fort Hills bitumen is we literally cut off the bottom 10% of the barrel and we remove a bunch of the carbon and put it back in the ground. So instead of waiting until it's a greenhouse gas and then spending a lot of money trying to figure out how to get it back in the ground or container offset it, we cut out the carbon right away. So the quality of the barrel that goes to market is much better than a normal bitumen barrel. In fact, on a full lifecycle basis, it has essentially the same greenhouse gas emissions as the average barrel run-in U. S. Refining, which isn't the way a lot of people look at oil sands. So the quality is very good. The yield structure is higher and it has a lower greenhouse gas emissions. Okay. Okay, interesting. And then just a final question on the downstream side. I mean, the crack spreads are still strong and you're running already at 98% utilization rate. Is there any opportunities? Or is this part of some of the initiatives that you're looking at in terms of capacity creep that you might be able to do on the downstream side? Well, we're one of the things we're looking at is exactly that is what is the capacity creep and how does it fit in with the markets in the various regions and such. So that's something that we're looking at as part of our planning process. Okay. Do you have a like do you feel that you could grow capacity a few percentage points? Well, there's definitely sorry, there's definitely opportunities there. I think one of the things we're looking through is where the best opportunities for the organization and then how do they fit with all the spreads and expected market conditions and where do we think the cracks are going. So that's the ongoing debate. Obviously, we haven't announced anything yet. So it's something that's still under consideration. Okay, terrific. Thank you. Thank you. And our next question comes from Joe Gemino with Morningstar. Your line is now open. Thanks guys. You touched on that you won't make any investments in oil sands unless you have a clear line of sight into something that improves the environment. In that scenario, how do you see yourself deploying your cash? Is that where you would increase share buybacks? Is that where you would increase the dividend? Yes. I mean, I think our capital allocation will be quite clear. Our run rate for sustaining capital and the small incremental growth programs that we've been talking about is in that $4,000,000,000 to $5,000,000,000 a year range. So that will be a constant through the piece. Dividends are forever as far as we're concerned. So as the long term, we like to be able to pay our dividend at a very low crude price. It's not subject to the commodity price cycle. So we've been steadily increasing that. We're now in our 16th year of increasing that and the balance will be share buyback. So we do not see ourselves making major investments in Canada until we can see some clarity on market access issues. Great. Thank you. Thank you. And our next question comes from Harry Mateer with Barclays. Your line is now open. Hey, good morning guys. I appreciate the comments earlier on around working capital changes. Just wanted to clarify on your short term debt balance creeped up a bit. Do you have any intentions in terming it out or is that going to kind of draw down over time as the working capital reverses? Yes. That was a planned event. As you look forward to your cash flow coming in, we're positioning ourselves to be able to pay that down certainly as the working capital resources and then as we generate more cash towards the end of the year and into next year. Great. Thank you. That's all for me. Thank you. And that brings an end to our Q and A session for today and to our call. Your call has concluded for today and thank you for participating. You may all disconnect. Everyone have a great day.