Suncor Energy Inc (SU) 2018 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Suncor Energy first-quarter 2018 financial results call. (Operator Instructions). 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.

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; Alister Cowan, 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 first-quarter 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 first-quarter earnings release. After the formal remarks we will open the call to questions first from members of the investment community and then, if time permits, members of the media. With that I will 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 would also like to welcome Trevor Bell who is transitioning into Investor Relations role and I know that he will 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 first quarter of 2018 featured the highest average oil prices since the fourth quarter 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 will meet our commitments on reduced capital spending. We will avoid growth for growth's 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 midstream 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 first quarter the WCS WTI price differential averaged 24 US barrels -- USD24 per barrel and that's versus just USD12 per barrel in the fourth quarter of last year. So that near doubling of the light/heavy differential had absolutely no impact on our earnings or cash flow. 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 first quarter. 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 will 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 rollout autonomous haul trucks across our mines, a global first for soft rock mining.

Our North Steepbank 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 certainly have 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 first-quarter guidance, effectively delivering three months of production in just February and March. And with the start up of our second solvent extraction unit on April 22, we've now successfully run the plant at over 150,000 barrels per day.

So with the start up of the third 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 first quarter. We were anticipating average net production for this year of about 10,000 barrels per day at Hebron. With a third production 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 million 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 co-gen units through the use of advanced analytics to reduce maintenance costs and optimize facility throughput. And to more simple measures like employing remote sensor technology 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 products and we believe that they will increase our annual cash flow by more than $2 billion by 2023.

So the real strength of our growth plan for the next five or six years is our 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 barrel.

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 our 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 first quarter. Mark?

Great. Thanks, Steve, and good morning, everyone. As Steve mentioned, we dealt with some operational challenges in the first quarter 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 bridged 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 first quarter 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 one month so that the issue with the froth 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 preventing reoccurrence. We expect Syncrude to complete the turnaround and return to normal operations in the next couple of weeks.

In situ operations continued to be extremely reliable as Firebag and MacKay River combined to produce 241,000 barrels per day of bitumen, equal to 100% 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 start up 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 first four 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&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 first quarter at Terra Nova, Hibernia and White Rose 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 first quarter. Crude throughput averaged 454,000 barrels per day, which equates to 98% of nameplate capacity. Building inventory for the second-quarter refinery turnaround also helped 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 cost came in at $26.85 per barrel in the first quarter. 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 which started at the beginning of April.

Of note our all in in situ cash cost averaged $9.55 per barrel in Q1. That is in situ's third consecutive quarter of sub $10 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&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 cost 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 were able to reduce operating expenses to just $4.90.

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 will turn it over to Alister Cowan to provide some color on our financial results. Alastair?

Thanks, Mark, and good morning. With an average WTI price of USD62.90 and a New York Harbor 3-2-1 refining crack of USD15.50 per barrel, the business environment in Q1 was stronger than we've seen in some time.

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 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 then to CAD27.57 for in situ bitumen, reflecting the unusually high Western Canadian light/heavy differential. Fort Hills [higher coal to] PFT bitumen realized a premium of approximately CAD5 per barrel over in situ bitumen. And the offshore production realized very close to Brent pricing with East Coast currently 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 CAD30.25 per barrel versus the New York harbor CG1 crack of CAD19.60 per barrel.

With (inaudible) realized margins across the business we delivered strong financial results again in the quarter. We generated $2.16 billion in funds from operations and $985 million in operating earnings in the first quarter and our return on capital employed improved to 7.8%, excluding major projects in progress.

Our funds from operations for the first quarter significantly exceeded our sustaining capital plus our dividend, leaving $755 million in discretionary free funds flow to invest in growth and return to shareholders.

I said that there were 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 million due to the annual payout of stock-based compensation which we accrue to earnings on a quarterly basis, but it only hits our cash flow on the annual basis in the first quarter.

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 $1.4 billion in the first quarter, and that's really a result of an increase to accounts receivable on an improving price environment, a substantial build of product inventory in advance of major turnarounds, and the payment of deferred 2017 tax installments. Now obviously some of this build in working capital will reverse in Q2 and later in the year.

As everyone is aware [of the start at] Fort Hills and Hebron, we have reached the end of a period of intense capital spending on large growth projects. So in the first quarter our total capital expenditures were $1.2 billion with approximately two-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 $4.5 billion to $5 billion, a significant reduction from our $5.8 billion 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 first quarter Suncor's dividend increased by 12.5%, marking the 16th consecutive year of dividend increases, and we invested $389 million to repurchase approximately 9 million shares.

That brought the total since we launched the current program last May to an investment of just over $1.8 billion to repurchase over 42 million Suncor shares. That is roughly about 2.6% of our outstanding float. 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 2.15 billion share buyback program.

We finished the first quarter with our balance sheet in robust health, including cash on hand of approximately $2.1 billion and approximately $4.8 billion in the liquidity after funding approximately $1 billion 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 second-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 turnarounds expected to wrap up later this month, we should be well-positioned for a strong back half to the year. With that I'll pass it back to Steve Douglas.

Well thank you, Alister, 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 first quarter. As a result we had a FIFO gain after tax of $53 million, stock-based compensation was a net cost to us of $82 million after-tax.

On foreign exchange the Canadian dollar weekend by $0.02 from the end of the year to the end of the first quarter resulting in a $329 million after-tax charge, but that of course has no cash impact. That is a balance sheet item on our forward debt payments denominated in US 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 first quarter 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.

(Operator Instructions). Phil Gresh, JPMorgan.

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.

Thank you, Phil. I appreciate it.

So first question, Alastair, a couple 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 lost 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 million from a cash flow perspective. And then on our working capital, let me just highlight -- I mentioned some of the key things but I'll just give you some quantification around those.

Price related, because of the increase in price (inaudible) from December to March really is about $450 million of the $1.4 billion. Now if prices stay where they are that will 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 receivables. They are always lumpy, as you know. That's about $225 million.

We did build out the inventory as we talked about in the script, so that is about $200 million and that should reverse in Q2 as we draw that down. And then on the payable side our annual incentive comp gets paid out after working capital movement and then we paid the final installments of the 2017 cash taxes, so that was about 570. So of the $1.4 billion, obviously about half of it will reverse during the year.

Okay. All right, that's very helpful.

And the rest is related to price, so if it goes -- if the price goes down you will see some of it reverse. If price goes up you will 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 quickly hand over to Mark who can run us through (inaudible). 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 presents a little more detail, remember that we've got the vast majority of that plant up. It is only the final parts of secondary extraction which need to come on and we've started the first two of those so we've got a pretty high degree of confidence.

So whilst not stealing Mark's thunder, we will be bringing the third one on in a couple weeks. And if history is anything to go by, we will 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 third train is we will end up running into ultimately the constraint 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 were in the process of bringing on the third train here in the coming months, we expect that we will be seeing this -- stable rates likely by the end of the third quarter here as we go through it.

But it's never over until it's over and that's the word of caution because you never know where the constraint is going to be and whether we're going to find some issue through the start up. But so far it's going extremely well and we are 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?

We talked, Phil, about that $500 million a year adding up to $2 billion a year in cash flow between now and the early 2020s. You've seen our track record over 10 years. We understate and over deliver, that's our plan.

You've not seen as 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 second throughout third quarter. We won't change guidance; we'll report once we've actually achieved that. Syncrude is moving ahead very well. I think Mark said it fairly quickly in his update there, but we've already addressed that pipeline (inaudible) issue that we had, so we are fully confident we are past that.

So, we've got a be realistic but we are cautiously optimistic we're going to beat guidance this year. So, yes, you will see some continuing improvement. You'll get a chance to see what we are capable of in the third and fourth quarter as we unconstrain these operations.

Okay, I apologize. I was just referring to M&A bolt-ons, 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 $500 million a year. We keep an active look in the market, but 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 eminent though at the moment.

Okay, perfect. Thanks a lot.

Guy Baber, Simmons and Company.

First off, Steve Douglas, congrats on a great run, man. 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 million 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?

I'll start and I'm sure the guys will jump in and help me with some of the details. First of all, it's as we designed it, not because we are clairvoyant 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 are about 70%-80% of those ratios to the upstream, which is why we never said we have no exposure forever going forward.

But you can assume we already purchased -- that was part of the strategy -- the long-term access to pipelines to accommodate the Fort Hills production. So it's not zero 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 first quarter.

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 debt which is the one you are talking about. But we don't expect to see any significant exposure to the light/heavy differential through the peaks.

One of the questions as we look at M&A is are we prepared to accept more exposure to that. And 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.

I don't -- we've seen some -- and 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 annual 2020 regulations start to put pressure in there too. So we like our position. If we do any M&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 are 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.

The only thing I would add to that, Steve, is we have obviously been ramping up Fort Hills in the quarter. We have been moving product down to the Gulf Coast, so therefore on our existing Keystone access, so obviously we're not exposed to the Hardisty differential. So we are getting Gulf Coast pricing for our products so that's part of it, but that's helpful.

And you are seeing the premium that we talked about and getting for PFT bitumen of CAD5. Not significant over our $27 in situ bitumen price to get a $5 premium Fort Hills bitumen. So it is 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, 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 the business? Or how do you think about a little bit more CapEx versus more buyback? Would appreciate any color there.

Yes, Guy, I'll just make a few comments there. 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 $4.5 billion to $5 billion. 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 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 the 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 could expect to see dividends continuing year on year to come up as the earning power of the Company comes up. And you will see us using share buybacks to take up that slack.

Thanks very much.

(Operator Instructions). Greg Pardy, RBC Capital Markets.

Happy trails, Mr. Douglas. Really a lot of my questions have been answered, but maybe it's a question more for Mark Little. Could you dig a little bit into the Syncrude turnaround? And then specifically -- I think it's one of three cokers or one of four cokers that are down right now. So how much is Syncrude actually down at this stage?

Yes, it's one of the three 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 off-line and clean up the assets and take the coke out of it and 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 off-line because we weren't fully utilizing the assets anyway.

Okay, that's great. And then just a quick one from me. Your exploration expense in the first quarter is really small, it was like $9 million or so. What are you doing on the exploration side, whether that's North Sea or whether that's East Coast of 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 use all our transaction, as an example, when we went into Rosebank. Our view was, well, we can go and buy resource substantially cheaper than peoples' 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 are doing is around existing assets or improving the 3-D seismic and the sorts of things. So, we are very minimal on exploration right now and that's intentional.

Okay, great. Thanks very much.

Roger Read, Wells Fargo.

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 what's going on in the pipeline world.

I mean, if you look at how this schedule pans out it's looking -- the schedule works very, very well for us. So we're still continuing to work on the details 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 investment in the Canadian Oil Sands until we see an improvement in the competitive position of 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 execute and we think those will have good returns.

So the technology is developing well, the plans are developing well and we need to see 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 now. 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've got about 10% growth this year, 10% growth next year. We've got these $500 million per year building up to the $2 billion by 2023. And then we've got this set of products 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 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?

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'd be looking -- the 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 five 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.

Paul Cheng, Barclays. Our next question comes from Neil Mehta with Goldman Sachs.

Steve, congratulations. I'm looking forward to celebrating with you in person next week. I guess the first question I had was just around IMO 2020. You alluded to it, Steve, in your comments about the impact it could have on the light/heavy differential. But wanted 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.

Let me start and then I'll hand it over to the other Steve. You're right, from a macro point of view for 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 three things to look at. One is light/heavies are expected to be wide. And we've already talked about the fact that we are 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 of those 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 are 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 Steves, but for your planning purposes what are you using in the early 2020s from a differential -- light/heavy differential standpoint, TIW versus WCS as a result of IMO?

I think we have $25 in the plan in that 2021-2022 period. And that's on I think an $80 crude.

Okay, that's great. And then the follow-up question is just how you guys are thinking about the cost side of the equation. And we've been -- every quarter for the last four 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 years?

I mean just a general comment. In the real world we're not seeing much 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. But costs are largely systematic so they are not reversible. So we are 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've still got programs in place which are putting some downward pressure on cost.

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 the first signs are very encouraging. And between you and me -- we don'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's team is doing now, that we can get to 90% reliability and $30 a barrel by year 2020.

That's great. Thanks, guys.

Amir Arif, Cormark Securities.

Just a few questions for you. The $500 million of increased fund flows, Steve, that you mentioned from your operating and margin initiatives that you are undertaking. Just curious, how much capital would be required to achieve that? I understand it's over three years.

It's very minimal capital. We're really looking at minimal capital, low intensity spend to achieve lots of technology. But really within $4.5 billion to $5 billion capital targets that we'll bleed out.

Okay and is that -- it seems like it's from a lot of little projects. Is that lumpy or it linearly will come in over that three years in terms of the improvement in (multiple speakers)?

It's a lot of small projects so we'd expect it to be relatively straight lined.

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 normal startup as you do tank fills and line fills? Or are you actively holding back production based on the bitumen market?

No, it is exactly what you said at the beginning. You start production you've 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 on 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 at Fort Hills versus your other bitumen?

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 contain or 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 US 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 emission.

Okay, that's interesting. And then just a final question on the downstream side. The crack spreads are still strong and you're running already at a 98% utilization rate. Is there any opportunities or is this part of the initiatives that you are looking at in terms of capacity creep that you might be able to do on the downstream side?

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 are looking at as part of our planning process.

Do you feel that you could grow capacity a few percentage points without --?

There's definitely opportunities there. I think one of the things we're looking through is where are 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.

Joe Gemino, Morningstar.

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 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 million to $5 billion 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 are now in our 16th year of increasing that and the balance will be share buybacks. So, we do not see ourselves making major investments in Canada until we can see some clarity on market access issues.

Great, thank you.

Harry Mateer, Barclays.

Appreciate the comments earlier on around working capital changes. Just wanted to clarify on your short-term debt balance, it has creeped up a bit. Do you have any intentions in terming it out or is that going to draw down over time as the working capital reverses?

Yes, that was a planned event. As we look forward to our cash flow coming in, we're positioning ourselves to be able to pay that down certainly as the working capital reverses and then as we generate more cash towards the end of the year and into next year.

Thank you and that brings an end to our Q&A session for today and to our call. Your call has concluded for the day and thank you for participating. You may all disconnect. Everyone have a great day.