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Edited Transcript of IMO.TO earnings conference call or presentation 2-Aug-19 3:00pm GMT

Q2 2019 Imperial Oil Ltd Earnings Call

CALGARY Aug 8, 2019 (Thomson StreetEvents) -- Edited Transcript of Imperial Oil Ltd earnings conference call or presentation Friday, August 2, 2019 at 3:00:00pm GMT

TEXT version of Transcript

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Corporate Participants

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* Daniel E. Lyons

Imperial Oil Limited - Senior VP of Finance & Administration and Controller

* Dave Hughes

Imperial Oil Limited - Manager of IR

* Richard M. Kruger

Imperial Oil Limited - Chairman, President & CEO

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Conference Call Participants

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* Benny Wong

Morgan Stanley, Research Division - VP

* Dennis Fong

Canaccord Genuity Corp., Research Division - Exploration and Production Analyst

* Emily Christine Chieng

Goldman Sachs Group Inc., Research Division - Associate

* Greg M. Pardy

RBC Capital Markets, LLC, Research Division - MD and Co-Head Global Energy Research

* Jon Morrison

CIBC Capital Markets, Research Division - Executive Director of Institutional Equity Research

* Manav Gupta

Crédit Suisse AG, Research Division - Research Analyst

* Mike Dunn

* Philip Mulkey Gresh

JP Morgan Chase & Co, Research Division - Senior Equity Research Analyst

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Presentation

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Operator [1]

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Good day, ladies and gentlemen, and welcome to the Imperial Second Quarter 2019 Earnings Conference Call. (Operator Instructions)

I would now like to turn the conference over to your host, David Hughes, Investor Relations. You may begin.

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Dave Hughes, Imperial Oil Limited - Manager of IR [2]

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Thank you, and good morning, everybody. Thanks for joining us on our second quarter earnings call. I'll start by introducing you to who is in the room. We have Rich Kruger, Chairman, President and CEO; Dan Lyons, Senior Vice President, Finance and Administration; and Theresa Redburn, Senior Vice President, Commercial and Corporate Development.

Just before we get going, I want to start by noting that today's comments may contain forward-looking information. Any forward-looking information is not a guarantee of future performance, and actual future financial and operating results could differ materially depending on a number of factors and assumptions. Forward-looking information and the risk factors and assumptions are described in further detail in our first -- or sorry, second quarter earnings release that we issued earlier this morning as well as our most recent Form 10-K, and all those documents are available on SEDAR, EDGAR and on our website, so please refer to them.

When we get started here, Rich is going to open up with the business overview and then turn it over to Dan Lyons, who's going to provide a financial overview for the quarter. Then Rich will provide some further details on the operating performance. And once we're through that, we will turn it over to Q&A. We have had some questions submitted via our -- the Slido application earlier this morning, so we'll be mixing those in with live Q&A.

So with that, I'll turn it over to Rich.

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Richard M. Kruger, Imperial Oil Limited - Chairman, President & CEO [3]

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Good morning. Before I start detailing the second quarter results, I'd like to offer a few comments on the overall business environment. And I'll focus my comments in 2 areas: crude prices or the price environment; and then politics and policies.

First of all, prices, WTI, about $60 in the quarter, a bit higher, $5 a barrel or so higher than the first quarter and about $8 a barrel lower than it was a year ago. So somewhere in the range of what we'll spend a lot of time comparing to. You saw the Canadian Light or MSW up essentially the same, $5 a barrel quarter-to-quarter. And then Canadian Heavy or MSW was up about $7 a barrel in consecutive quarters. That averaged $49 in 2Q. So consequently, if you take quarter-over-quarter differentials, they remain essentially flat year-to-date. The MSW to WTI at about $5 a barrel for both the first and the second quarter, and then the Canadian Heavy or WCS to WTI in -- averaging between $11 and $12 a barrel [again] across the 2 quarters.

On politics. On April 16, Jason Kenny was elected the new premier of Alberta. And I would characterize it, that is, government has not wasted any change in making -- any time in making pro-business changes. Some of the changes most notable for the oil and gas industry. Bill #1, which repeal the prior administration's carbon tax. This will result in annual savings for our company. The amount remains to be determined. And Bill #3, which reduced corporate income tax rate from 12% to 8% over 4 years, starting this year, which -- this is detailed in -- or will be detailed -- or is detailed in our second quarter release we'll talk more about. This reversed an increase 4 years ago from 10% to 12%. The government of Alberta's curtailment program has remained in effect with modest easing of constrained volumes over time, and I'll offer more comments on this program and its impact on us throughout the review.

So with that, I'm going to turn it over to Dan to go through the financial performance before I come back and talk more about operational performance.

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Daniel E. Lyons, Imperial Oil Limited - Senior VP of Finance & Administration and Controller [4]

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Thanks, Rich. Good morning, everybody. I'll start with our net income. Second quarter net income was slightly over $1.2 billion, which included a $662 million favorable impact from the Alberta corporate tax rate change that Rich referenced. On June 28, Alberta government's Bill 3 received Royal Assent and came into effect. So Imperial has the substantial deferred tax liabilities, and the rate reduction reduces those liabilities and generated that onetime gain. The $660 million roughly benefit is split between $690 million benefit in the Upstream segment, actually a slight negative for Downstream of $10 million and a slight negative for [corp and fin] of about $20 million. Now excluding this impact, Imperial earnings were $550 million, up $257 million from the first quarter of '19 and up $354 million from the second quarter of '18.

Relative to the first quarter of '19, Upstream earnings increased more than $900 million. Excluding the tax impact, Upstream earnings increased almost $240 million to just under $300 million. That was driven by higher prices and higher volumes.

Relative to the first quarter, Downstream earnings were flat as higher margins were offset by planned maintenance and a fractionation tower incident at Sarnia that we will talk about more later.

Moving on to talk about cash. Cash generated from operating activities was $1 billion in the second quarter, essentially the same as the first quarter of '19. So for the first half, just over $2 billion of cash generation. That's the highest cash generated from operating activities for our first half since 2014, where we generated just under $2.1 billion. It's interesting to note that Canadian Heavy or WCS averaged $79 a barrel in the first half of 2014, 5 years ago, whereas in the first half of 2019, it averaged just $46 a barrel. Clearly, our integration and balance across the Upstream, refining and petroleum product sales continues to support the strength and resiliency of our cash-generating capability across a range of market conditions.

Moving to capital expenditures. In the second quarter, those totaled $429 million, bringing the first half of 2019 to $958 million. Upstream expenditures of $673 million represented 70% of the total in the first half. We had spending on key projects in both the Upstream and Downstream. These included the drill pressure; Aspen, albeit in the case of Aspen, ramping down; included the Strathcona cogen project and the Alberta products pipeline. Those together total $420 million in the first half. Recall after the first quarter, we modified our CapEx guidance for the full year to take account for the slowdown of the Aspen project. Our guidance at that time was $1.8 billion to $1.9 billion for the full year. Our current outlook is consistent with that guidance.

Moving to dividends and share buybacks. Our capital allocation strategy remains unchanged. We want to maintain a strong balance sheet, pay a reliable and growing dividend, invest in attractive growth opportunities and return surplus cash to shareholders through buybacks. Our balance sheet remains strong. We have $5.2 billion of debt, a 17% debt-to-capital ratio. At the end of the quarter, we had $1.1 billion in cash. In the second quarter, we paid $147 million in dividends at $0.19 a share, an increase from $132 million and $0.16 a share in the second quarter of '18.

In July, just a month or so ago, we paid $169 million in dividends at $0.22 a share, consistent with our announcement in April to increase the dividend by an additional $0.03 a share from the dividends paid in the second quarter. We continued share buybacks in the second quarter, consistent with our Toronto Stock Exchange-approved normal course issuer bid program, allowing us to purchase up to 5% of outstanding shares over the June 2018 to June 2019 period. We fully utilized this program by purchasing the maximum allowable shares at about $40 million, returning almost $1.6 billion in cash to shareholders over the 12-month period.

In June this year, we received approval from the Toronto Stock Exchange for a new normal course issuer bid running from June '19 through June 2020. That approval allows us to repurchase just over 38 million shares. Again, 5% of outstanding shares between June 27, 2019 and June 26, 2020. We plan to continue to execute to our buybacks ratably, roughly 9 million to 10 million shares per quarter, ExxonMobil also intends to continue to participate, maintaining its overall ownership at 69.6%. At Imperial, we continue to see our share purchases as a flexible way to manage our capital structure and distribute surplus cash to our shareholders.

With that, I'll turn it back to Rich to discuss our operating performance.

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Richard M. Kruger, Imperial Oil Limited - Chairman, President & CEO [5]

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Very good. I'll start with Upstream production. Production averaged 400,000 oil equivalent barrels per day in the second quarter. This is up 64,000 oil equivalent barrels a day or 19% from the second quarter of last year. Relative to the first quarter, we were up 3% or 12,000 oil equivalent barrels per day. The second quarter represented our highest second quarter in over 25 years, and it was the fourth highest of all quarters over the same 25-year period. The second quarter typically includes major turnarounds, and this year was no exception. We had turnarounds at Cold Lake and Kearl. I'll comment more on those in a moment. And for context, over the past 3 years, with fundamentally the same operating asset base, second quarter production has averaged about 332,000 barrels a day, so we were 17% higher this year with the typical major maintenance performed but also without a series of unplanned outages that have occurred in recent years, most notably at Syncrude.

So if I step back, from most any angle, this second -- this year's second quarter production of 400,000 oil equivalent barrels per day, I would characterize as exceptionally strong. While the first half, we averaged 394,000 oil equivalent barrels per day compared to 353,000 in the first half a year ago and an average of 361,000 over the prior 3 years. So 9% to 10% higher than the more recent years.

Liquids in the quarter, 300,000 in the second quarter or 377,000 barrels a day. 94% in total production in the first half. They were 370,000 barrels a day. If I look ahead of the third quarter, we anticipate total production in the same range as 2Q, plus or minus the 400,000-barrel-a-day range. We do have major maintenance planned in the third quarter, both at Kearl and at Syncrude, and I'll detail those more here in a moment. The outlook includes some estimated impact of the government of Alberta's ongoing curtailment program. And we continue to work with the government to minimize any curtailment impact, recognizing that the third quarter typically includes some of our highest individual months of production each year.

Continuing with Kearl. On a gross basis, we produced 207,000 barrels a day at Kearl in the -- 2Q, up from 180,000 in 2Q a year ago. This was by far the highest second quarter in the asset's history, and it was the third highest of any quarter in the asset's history. It was also achieved despite completing the largest turnaround Kearl has ever had. The turnaround impact to gross production by an estimated 46,000 barrels a day in 2Q or on a year-to-date basis, about 23,000 barrels a day. The turnaround itself was completed ahead of schedule. It was on budget, and most importantly, it was completed injury-free, which included a peak workforce of more than 1,500 individuals on site. Scope: normal inspections, repairs, some supplemental crusher work, some preparatory tie-in for those crushers. Total cost gross basis, a bit over $100 million. About $72 million Imperial share. It was completed in 30 days versus the plan of 32 mid-May to mid-June. And it compares similar in cost and scope to the turnaround Kearl had a year ago.

Now coming out of the turnaround. Since essentially mid-June, we've had quite strong performance for reference for the asset's top 10 highest-ever production days have occurred all days in excess of 320,000. We had a 338,000 kbd maximum daily rate in there. And post that turnaround, we've averaged essentially 250,000 barrels a day throughout the second half of June and through July. So the -- that 207,000 in the second quarter, well above our earlier guidance that had pointed you more toward about 180,000 barrels a day for 2Q. Our full year outlook for '19 remains confident that'll be above 200,000 barrels a day, consistent with last year's 206,000. And at the halfway mark, we're at 193,000 barrels a day at a gross basis. In a year ago, we were at 181,000, so we're well positioned. And I'd add that through July, adding another month to the data. The year-to-date has now increased to literally 200,000 barrels a day, whereas a year ago, through the first 7 months, we were at 190,000.

So it -- all signs would point toward our confidence in being at or above that 200,000 where we were last year, so maybe suggestion we'd be higher than that. We do have another turnaround plan for the other plant at Kearl that will start in the first half of September. It's about a 5-week scope of work, quite similar to the work we completed here in the second quarter. It will have an impact that will affect volumes in both 3Q and a little bit of a carryover to 4Q. When we take all of that into account, we're anticipating Kearl to be in the range of 215,000 to 220,000 thereabouts for the third quarter. Our supplemental crushing capacity project and the flow interconnection work that is designed to take us from the 200,000-barrel-a-day annual average to a 240,000 or beyond is on schedule and everything is pointed toward the year-end '19 startup that we've communicated consistently now for some time.

At Cold Lake, we produced 135,000 barrel a day in 2Q. It was down 10,000 from the first quarter and up 2,000 kbd from second quarter of a year ago. We had previously communicated in our first quarter call that we anticipate a second quarter production to be in the range of 130,000 to 135,000. We had major turnaround work at Mahkeses plant, and we performed at the upper range of our expectations. Mahkeses is one of Cold Lake's 5 plants. It averages about 32,000 barrels a day or so on average. The scope of work there that we do on a 5- or 6-year cycle: regulatory inspections, some line cleaning, base repairs, fundamental maintenance. We completed that over a 32-day period, from late April to late May. Cost was about $30,000 -- about, excuse me, $30 million. And the production impact was -- round number is about 12,000 barrels a day in the second quarter. Here again, we had a peak workforce of 700 individuals on site. The work was completed 4 days ahead of schedule, and I'm very pleased to say, injury-free. The -- a year ago, we had a turnaround at the Moscow plant, which was similar in scope duration cost to this year's work. With this work now behind us, in the third quarter, we expect to average somewhere in the 145,000 to perhaps as high as 150,000 barrels a day at Cold Lake. Relatively flat over each of the month in the third quarter.

Turning to Syncrude. Our 25% share of Syncrude production averaged 80,000 barrels a day in the 2 -- in the second quarter compared to 78,000 barrels a day in the first quarter and 50,000 barrels a day in the second quarter of last year. The 80,000 for this quarter was consistent with what we had previously communicated and consistent with our expectations for the quarter. With the reliability we've now been experiencing at Syncrude, the first half at 79,000 is the highest first half in the asset's history. The previous best was in 2011 at 75,000 barrels a day. And when you take into account last year's fourth quarter, we're now on the strongest 9-month run, again, in the asset's history. Syncrude is a designated operator in Alberta. So what that means is it's subject to specific orders associated with the government of Alberta's mandatory curtailment program. And the negative impact of these orders have been largely, although not entirely, offset by purchase production quotas -- credits from other operators, and we as Imperial have contributed to providing those credits to the Syncrude asset.

At third quarter, our share production at Syncrude is expected to be in the 60,000 to 70,000-barrel-a-day range. It will be impacted by scheduled turnaround work. Specifically, there'll be a turnaround on one of Syncrude's 3 cokers, the 8-1, that will start in the third quarter and continue into the fourth. A very large scope of work. Our share of cost is estimated to be in the $85 million range, so you can see the gross process in the $350 million-plus-or-minus range. It's a long slip of work. 75 days. It will start in the second half of August. And we anticipate it will go in -- early into November. About a 10,000 kbd impact in the third quarter. And we would estimate, at this point in time, a comparable impact in the fourth quarter.

Crude-by-rail, with a little bit of history here with market forces working [unconstrained, pipeline's] full. You recall industry crude-by-rail out of Western Canada, it increased rapidly in late '18, and it peaked in excess of 350,000 barrels a day in December. Then came the government of Alberta's mandated curtailment order. Crude-by-rail economics nearly instantly eroded. And so you saw a lot of volatility, a bit of a roller coaster for industry in our Edmonton Rail Terminal as well where it came off of those peaks, industry's crude-by-rail was half of the December level by March and now has moderately increased a bit over the second quarter. And you -- we've seen similar performance for us to the extent that we averaged 64,000-barrels-a-day crude-by-rail in the second quarter, but it was an increasing profile of we were in the mid-30s in April, in the mid-80s in June, and that's what got to the average over the course of the quarter.

The -- all of our decisions are economic-based. And so in February, when we had the terminal shut down, it didn't make any money. And in the second quarter, when we've increased it, we're back in the black-making money. But I think it's important to note the volatility here, both in what you see from us but as important overall, the industry, the volatility really highlights what we consider to be a very negative unintended consequence of the curtailment order.

If I step back and look at where the province is right now in terms of provincial crude inventories, there have been progress in reducing the inventories. At the end of the year, we were essentially -- the industry was essentially at tank tops. 34 million, 35 million barrels in crude inventories. We saw some variation over the first several months of the year, but we remained high at the 34 million, 35 million through April and into May. Now most recently, publicly reported numbers have suggested inventories have dropped to 27 million barrels, plus or minus, in the middle of July. We commented in our first quarter earnings call that we would anticipate that, particularly with a lot of the major maintenance that would be occurring. But where we are today is the lowest provincial inventory since November 2017. And our view is this restores much needed flexibility within the system.

So back to curtailment specifically. The original orders for the government called for a 325,000 barrels a day was held across industries effective January of this year. There have been a series of allocation increases over time, reducing that 325,000 to 175,000. Through July-August, industry was given another 25,000 barrel a day increase. And now we received the orders for September, which provided a further 25,000-barrel-a day increase. So the 325,000 has been reduced by about 200,000, suggesting there's still curtailment orders that would withhold about 125,000. We believe, with the inventory cushion that now exist, that the government of Alberta can and should further reduce curtailment levels, if you do some math, 100,000 barrels a day over 30 days is 3 million barrels. With inventories 7 million or 8 million below tank tops, we think there's flexibility. And the time is now to test this system and see what differentials do in response and in particular, what rail movements do if the incentives are provided to sustainably move crude-by-rail. Our conversation with the government are focused on achieving this further relief and ultimately, the elimination of the curtailment program entirely.

Switching to Refining. Throughput averaged 344,000 barrels a day. For us, it was down about 19,000 from a year ago. It's up about 19,000 or 20,000 from the prior 3-year average, so we're between -- we're kind of midrange over the last 3 years. But if I look at year-by-year -- our year-over-year, there were 2 factors as to why we were lower this year: we did have major turnaround work in our Sarnia refinery; but we also had the impact of an incident with a fractionation tower also at Sarnia, which occurred early in the quarter, specifically April 2. And I mentioned that in our first quarter call, and I will detail more fully here in a moment.

Regarding the turnaround itself, this is part of normal ongoing maintenance activities typically completed over plus or minus 4-year cycles. Work includes catalyst change out, reliability upgrades, any replacement of end-of-life equipment. The cost to us was $60 million to $65 million. That is essentially as planned. However, the time for the turnaround was extended due to the tower incident itself. Volumetrically, if I isolate the turnaround, we met most all of our petroleum product sales over the period, with preplanned third-party purchases, but the impact on Refining, we would characterize as 20,000 to 25,000 barrels a day due to the turnaround, as expected. The more material and the unexpected impact in 2Q was associated with the fractionation tower incident. And in short, what this is, is a tower more than 100 feet tall. It was taken out of service in preparation for the turnaround. It overheated, buckled and fell over inside the plant boundaries. Fortunately, no one was hurt. There were no air emissions or hydrocarbon spills associated with it. The tower is used to manufacture jet fuel and gasoline components that was installed in the late '60s and has been opened 5 previous times without incident. The investigation concluded that work performed in 2011 that modified internal components, we call it packing within the tower, it increased or -- the potential for pyrophoric ignition or said differently, accumulation of materials, which can ignite under heated conditions when exposed to air.

So the turnaround preparation activities didn't adequately anticipate or prepare for this potential. Suggestion is there's a lot of learnings that have come out of it. We expect a full year impact of this incident to be about $80 million to $90 million of OpEx and CapEx for the repairs and the replacements. And in addition, we estimate a margin impact from loss production to be on the order of $100 million over the course of the year, and we've already absorbed about 2/3 of that margin impact in the second quarter, with the remaining 1/3 essentially all in the third quarter. The refinery was initially shut down, later restarted, reduced rates under a revised configuration. Over time, throughput has increased to now where it's 105,000 to 110,000 barrels a day. This is about 5,000 or 10,000 kbd lower than normal rates. A new tower is being built, expected to be operational in the fourth quarter. And as a result of the incident, we would assign refinery throughput impact to be about 35,000 barrels a day in the second quarter. In the third quarter, with Sarnia at a bit lower rates, we would expect the impact to be about 5,000 to 10,000 barrels a day.

Performance at our other 2 refineries, Strathcona and Nanticoke, was quite strong, with utilization at or above 90% in the second quarter. But overall performance was certainly overshadowed by Sarnia.

With our outlook over the remainder of the year, we do have 2 additional maintenance turnarounds planned. Nanticoke: early September for about 50 days. $70 million, $75 million cost. And of course, there'll be a margin and volume impact, as there always is. And some more work at Sarnia that had always been planned in a 2-step manner, with a second turnaround also late September for about 55 days, $45 million to $50 million cost here. With 3 major refining turnarounds in 2019. It is a higher-than-typical planned maintenance year. Generally, a typical year would include 2 significant refining turnarounds at our 3 facilities overall so a bit higher than normal.

On petroleum product sales, we averaged 477,000 barrels a day in 2Q, flat with the first quarter, but it was down about 33,000 from the second quarter of last year. You may recall our second quarter of last year at 510,000. It was a -- essentially a modern-day high, a 30-year quarterly high at the time. For prospective, second quarter sales have averaged over the last 5 years about 485,000. So we were within a 1% or 2% of that more recently historical average. But any shortfall this year, I would attribute to the Sarnia refining issues that I've just highlighted.

Throughout the quarter, sales volumes grew. They were most -- they were lowest in April at 441,000 with the Sarnia incident turnaround, growing to 488,000 in May and 502,000 in June.

First half, we averaged 477,000, down a bit from the first half of last year. And again, I would link back to the experience at Sarnia. For our current [sales], the last 5 years, our first half sales have average 481,000 versus this year's 477,000.

In the third quarter, we expect performance to rebound a bit from the second quarter as refining throughput increases. And as I would sit here today, I would anticipate sales volumes in the range of 480,000 to 500,000 in the third quarter, quite consistent with the prior 5-year average.

So with that summary, I think I'll pause on a couple of comments before we start the Q&A. I would characterize our second quarter and the first half overall as the financial and operating performance was generally strong, not without a few hiccups that we have had or are resolving. Strength particularly in the Upstream. And here again, I'd say, particularly, as Dan highlighted, in the cash flow from operations and the continued strong shareholder distribution. And I just reiterate that with the integration and the balance we have across our portfolio from production, refining, petroleum product sales, you are seeing the resiliency in whatever market conditions happen to exist with our ability to continue to generate cash in most any of those environments.

So with that, I'll turn it over to Dave, and he will describe and kick off our Q&A process.

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Dave Hughes, Imperial Oil Limited - Manager of IR [6]

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Okay. Thanks. As I mentioned at the start, we did have some questions pre-submitted. So I think I'll start with a couple of those, and then we'll move over to the live Q&A.

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Questions and Answers

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Dave Hughes, Imperial Oil Limited - Manager of IR [1]

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So the first question is from Prashant Rao from Citigroup.

Given the K2 turnarounds' strong production, 207,000 barrels per day was a nice surprise. Can you talk a bit about the drivers of the outperformance? And then given that we are already at 193,000 year-to-date, with less overall maintenance work and better weather conditions in the second half, do you consider that 200,000-barrel-a-day target a bit conservative?

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Richard M. Kruger, Imperial Oil Limited - Chairman, President & CEO [2]

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Okay. And I hit a number of that in my comments. But what I would say is we had several years running where we were underperforming expectations. And when we did -- we communicated in late '17 the cumulative scope of work we had completed at that time to enhance our liability with crushers, with transport lines and a number of things. And coming out of '17, that gave us a great deal of confidence that our plan for '18 and '19, at or above 200,000 barrels a day, we had a lot of confidence in that. And of course, from year-end this year and beyond, supplemental crusher will bump it up again.

I think what we're seeing, we certainly saw in the second half of last year, and we also saw it coming out of our -- the turnaround this quarter, is those upgrades we've made: modifications, operating practices, enhancements to equipment and maintenance procedures, have had and continued to deliver the intended results. I'll feel better when we get through the third quarter turnaround this year. It's a bit bigger in scope than our third quarter turnaround last year. So there'll be a little more volumetric impact. But certainly, where we're positioned through the first half, and I commented on where we are through July, gives us very high confidence in the year. And we're not going to refine that 200 and say, "We're going to be 210 or so." Again, I think, it's a little bit too early to call that. But the strong performance, I would be disappointed if we don't meet or, perhaps, exceed where we ended up a year ago.

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Dave Hughes, Imperial Oil Limited - Manager of IR [3]

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Okay. We've also received a number of questions related to crude-by-rail. And also you did comment extensively on it. But I'll try to summarize the questions. There's really 2 particular ones coming through. Number one is around our utilization of crude-by-rail. Are we -- can we offer something about July and then through the rest of the year? And the second one is more on the incentive side. A comment on our view of the economics of crude-by-rail.

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Richard M. Kruger, Imperial Oil Limited - Chairman, President & CEO [4]

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Sure. It's a good question because it is -- it has been volatile over the last 7 or 8 months. And as I commented on, it's one of the unintended -- I would characterize it as negative unintended consequences coming out of curtailment because if I step back, and I'll get to the question more explicitly here, but market demand for Western Canadian heavy crude remains robust, particularly in the Gulf Coast, with supply capacity exceeding takeaway capacity. We saw, and it's recognized that the potential for volatile pricing dynamics certainly was shown late last year and exists. You can work this 2 ways: you can increase takeaway capacity, or you can curtail supply. I think folks know what I think about curtailing supply. We've tried that. It certainly bolstered prices, but it's been slow in coming with other consequences on first initial inability to reduce provincial inventories, the erosion of rail economics. And our view is current pipeline capacity has been optimized. Our partners in the Pipeline business have and continued to do a good job at fully utilizing those facilities. So expanding rail is the only real, real or only real short-term option for us. And what we need is a sustainable economic incentive to do that. And one of the best indicators I have. We talk -- parties have talked a lot about differentials. And I think it's important that when you do, you talk about what are you talking about. Often, WTI versus WCS is compared.

But when you're looking at rail economics, I would urge folks to focus on WCS in Hardisty and WCS in the Gulf Coast. You look at those 2 prices, and you look at the differential. And if the differential is wide enough to cover rail cost, rail will move. If it's not wide enough, you lose money on each barrel you sell. And so that differential has actually been quite tight over the first half of the year and oscillating around $10, $12 a barrel. It increased a bit in the second quarter, and we responded by increasing rail. Right now, it's back at or below $10. Parties, including us, have various -- variable costs in their rail system, but you don't invest money on a variable cost basis. To grow it, you need to have a full cost recovery. And I've said before that we look for something that creates a sustainable rail instead of a differential or an arbitrage between the same barrel in 2 locations of $15 to $20 a barrel. And we're not there. So what we're doing right now, July, was about where June -- or May and June was, in the mid-70s or so. But our outlook for August and September is we will ramp down rail because it is not economic to move those barrels on rail. In this ragged edge of up and down, pardon the pun, but it's no way to run a railroad. We need a sustained incentive to increase rail capacity. We and industry, and that's one of the reasons I'll go back to curtailment. We think it's time to loosen up the curtailment purse strings, allow more oil to flow to the barrel, strengthen or solidify differentials in a range where rail is clearly incentivized. And we think that's the best answer in the foreseeable future as we all await uncertain but future pipeline capacity additions.

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Dave Hughes, Imperial Oil Limited - Manager of IR [5]

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Okay. Operator, I think we'll go to the Q&A line now, please.

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Operator [6]

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(Operator Instructions) And our first question comes from Emily Chieng from Goldman Sachs.

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Emily Christine Chieng, Goldman Sachs Group Inc., Research Division - Associate [7]

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So my first question is just around egress, it's sort of a 3-part question here. One, what do you think of the government's rail contracts? And is there any potential in Imperial potentially having to look at that? And then on just what the government is thinking -- how the government is thinking about curtailment levels? And what's the thought on whether or not they continue to ease curtailments or cut them completely? And then just on the final egress pace. There's been a little bit of noise around Line 5. Any -- what's sort of the thought around the impact Imperial [if that] does get potentially shut down?

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Richard M. Kruger, Imperial Oil Limited - Chairman, President & CEO [8]

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Thanks for your questions, Emily. First, the government rail contracts. We agree with the government that we think the rail business is best left in the hands of the industry. So the government's subjective or intent to remove themselves from the rail business, we have supported that all along. Now in the process of assigning or taking on those rail contracts, we, like others, are reviewing those. We're working with the government. I can't really comment on those specific contracts themselves. We're all under confidentiality agreements in doing that. But I think their direction of getting industry participants to take on those rail contracts to support a sustainable healthy rail sector for the foreseeable future, I think, is a good thing to do.

Now specific to us, we got in the rail business when getting in the rail business wasn't cool. We got in it several years ago of anticipating the -- and some of the uncertainties on pipe that we wanted to have that. I described it before as an insurance policy if and when we needed it. And lo and behold, we're glad we've had that insurance policy because we and the industry have needed it. So we got [it up] early, we built a rail terminal, we negotiate contracts with CN CP, we have not only the loading points, but we have offloading points, we have a very efficient unit train operation that allows us to get to market and get empty cars back here fast. So we feel that we have an advantaged rail situation. And if we were looking to enhance or add to that in any way, whether that's due to the government taking on part of their contracts or other things, we're going to want to ensure it is just as economic and just as efficient as what we've been over to build -- what we've been able to build over the last several years.

Now on curtailment levels. I think I've commented on this. The first several months of the year didn't give a lot of flexibility here. We had -- the industry had -- was working under curtailment. But lo and behold because rail had ramped down, their inventory levels maintain themselves at or near tank tops for largely the first 4 or 5 months of the year. With major maintenance work and increase in rail in the second quarter, I've commented about specific numbers, how the inventory levels have been brought down. And we think there's a lot of flex in the system right now, and now is the time to see what that means. I commented how 100,000 barrels a day for 30 days is 3 million barrels. There is 8 million or 9 million barrels of inventory.

I would let out the curtailment at this point in time, the month of August, the month of September, and I would let them see what does the market do if there's concerns that it's getting back near tank tops, and parties start suggesting differentials will blow out and anxiety rises, the government has flexibility to do that, but we'll never know unless we try. And I think the market conditions -- physical conditions are right to -- instead of 25,000 barrels here and there, I would go further than that. And we've had conversations, very good conversations, with the government on that. So hopefully, their decision, but we would like to see that curtailment level if not eliminated, certainly reduced in the near-term. And let's see what market conditions develop. In particular, can we get to where this rail incentive is clear, sustainable and not a month-by-month decision.

Line 5, this is -- I won't recap the situation. Folks are aware of the situation in Michigan with the governor and most notably, the Attorney General. Line 5 is a critical piece of infrastructure to Ontario, Québec refineries as well as key parts of the Midwest.

We are a shipper on Line 5. The majority of our light crudes go through Line 5 that support our Sarnia and Nanticoke refineries. We get some light crudes in other pathways and heavy crudes come in a way unaffected by Line 5. So it's an important topic to us. And we are working very, very closely with Enbridge, the operator of -- on whatever help they support -- they need from us as they progress the legal and operational challenges that they're receiving from the state of Michigan as it relates to Line 5. I'll really stop there. I think specific comments on Line 5, I would defer to Al Monaco and Enbridge on that. But important piece of infrastructure. Quite important not only for us but the industry on the supply balance in Southeast Ontario and parts of the Midwest. And finding a good long-term resolution here is in the best interest of consumers both north and south of the border.

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Emily Christine Chieng, Goldman Sachs Group Inc., Research Division - Associate [9]

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Great. And just one quick follow up, how should we think about Aspen and when that decision may be to bring that back into construction mode?

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Richard M. Kruger, Imperial Oil Limited - Chairman, President & CEO [10]

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Okay. Thank you. Just a recap there for those that missed it. Late last year, we funded Aspen a $2.6 billion project. Best-in-class technology for carbon intensity reduction or water intensity reduction. A globally competitive project that had a lot of resiliency under a low-price world. We are quite pleased. Then sadly for us, government intervention through the mandated curtailment program came into place. It kind of -- well, it destroyed rail economics for us. Within a several year period, we were -- we looked at Aspen over a range of scenarios: getting into the current pipe system, capturing space and incremental pipe capacity, but the ace in the hole was always rail as a way to get it to market. With the curtailment and what it did on rail economics, that shattered our confidence in that. We worked with the prior administration on getting some assurances that Aspen would be able to -- when it came online, that it would be able to produce it. The current curtailment rules wouldn't do that. They're based on historical production. A new project has 0 historical production. We were not able to get the assurance that we sought for our shareholders who put investment of this magnitude. And sadly, that led us to ramp down Aspen project activities in an orderly way so that we could be positioned when we think the time is right to restart it. And I've said before. If we're going to be looking at what happens on subsequent actions around intervening in the market, curtailment specifically, certainly, what happens to rail incentives, rail economics. And then just our overall confidence in market conditions, and I would say that does include, as we look at progress on the new pipes, whether that be Line 3, Trans Mountain and/or Keystone XL, we'll be looking at all of that. And when we feel the time is right to resume the ramp-up and full scale investment, we will do that. And we have not concluded at this point in time that, that time is right to ramp that up.

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Operator [11]

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And our next question comes from Benny Wong from Morgan Stanley.

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Benny Wong, Morgan Stanley, Research Division - VP [12]

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My first question is really on your perspective of integration. An option production to downstream throughput, it looks like you guys are well matched. But most of your Upstream volumes and future growth is largely on heavy production while you're mostly a light oil refinery. So just want to get your view on that, if it makes sense to have more heavy processing capacity at some point, or does that balance still makes sense going forward because a lot of global production growth is really light?

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Richard M. Kruger, Imperial Oil Limited - Chairman, President & CEO [13]

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Yes. Very good. And you've described it well. We're roughly a 400,000-barrel-a-day equity producer. This quarter was quite convenient when I say that because that's exactly what it was. We were roughly a 400,000-barrel-a-day -- largely a light oil refiner. And then of course, the 450,000- to 500,000-barrel-a-day petroleum product sales. So you -- at a glance, you see, certainly, the integration and the balance. But as you appropriately point out, the mix effect is heavy production-oriented and light refining. Now what we've done over the last few years with incentives with this kind of heavy crudes, we have incrementally increased our heavy throughputs in our facilities from roughly 65,000 barrels a day to when it made good strong economic sense last year, we were tipping 100,000 barrels a day. So almost 25% of our capacity. We've got a coker at Sarnia. We've got asphalt facilities at Nanticoke and Strathcona. And the incentives were there to push every bit of heavy molecules into those facilities. And that's exactly what we did.

Now with heavy and light, the differentials, we optimize that on any given day. We do see demand for heavies continuing strong, particularly in the Gulf Coast. So it's all about getting the heavies there. And we don't necessarily run our own production in our own refineries. Our Upstream is charged with maximizing the value of each and every barrel they sell to whoever they can sell it to. If that's our own facility, so be it. And our Downstream is charged with getting the most price-advantaged feedstocks, heavy or light, from whoever they can get it from. So we, with our -- not only with our operations but with our commitments on infrastructure. Certainly the common carriage in Enbridge, but we also have contract commitments with base Keystone, Gulf Coast access and then our investment in the rail terminal. We are quite active in maximizing the value, however it happens to go. I think for the foreseeable future, we'll continue to look at if the economic incentive is there, as how can we get more heavies into our existing facilities. But as I sit here today, I look at coking capacity and other parts of the world, it's harder for me to see a clear economic incentive that we would want to make large investments to materially modify our facilities as opposed to continuing to work to optimize them.

Now that -- as market -- as conditions change and particularly, when you have some confidence that market condition changes aren't short-term in nature or aberrations. And particularly, when they've not been caused by artificial interventions. Then when you have the confidence, we reevaluate that, and we look at it. Does it make sense to invest more in the Downstream or the other. Downstream investments more recently have been in things like cogen, reliability enhancements, things that can strengthen what we already fully believe is already a strong Downstream business. And they've been less to take our Downstream business and convert it to something that it's not today. But I hope I hit on your question there.

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Benny Wong, Morgan Stanley, Research Division - VP [14]

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Yes. My next question is on Aspen again. And I know you just previously touched on it. And I know you're really focused on egress before you really move forward. I just want to take that question a little -- one step further, particularly in a world that doesn't value growth like it used to. I think some investors will argue that they would prefer Aspen being further indefinitely and free up more capital for even more cash returns. So just want to get your perspective on that. Do you think that's a little shortsighted because you're managing a long-term business, or has the world and the market changed enough for that argument to have [to be letted]?

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Richard M. Kruger, Imperial Oil Limited - Chairman, President & CEO [15]

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Yes -- no. Fair question. Now we have a large and diverse shareholder base. And what I found in the 6.5 years I've been in this job, I get no shortage of advice from people on how to run this business, whether it's debt reduction, whether it's increased dividend, whether it's increased buybacks, whether it's investments, no investments. And we take all that in. And what we do is we strive to enhance the long-term value of this enterprise. Now obviously, we deal with short-term market disconnections, dislocations. But that integration and balance we have positions us extremely well. So now if I'd just do just a little bit of math. We have roughly $1 billion to $1.1 billion, $1.2 billion a year in requirements of sustaining capital, current feed for our existing corporate asset base. Our dividend at current rate, which the last 2 increases have been the highest 2 increases we've made in our history, roughly consumes about $600 million a year at current rate. So you add the 2 of those together, you get $1.6 billion, $1.7 billion a year.

Dan commented, through the first half of the year, we've generated $2 billion in cash in a -- not necessarily the most advantaged marketing environment. Oil price is a bit higher, but differential's lower. If you look back over the average of the last 10 years, that's closer to $3.3 billion, $3.4 billion a year. But we have been enhancing the cash generation capacity of this enterprise where it's more consistently looking on the higher side of that $3.5 billion to $4 billion. So if you've got about half of that is sustaining capital and dividend, the question comes down to what do we do with the other half of it? For the last 2 years now, we have maximized share purchases under the TSX-approved program. 5% of our outstanding shares. We maximize it in the first program, and we maximized it again. And lo and behold, we look at the end of each quarter, and we still have $1 billion or so of cash on hand.

So -- and this year's capital is more than that sustaining. It's select growth. So our view is from a -- ability to balance and meet our capital allocation priorities: dividend, sustaining capital, highest-quality selective growth and some level of share buybacks. We see the ability to do all of that under a wide range of market conditions. And when we launched Aspen last fall, we detailed the amount of capital it would require over a 3-year period. It's going to be roughly $700 million or $800 million a year. We anticipate that we would continue to be able to do buybacks. Did I say at the time we'd be able to maximize the program, no. Because it depended on market conditions. But I think we're quite confident we can find a selection of all of those priorities, continue dividend growth, take care of what we have, continued share buybacks. And if and when the time's right to resume Aspen, I think we'll have the financial capability to do all of those. It's just a matter of when is the time right.

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Operator [16]

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And our next question comes Greg Pardy from RBC Capital Markets.

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Greg M. Pardy, RBC Capital Markets, LLC, Research Division - MD and Co-Head Global Energy Research [17]

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Rich, I'll tell you, you guys have gone from never having done a call to probably one of the best from an informational standpoint, so please keep that going.

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Richard M. Kruger, Imperial Oil Limited - Chairman, President & CEO [18]

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Greg, I appreciate that. I like everything you said, except the one of the best. [That, we'll keep working, so...]

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Greg M. Pardy, RBC Capital Markets, LLC, Research Division - MD and Co-Head Global Energy Research [19]

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All right. There you go. Something to strive for. So I've asked it before, just around OpEx at Kearl. But I'm looking at your numbers, and we won't get the actuals until next week. But realizations look good. We understand the Downstream, you hit the cover off the ball with the Kearl volumes. If you were to look at the run rate ex the turnaround impact, are you now in the lower -- I don't know, low USD 20s. Or are there about just from an operating cost standpoint?

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Richard M. Kruger, Imperial Oil Limited - Chairman, President & CEO [20]

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Yes. Greg, we're not there yet. What I'll tell you, a little bit of this year -- a bit of the first half of this year has some -- a little bit of an artificial aspect to it because we've been doing a lot of work that is -- has been preparing for the supplemental crusher at the end of the year, increasing the size of our truck and shovel fleet because when we go from 200 to 240, we're going to need more trucks, more shovels. So you can't go to Home Depot and get those on December 31. So we've been doing some of that. We've been also with all of the work we've done in the last year or 2 on reliability, we've been ensuring that we've been quite proactive on a lot of our maintenance practices and taking care of that fleet. And John Whelan described a year ago at our Investor Day in November in Toronto, and he outlined a series of initiatives that we refer to as Kearl profitability improvement. And so we have been spending money on getting Kearl in a position not only where it can sustain the 240, but we also outlined a pathway last November on how -- what's beyond 240, how do we get it to 270 to 280. We described how that was not some big-bang capital project, but it was a series of things. And we have been working on those series of things. So taking the first half of this year at Kearl and comparing it to the first half of last year. It's not quite an apples-to-apples. But I think the thing I would say is the confidence and commitment we have on Kearl and the number we've advertised for a long time now is the USD 20 a barrel and sustaining that. Nothing has wavered in that.

The supplemental crusher, I think we've advertised -- we think that is going to be about a $3 a barrel drop in Kearl OpEx. Nothing has suggested that would change. And these other things we do continue to drive at it. So we haven't advertised explicitly what Kearl cash unit costs are year-to-date. They're -- actually, they're slightly higher than they were last year. But then when I go back to that -- my first set of comments on monies we've been spending, they -- you haven't directly seen those costs will be reflected in the barrels yet because they're what comes as we get to the end of the year with the crusher and beyond. But nothing has changed in terms of our focus and confidence to where we think this asset will be for the long term nor our pathway and the time frame to get there.

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Greg M. Pardy, RBC Capital Markets, LLC, Research Division - MD and Co-Head Global Energy Research [21]

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Okay. That's great. I mean second one is really kind of coming out of the Suncor conference call. I mean they did increase the OpEx guidance on Syncrude. I think there was some disappointment in the market as to whether cost could really get down there given the utilization rate. We've seen turnarounds at Syncrude for many, many years, typically in the third quarter. Is there anything unique from a, I don't know, from a sustainability or performance-enhancing basis that's going to occur with the trend you talked about in September?

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Richard M. Kruger, Imperial Oil Limited - Chairman, President & CEO [22]

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Just so we're clear, Greg. Are you talking about Kearl or back to Syncrude here?

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Greg M. Pardy, RBC Capital Markets, LLC, Research Division - MD and Co-Head Global Energy Research [23]

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Oh, I'm sorry. Sorry. Yes -- no, no. Just all at Syncrude.

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Richard M. Kruger, Imperial Oil Limited - Chairman, President & CEO [24]

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Yes. I haven't seen everything -- I haven't analyzed everything that Suncor set on it. The turnaround September is a big deal. We're pretty euphoric of late on the performance at Syncrude. So I don't really have anything to offer that there's any fundamental change on the ongoing operating cost level. It's -- Syncrude is a difficult one, at least over the last several years, to kind of chart trend lines because there've been so many one-offs. But where -- when I look at where they are and certainly where they've been on an all-in, we're quite pleased certainly with the reliability. We've spent money to achieve that reliability. And as long as we -- as it continues to perform like that, we continue to be the quite confident. And the outlook for Syncrude is not materially different than what we've had in our own internal plans. In fact, I would say -- I'm looking at a table right now, kind of where we are year-to-date versus where we thought we would be year-to-date. And we're -- internally, we're a moderately optimistic lot internally. When we come to talk to hard-nosed fellows like you, we might tamper that a little bit. But our own internal expectations -- and we're spot on in Syncrude with -- from a cost standpoint and from a production standpoint with exactly where our plan through the first 6 months would have been.

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Greg M. Pardy, RBC Capital Markets, LLC, Research Division - MD and Co-Head Global Energy Research [25]

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Okay. Last quick one for me. You guys looked to the diluent recovery unit, and I think back in 2015, attached the Edmonton rail terminal, I guess, and then it just went away. Is it -- DRU something that you'd contemplate or is effectively the paraffinic froth treatment just so good from dropping up the heavy molecules, it's not a path you'd ever go down?

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Richard M. Kruger, Imperial Oil Limited - Chairman, President & CEO [26]

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No, no. You're right. We've looked at that before. And I think what's important on a DRU, the map or the economics on a DRU deal with a series of differences between a whole bunch of numbers. So what's the cost of pipe or rail on transportation. And of course, a diluted barrel has more volumes of roughly 1/3 more volume. So if you [save] transportation on that, well, what type of transportation? What's a rail cost versus a pipe cost? What's a diluent cost? And when we looked at it -- we did a pretty good scrub on it. It's not -- it wouldn't be an inexpensive investment to go at scale. And at that point in time, we thought even before some of the things that have occurred more recently, there's a lot of variables in this marketplace. Diluent supply with some of the unconventionals, how much diluent you get from the Gulf Coast or the U.S., rail versus pipe economics. And we concluded then that there's validity to this project. But our own assessment at that time on the economics on it and the uncertainties were too high to take it to the next level of commercial progression. And I would say now we still have it. We've dusted off the shelf now and then. We look at some of those key assumptions. But I think you've described it. I would never say never. But right now it's not a front-burner opportunity for us.

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Operator [27]

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And our next question comes from [Mike Dunn] from [PNS Energy].

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Mike Dunn, [28]

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Rich, some of your competitors have commented recently that they would be supportive of the Alberta government linking an operator's increased production allowance to an increase in their crude-by-rail shipments. Can you comment on how you guys feel about that and whether you've had discussions?

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Richard M. Kruger, Imperial Oil Limited - Chairman, President & CEO [29]

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Sure. We've had discussions with the industry, and we've had discussions with the government. And Mike, if I step back far enough, we do -- and I said this earlier in my comments, that expanding rail capacity in an economic and sustainable way is the winning formula for the foreseeable future. We can't -- there's still so much uncertainty on new pipe. Rail is the answer near term. And so on my earlier comments, I talked about we don't think the government being in the rail business is the best way to go. And similarly, when you let market forces work, and you get the right level of economic incentive, industry will take the actions, invest in growth. The specific -- what you've talked about is the linking of allowances to rail. The devil's in the details. It's how you do it. And at one level, I can hear, "Okay. The government linking additional allowance to additional rail," that sounds a lot like continued government intervention to me. I like the idea of letting the market work, letting differentials expand by relieving the pressure and reducing curtailment. And I think the market will get there. But I do get concerned about how, when you talk about specifically linking things because then, the government is back in the rail business in a big way, just in a different way. So yes, I support the industry's comments on what they're trying to achieve, but I can't say I'm there yet on what I understand how. It's a work in progress. We're working in collaboration with other industry players and the government on this. How we do it, I think, is going to be very important to it. Because the last thing we want to do is engrain the concept of curtailment, that you get relief for curtailment if you get rail. I want relief from curtailment and no curtailment. I want it done. And I think the industry can be in that position sooner rather than later, and I'm looking forward to that day.

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Operator [30]

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And your next question comes from Manav Gupta from Crédit Suisse.

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Manav Gupta, Crédit Suisse AG, Research Division - Research Analyst [31]

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I just have a very quick question. Any update you can give us on the progress of the supplemental crushers? And what I'm trying to also understand is you can do 220 without the supplemental crushers, and I understand the guidance for the supplement crushers will average 240. But I'm also trying to understand what could be the peak production for a month for the supplemental crushers. So do you mean no turnaround in a particular month, how high could you go with the 2 supplemental crushers coming on?

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Richard M. Kruger, Imperial Oil Limited - Chairman, President & CEO [32]

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Yes. Fair question. The -- When you say an annual average of 200 at Kearl, what you typically get is you get a lower first quarter, just like we had because it's oftentimes affected by extreme cold weather and what the challenges that offers in the mining environment. You often get a artificially lower second quarter because of major maintenance or weather warms up, we all get a lot of work done. This year was a very strong second quarter. Last year had been the previous high at about 180. Then in the third quarter, all that maintenance behind you, you get after it. And the months of July and August have typically been the best months of the year. Oftentimes, we've had some maintenance that starts in September and October, so the quarter tails off a little bit. And then the fourth quarter can also be quite good. A little bit dependent on when you get into the later in the year, what's the weather. So the profile of the mining operation, if we say 200 or 240, it's not a flat line. It's either one of them.

Now the best months we've had at Kearl without supplemental crusher were last July and August. And we averaged a smidgen over 260. I think it was 262 and 263. The quarter last year was -- I think the third quarter was like 243 or something like that. And then it had 2 months of 260 in it without supplemental crusher. We have long talked about the downstream aspect of [grow] the processing capabilities of having 2 parallel trains that have 300,000-barrels-a-day capacity. And I increasingly referenced that we've had the number of days we've had that not only at 300 but beyond 300. We have 4 of those best days in the second half of June. So when we have the supplemental crusher, you take the bottleneck and constraint out of the front end, and you start to balance across that. So what's a good month with supplemental crusher in place, I think 300,000 barrels a day is a very achievable month when we don't have other downtime in that. But you'll still have that quarter-to-quarter profile, you'll still have maintenance in the spring and in the fall. That -- and then of course, you still have weather to deal with. But the 300,000-barrel-a-day months are certainly achievable.

We've had weeks that have approached that now, and that supplemental crusher will largely deal with what's prevented us from having longer periods of time at that range. I know there's a lot of folks who are saying, "You guys are -- you have this big second quarter, you did better last year. Come on, 240? You guys are going to be able to do better than that." And you guys as prompting leaves me to ask those same questions of my team, so thank you for that. My tongue's in my cheek, fellas, as I say that. I -- we're not ready to commit to more than that, but I certainly see the potential with the stability that the -- and the redundancy the supplemental crushers will add to allow us to do more than that on an annual average basis. And once we get those things up and running, that's exactly what we'll start talking about. What now do we think we have. But I think one of -- takeaway from that a great deal of confidence in the 240 with the supplemental crushing capability.

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Operator [33]

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And our next question comes from Phil Gresh from JPMorgan.

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Philip Mulkey Gresh, JP Morgan Chase & Co, Research Division - Senior Equity Research Analyst [34]

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Just a bit of a follow up to Greg's question on the OpEx side of things. Obviously, you're pre-investing here at Kearl. There's some pre-investment, I guess you call it, at Syncrude as well that was discussed. If I look at the absolute levels of the OpEx that we're seeing here in 2019, is that the run rate that we should be thinking about for the year? And then I realized the per barrel will come down as the supplemental crushers come online. But I presume there's going to be some absolute increases from there. So I'm just kind of trying to baseline myself and think about the cost outlook for...

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Richard M. Kruger, Imperial Oil Limited - Chairman, President & CEO [35]

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Yes. Great question, Phil. And we've talked a bit before about kind of the -- when we -- what's the incremental barrel cost and then what is the incremental cost -- barrel cost when you add new kit, which in this case, it will be the supplemental crusher and stuff, that's still work in progress. But I think whether that run rate is exactly what you've seen in the first half, I think it's indicative of what you'll see. We've got a lot of efforts that -- as we've done this pre-work or pre-investment, take some of those cost out of it that are more onetime. But it -- a run rate that's at a higher level than what we saw last year, more indicative of the first half, that's not unreasonable. And you hit on it. But along with that's going to come higher production. So when you start looking at the unit cost, we -- you would expect that, and this quarter was an example of much, much higher production. And our unit cost on a year -- this year versus year last year for the first 6 months, the unit cost, despite higher absolute cost, the unit cost was at or below what we were a year ago with a lot higher production. So we really managed the business on unit costs. We sell barrels, we produce barrels, so we're interested in what the cost per barrel is. But I think the absolute cost kind of the more -- the first half run rate is probably not unreasonable. I hope I get to tell you at the end of the year that we did better than that. But for modeling standpoint, that's probably fair.

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Philip Mulkey Gresh, JP Morgan Chase & Co, Research Division - Senior Equity Research Analyst [36]

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Okay. I appreciate that. This follow-up, it might be granular, so if it is, happy to take it offline. But I just noticed in the past few years that you guys have had very low cash taxes and you have NOLs and things like that. So I'm just wondering how you foresee that kind of mathematically playing out as we move into 2020? I think you will -- that works here with a lot of those NOLs. But is there a way to think about book and cash tax rates on a go forward?

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Richard M. Kruger, Imperial Oil Limited - Chairman, President & CEO [37]

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I think I'll ask Dan Lyons to comment on that a little bit, and -- Dan will offer a few comments. But if there's more granularity, as you say, we can do it offline.

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Daniel E. Lyons, Imperial Oil Limited - Senior VP of Finance & Administration and Controller [38]

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Yes. Phil, we've had a significant tax loss carryforward balance last couple of years, which has really minimized our cash taxes. As we -- as our profitability has been pretty solid, those are running down, and you can look at -- in our Q, which will come out here in a week or so and see the balance. As they are coming down, and we anticipate being cash tax paying pretty shortly. But obviously, it's going to depend on prices and other things. So we benefited from that. We still have some tax loss carryforwards we're using. We obviously are still benefiting from accelerated depreciation, but our rate of cash tax paying have these prices should start going up in -- certainly in 2020.

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Philip Mulkey Gresh, JP Morgan Chase & Co, Research Division - Senior Equity Research Analyst [39]

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Any order of magnitude relative -- and I think [book cash] kind of mid-20s recently. Any order of magnitude relative to that thought that you would -- kind of ratio of cash to book?

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Daniel E. Lyons, Imperial Oil Limited - Senior VP of Finance & Administration and Controller [40]

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Yes. I wouldn't go -- I don't have a number on that. Suffice it to say, once we run out of tax loss carryforward, our cash tax rates can be closer to our book tax rate.

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Operator [41]

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And our next question comes from Dennis Fong from Canaccord Genuity.

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Dennis Fong, Canaccord Genuity Corp., Research Division - Exploration and Production Analyst [42]

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I know we're getting pretty long in 2Q here, but I'll keep my couple of questions short. So this is just a bit of a follow-along on -- in terms of the OpEx question there at Kearl. So essentially, it sounds like you guys were implying that there was some kind of pre-spend to kind of prep for the supplemental crusher. And then you kind of -- going back to the Investor Day, there's obviously a short list there of future upcoming projects that you could recall due to further development of 280,000 build-to-date plus. I suppose the question from me really here is like how much of that have you actually completed thus far and is incorporated essentially in your, we'll call it, elevated OpEx right now? And how much could potentially come in the next few years? And how you guys [persee] the decision around sanctioning or allocating capital towards that component of debottlenecking?

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Richard M. Kruger, Imperial Oil Limited - Chairman, President & CEO [43]

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If I get -- if I take the last part of your last question first in terms of the decision. You may recall from the investor deck, we ramped up investment opportunities we have, and we used just a very simple indicative cost-per-flowing barrel kind of a measure just to normalize. And we described Aspen -- we described a couple of phases of Aspen, Cold Lake expansion. And we had the supplemental crusher on there. And then we had what we think kind of investments are spending that might take us from 240 to 280 at Kearl. And those incremental redundancy, reliability investments are extremely attractive. The supplemental crusher, at kind of the advertised, what I've said about it from a price standpoint -- or cost standpoint before in incremental, an incremental production that comes with it, we talk about $15,000, $16,000 per flowing barrel. So there are quite -- that's quite attractive. And we'll look at it not only on individual economics but what it does to the enterprise and its ability to more confidently sustain cash generation.

So -- but there are also to the point after the supplemental crusher, it's -- they're quite small. So we're looking at it kind of bit by bit. It's not like there's a $500 million project or a $300 million project. There are component part things. And we have been doing some of those. Some of them you could say that, well, they reduce maintenance intervals, maintenance requirements. But some of them I can say, they support that higher capacity from a 240 to a 280. And I'll give you one that I haven't really talked about, and my Upstream Lead, John Whelan, is not the room with me. He might cringe. We're working long and hard on the turnarounds we're doing this year and next year to see as opposed to an annual turnaround at each of the 2 big plants, can we get those extended where we have a -- an every 2-year cycle on those. And that would be huge, not only from the OpEx cost you would say but also from the incremental volumes that, that would shed in a given year. Not ready to say we're going to be able to achieve that yet. But we've been spending some money on whether that strength of materials and key components where we went in on annual cycles because we felt the need to check and see what erosion has been.

If we modify some of that, and we operate for a year, look at it and say, "Wow, there's not much change." Those kind of things can give us the confidence to go to longer and longer cycles between turnarounds. And that's a winning formula here because not only it saves the OpEx of a turnaround, which as I described at Kearl, was $100 million gross. And then the quarterly impact on production at 46. So you save that $100 million OpEx, and you don't have the annual average 10,000-, 11,000-, 12,000-barrel-a-day impact for production. So we've been working on that. We haven't talked much about it. I think I just did right now. So that means probably this fall, we'll get to talk more about it. But those are some of the things you're seeing in the OpEx run rate that we really -- it's not just higher cost at Kearl. It's things we're doing that we're absolutely convinced will lead to higher value at Kearl for the longer term. I'm probably on the -- probably walked to the end of that limb on that one. But we're going to -- later this year, we'll pull investors together again and analysts, and we'll talk in more detail. And I'll promise you now, we'll talk in more detail about what we are and have been doing in those areas.

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Dennis Fong, Canaccord Genuity Corp., Research Division - Exploration and Production Analyst [44]

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Okay. Perfect. And then the second question that I have is just with respect to a comment that you made earlier in the call on Syncrude and the potentially allocation of production quotas. How should we think about that going into Q3 and the remainder of this year, just given that you do have some levels of heavier turnaround at some facilities? And how are you guys thinking about balancing out, I guess, the production on a corporate level, notwithstanding a potential significant change from the mandatory curtailment plans from the government?

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Richard M. Kruger, Imperial Oil Limited - Chairman, President & CEO [45]

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Yes. Good question. I'll comment -- I'll mix my comments a little bit industry and then us specific. In the us specific, when you take the quotas, we're assigned a quota for Kearl and Cold Lake combined as an operator, and Imperial is the operator of those 2 assets. Then we have, at our discretion on a month-to-month basis, to decide if we're bumping up against those limits, how and what we produce between Kearl and Cold Lake. And now Syncrude is a designated stand-alone operator, so they have no ability to trade-off between other assets. It's Syncrude. And so with the turnaround work for example that we had at Kearl in the first quarter, with some of the operational challenges on cold weather that we had both at Cold Lake and Kearl in the first quarter -- I'm sorry, the turnaround in the second quarter, we were a net seller of credits during both -- much of that time period. And we sold many of those to Syncrude so that we could optimize our -- Imperial's overall performance. As we get into the third quarter, I've commented we're out of the turnaround at Cold Lake, we're out of the turnaround, and we're roaring loud at Kearl. Syncrude has some turnaround late in the period, but these orders are month-by-month. And so we see it's going to be pretty tight. It was tight in July. It's going to be tight, if not tighter, in August. And this is true not only for us but industry at large. I wouldn't expect there's going to be a lot of credits traded in the -- at least for the next 1.5 month or so in the quarter until others start to do maintenance work again or they have other -- or the government continues to release incremental quota to industry.

The third quarter, we -- from a year ago, we looked at it and thought the toughest time in this world, not knowing what would happen on curtailed volumes, will be the third quarter. We saw that at the beginning of the year, and we're here now. And that's exactly the way we continue to see it.

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Operator [46]

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And our last question comes from Jon Morrison from CIBC Capital Markets.

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Jon Morrison, CIBC Capital Markets, Research Division - Executive Director of Institutional Equity Research [47]

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Rich, [I've got one more to ask, Imperial]. What was the right WCS [hardest hit] at WCS? Gulf Coast [stiffs] the target from an optimally functioning market perspective, i.e., all production is clearing the markets through the trifecta of pipe, rail and domestic refining capacity. But pricing is also protecting industry cash flows and arguably, sustainability for the broader group of companies, what would you say? And do you believe that the government can dial back curtailments to walk into that pricing scenario, or you believe that they need to just effectively remove curtailments, let it go wider, and let's see the [ramp] to get there?

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Richard M. Kruger, Imperial Oil Limited - Chairman, President & CEO [48]

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Yes. I can tell you what I'd say because I've said it. If you take WCS, Hardisty, WCS Gulf Coast for a healthy, sustainable, growing rail sector that parties will plan and invest in, we think that number needs to be $15 to $20. And that's kind of a full-cost model. On any point in time, to [insent] rail 1 month versus another month, many parties will operate under their variable cost. [Wait]. Okay. If I don't do, it I'm going to incur this level of fixed cost because I have tank car commitments or whatever. So at any point in time, the industry is not operating off of a full cost recovery model. But our number in there, and I -- one thing I'm -- I may not have the best memory, but I'm very consistent. I think I said $15 to $20 for some time now. And I'd still see that math the same way. And that's what we've described to the government, would hit us in a world of clear economic incentive, sustainable rail activities and then parties wouldn't be worrying about what's going to happen month-on-month like they are today.

Now the second one, we're walking into it. This is a tougher one. But when I go back to my inventory comments, with a 8 million-barrel-or-so inventory that is now exist, 100,000 barrels a day for 30 days is 3 million barrels, now is the time to test it. We do not believe if you put that incremental production in, that the differentials will blow out over it. If you get at or near tank tops, it's a lot more difficult to predict because there's no place to put oil, and you get into things like [shut-in] economics. But we think the time to -- let's flex our muscles a little bit and see if -- can we live in a non-curtailed world. We think the time is ripe right now to do that. And that also happens to be something I've shared in a very productive manner. We have good, good conversations with the government on this. They've got a lot of things to consider but that is the exact -- that differential and what we think could and should be done in the short term is exactly what I talked to the government about as recent as a couple of days ago.

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Jon Morrison, CIBC Capital Markets, Research Division - Executive Director of Institutional Equity Research [49]

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Maybe I'll just ask one follow-up, which is [Davon Jackish], there's obviously a decent amount of investors who would have liked to have seen you bought that asset rather than push forward with Aspen. At some point down the road, can you just share any color around whether it was of interest to you? And it was just a function of price that didn't really get you there, or it really wasn't on the table in the context of the market that we're in a curtailed world.

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Richard M. Kruger, Imperial Oil Limited - Chairman, President & CEO [50]

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I think the ability to grow shareholder value in a globally competitive, long-term sustainable way is of high interest to us in all environments. And we've described a bit of what we have from an internal opportunity inventory. Aspen Phase 1, Phase 2, Cold Lake expansion, Kearl supplemental crusher, other Kearl enhancements. We talked about how we compare that to other things in the market. You commented on one here, we've looked at several others. So I won't specifically get into [Jack, they should] sell. But we've got our nose and ears to the ground. We evaluate far more things than we ever talked about publicly. And we don't -- we're not opposed to making a move when we're convinced they can add shareholder value. But I'll go back to some of the things that I've just said, is there's a lot of uncertainty out there, and we would like, not the least of which, is the capability for the market to act -- operate in a free-market world. We'd like to get in that world. We'd like to see some supplemental pipe. We like rail economics to be sustainable. And I think then, you'll see us with more appetite than we have right now for spending new capital money.

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Dave Hughes, Imperial Oil Limited - Manager of IR [51]

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Okay. So that's the end of the questions. So thank you, everybody, for calling in. If -- as always, if you have any further questions, please don't hesitate to give us a call.

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Richard M. Kruger, Imperial Oil Limited - Chairman, President & CEO [52]

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Thanks, folks.

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Operator [53]

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