Welcome to the HollyFrontier Corporation's Third Quarter 2017 Conference Call and Webcast. Hosting the call today is the HollyFrontier is George Damiris, President and Chief Executive Officer. He is joined by Rich Voliva, Executive Vice President and Chief Financial Officer; Jim Stump, Senior Vice President of Refinery Operations; and Tom Creery, President of Refining & Marketing. At this time, all participants have been placed in a listen-only mode, and the floor will be open for questions following the presentation. Please note that this conference is being recorded. It is now my pleasure to turn the floor over to Craig Biery, Director, Investor Relations. Craig, you may begin.

Thank you, Natalie, and good morning, everyone, and welcome to HollyFrontier Corporation's third quarter 2017 earnings call. This morning, we issued a press release announcing results for the quarter ending September 30, 2017. If you would like a copy of the press release, you may find one on our website at hollyfrontier.com. Before we proceed with prepared remarks, please note the Safe Harbor disclosure statement in today's press release. In summary, it says statements made regarding management expectations, judgments or predictions are forward-looking statements. These statements are intended to be covered under the Safe Harbor provisions of federal security laws. There are many factors that could cause results to differ from expectations, including those noted in our SEC filings. Today's statements are not guarantees of future outcomes. The call also may include discussion of non-GAAP measures, and please see the press release for reconciliations to GAAP financial measures. Also, please note that information presented on today's call speaks only as of today, November 1, 2017. Any time-sensitive information provided may no longer be accurate at the time of any webcast replay or re-reading of the transcript. And with that, I'll turn the call over to George Damiris.

Thanks, Craig. Good morning, everyone. Today, we reported third quarter net income attributable to HFC shareholders of $272 million or $1.53 per diluted share. Certain items detailed in our earnings release and that Rich will discuss in his prepared remarks, increased net income by $70 million on an after-tax basis. Excluding these items, net income for the quarter was $202 million or $1.14 per diluted share versus $75 million or $0.42 per diluted share for the same period last year. Adjusted EBITDA for the period was $454 million, an increase of 119% compared to the third quarter of 2016. This increase was principally driven by higher refinery production and higher realized margins, combined with $23 million of earnings from our Petro-Canada Lubricants business. For the quarter, crude oil charge was approximately 455,000 barrels a day, within our guidance range. Our PCLI lubricants business had a strong third quarter led by solid operations and strengthening margins in the base oil market. Adjusted EBITDA for the quarter was $36 million, and operating costs were $56 million. Our first eight months of EBITDA annualized to $141 million, at the midpoint of our guidance range. Production levels increased quarter-over-quarter as we completed planned maintenance in July. Our plan is to run the plant at normal operating levels through the end of the year. We look forward to sharing more about our lubricants business at our upcoming Analyst Day in December. HollyFrontier's strong financial results reflect our ability to capitalize on the margins available during the third quarter. Additionally, PCLI performed well, and we're reaching the conclusion of our integration project. To-date, fourth quarter margins have held steady. With no major turnaround work scheduled until February of next year, we expect a strong finish to 2017. Now, I'll turn the call over to Jim for an update on our operations.

Thank you, George. As George mentioned, for the third quarter, our crude throughput was 455,000 barrels per day despite an unplanned reduction at El Dorado. Our Navajo plant set a new quarterly crude charge record averaging over 112,000 barrels per day in the third quarter while also setting production records for both gasoline and diesel. These are the benefits of the new optimization project completed during our first quarter turnaround. The Navajo refinery also set a new low quarterly operating expense, averaging just $4.13 per throughput barrel during the period. The Rockies region continues to improve operationally. We set a quarterly crude record charge averaging over 80,000 barrels per day for the quarter and ran over 50,000 barrels per day at Cheyenne in September. Our consolidated operating cost of $5.32 per throughput barrel was slightly elevated versus the $5.07 we posted in the same period last year due to the maintenance we incurred in the third quarter. Due to the effects of Hurricane Harvey, we made the decision to push our planned Tulsa West turnaround from November of this year to February of 2018. We had scheduled maintenance in October on the gas oil and hydrocracker in Woods Cross that is now complete, and we have no other work planned for the remainder of the year. I will now turn the call over to Tom for an update on our commercial operations.

Thanks, Jim. For the third quarter of 2017, we ran 25% sour and 20% WCS and black wax crude oil. Our average laid-in cost in the Mid-Con was flat against WTI and under WTI by $2.20 in the Rockies and $0.50 in the Southwest. The Brent/WTI differentials started to widen during the third quarter and still remains wide at over $6 a barrel, providing a tailwind into the fourth quarter. We experienced tightening differentials primarily amongst our heavy and sour crude slates during the third quarter. However, currently, we are seeing a move toward historical level as Canadian differentials in synthetic and WCS crudes are currently trading at plus $2.30 and minus $13, respectively, well off their third quarter averages. Midland third quarter price differentials showed strength over the second quarter as the Brent-TI spread provided the incentive to move barrels to the U.S. Gulf Coast for export. In the future, we expect differentials including the Brent-TI to be set by transportation and quality. Due to the effects of Hurricane Harvey, we expect to experience some relief on product inventories during the third quarter. Gasoline inventories in the Magellan system dropped by 1 million barrels in the third quarter, roughly 6 million barrels. Diesel inventories were down by 1.5 million barrels over the same time to close at 6.3 million barrels. In terms of days supply, gasoline is at 17 days and diesel is at 24 days. Each of these ratios is at or near six-year lows. This higher demand in the Gulf Coast post Harvey helped cracks in the Mid-Con in the third quarter higher as compared to the second quarter of this year. Third quarter consolidated gross refinery margin was $14.55 per produced barrel. This represented a 48% increase over the $9.83 recorded in the third quarter of 2016. We continued to see improvements in our Rocky Mountain region with a realized gross margin of $17.78 per produced barrel. This represented a 60% increase from the third quarter of 2016. RINs expense in the quarter was $90 million driven by higher biodiesel and ethanol RIN prices. For the fourth quarter of 2017, we expect to run between 450,000 barrels and 460,000 barrels per day. With that, let me turn the call over to Rich.

Thank you, Tom. Third quarter included a few unusual items. Pre-tax earnings were positively impacted by $111.1 million lower of cost or market benefit, which was partially offset by $4.2 million in PCLI integration-related charges. The table detailing these items can be found in our press release. PCLI's adjusted EBITDA for the quarter was $36 million. We remain confident in our expected annualized EBITDA range of $100 million to $200 million for 2017. The third quarter of 2017 cash flow from operations was $312 million including turnaround expense of $25 million, and HollyFrontier's stand-alone CapEx for the quarter was $36 million. Due to the deferral of the Tulsa turnaround and as well as other project timing, we expect to spend a total of $325 million to $350 million for both stand-alone capital and turnarounds for the full year of 2017. Additionally, we expect to spend $40 million to $50 million of capital at HEP, exclusive of acquisitions, and $20 million to $25 million for PCLI. As of September 30, our total cash and marketable securities balance stood at $631 million, representing a $170 million increase over our balance on June 30. During the quarter, we announced and paid a $0.33 regular dividend, putting our yield at 3.6% as of last night's close. As of September 30, we have a $1 billion stand-alone debt and no drawings under our $1.35 billion credit facility. This puts our liquidity at a healthy $2 billion and debt to cap at a modest 18%. Yesterday, HollyFrontier and Holly Energy Partners closed their previously announced IDR Simplification transaction. HFC now owns $59.6 million HEP limited partner units, representing a market value over $2 billion as of last night's close. We believe this transaction provides both fair value for the IDRs to HollyFrontier as well as strengthens HEP's capital structure for long-term sustainable growth. As a reminder, we published benchmark margins for Group I, II and III base oils. Going forward, we will continue to publish these lubricant indicators monthly along with the WTI based 3-2-1 margins in each of our operating regions. These regional product and base oil indicators do not reflect actual sales data and are meant to show monthly trends. Realized gross margin per barrel may differ from indicators for a variety of reasons. You can find this data on the investor page of www.hollyfrontier.com. And with that, Natalie, we're ready to take questions.

The floor is now open for questions at this time. Thank you. Our first question is coming from Roger Read from Wells Fargo. The floor is yours.

Thank you. Good morning and congrats on the quarter, guys.

Good morning, Roger.

I guess, maybe if we could come around really to the Brent-TI differential, it seems like you're one of the more favorably positioned companies for that. I agree with you in the long term in terms of transportation and quality but I guess, one of the questions here is what is the right transportation number. And we've heard about lighter barrels maybe leading to a little bit of a quality differential. So, is it a $4 long-term differential we should think about, something closer to $3? I mean, do you have any sort of detail to offer on that?

Yeah, Roger. It's Tom Creery. As you know, we're not a big international player, but the information that we've gained in talking to other traders and their counterparts, we realized that transportation rates have gone up from Europe back into the Gulf Coast in freight rates. So, on the long term, we're probably expecting between $4 and $5, and I think that's supported by the futures market at this point in time.

Yeah, I would agree with that. I just didn't know if you could give us any kind of thoughts on maybe the quality or whether or not you've seen any changes running a WTI barrel through your system.

We have not – the barrels that we run out of the Mid-Continent as sourced through Cushing, we have not seen any appreciable quality changes.

Okay. Great. And then, George, maybe a question for you on PCLI, still offering guidance for the year of $100 million to $200 million. We're three quarters through the year. Surprised you're not tightening that up a little bit. And I know that you're going to really want to focus on it at the Analyst Day, but I was just curious if you can give us some ideas. You've had it almost nine months now or I guess, by today, it's nine months, how it's performing relative to your expectations.

I think everything is on pace for our expectations, Roger. We've said that our annualized number so far is $141 million. Obviously, the midpoint of our range is $150 million. We mentioned on our last call that we've achieved those results despite some operating issues at the plant to the tune of $20 million. So, we hope to rectify that going forward. And again, as we've talked in the past, that excludes the synergies, we believe, we get from combining this business with our Tulsa business, opportunities to optimize crude slate and to optimize the product slate and produce more finished products. So, again, more to come in December when we see you guys in New York.

Okay. Great. Thank you.

Thank you, Roger.

Your next question comes from the line of Chi Chow of Tudor, Pickering. Your line is open.

Good morning. The margin capture rates across your refining system were noticeably higher than recent history relative to our indicators. Were there any kind of onetime type of items in Q3 that contributed to that performance or you think this is more the norm on operations going forward?

Well, I think, Chi, I think we've talked about this a little bit in the past. This is kind of a function of the absolute crack spread as well. So, as you know, a lot of the things that detract from capture rate are fixed in nature. So, at a lower margin, the fixed cost represents the higher percentage and thus a lower capture rate. So, like in the third quarter with the higher margin, the fixed costs are lower percentage and thus the higher capture rate.

Okay. Thanks. With that increased crude flexibility you now have at Navajo, are you seeing any sort of appreciable discount on the higher API gravity barrels there?

To-date, at this point in time, Chi, we haven't seen any appreciable discounts on the higher-gravity barrels at this point in time.

And a little bit of that depends on what you're defining as higher gravity too, right? So, between $42 and $50, I'd say not too much discount. Once you start getting above $50, that's where you start seeing some discount, but with as much pipeline capacity that's been built in the Permian, people are starving for barrels to put in the pipes, and the differentials aren't as wide as you'd usually think.

Okay. Thanks. And then maybe one final question, Rich. Do you have an outlook yet for 2018 CapEx?

So, Chi, we're firming it up now. Directionally, it will be higher, largely driven by a higher turnaround schedule in 2018. The Tulsa deferral is going to push at that direction. We'll have a full formal budget for you December 7.

Okay. Do you take the maintenance and environmental spending will be about similar this year? Any outlook there?

So, environmental – the turnarounds are up, but substantially, everything else is down. Environmental spending is drastically down as we finish completing our work on Tier 3 and some other issues.

Okay. Great. Thanks. Appreciate it.

Thanks, Chi.

Our next question comes from line of Doug Leggate of Bank of America. Your line is open.

Thanks. Good morning, everybody. I guess, George, can I go back to your Brent-TI comment that you gave to Roger? I'm just curious, $4 to $5, obviously, would – I guess, that would be sustainably above what most folks have got in their numbers right now. And I'm just curious what has given you confidence that we're not still seeing some wash-through from the hurricane impact, and, of course, TI is a higher-quality grade. So, if you remove the transport bottlenecks, what leads you to think TI doesn't narrow that gap a little bit on this quality differential? I'm just curious on your conviction on that. I've got a follow-up, please.

Yeah, I think there is some hurricane effect in the Brent market. It's over $6 right now, and I think, like Tom said, transportation costs, if you figure it $2 to $3 to get from either Midland or Cushing to the Gulf and then another $2 or $3 to get from the Gulf to a foreign market, that's where we're coming up with, call it, $5 on transportation. Then from a quality perspective, Brent is a good barrel. It's got a lot of distillate in it, but obviously, the quality differential between Brent and TI depends on the gasoline diesel spread as well. But nominally, in the past, I've thought that Brent is a better quality barrel than TI, even a quality TI barrel that comes from Midland.

Yeah. I guess, what was at the back of my mind was the export dynamics because in all prior periods, the U.S. wasn't exporting 2 million barrels a day, so that's really what I was kind of getting at, I guess. Okay. My follow-up is really on the IDR exchange. So, now you've done this, I'm curious on the timing. Obviously, it's been coming for a while, I guess, for you guys, but now that you're there, is there a visible pipeline that you expect HEP to be able to compete against in terms of with a lower cost of capital now, I guess, is better able to look at acquisitions? I'm just curious (20:43) in December for that or have you got something in mind that's already on the books?

No, I think we're going to continue the same strategy we've had to grow HEP in the past. We'd mentioned in the past that we spend about $1 billion at HFC moving things around. Not all of that is going to be addressable by HEP. But to the extent that we can substitute the third-party service providers with HEP, we'll continue to do that. I think you've seen that in some of the deals we've done over the last couple of years by pipeline to feed our refineries, tanks that service our refineries or product systems that take product out of our refineries. We've got a decent position, as we said in the past, around the Permian. As you know, the Permian is a scorching hot market and a lot of dollars chasing deals around there. So, it's going to be very competitive, but again, we've got a good position to leverage there. And then I think there's going to be some consolidation in the MLP space that we'd like to think there are some smaller MLPs that fit us that we can acquire and bolt on to HEP. So, nothing more specific than that, Doug. And we'll continue to work across all those dimensions.

All right. I appreciate the answers, George. Thank you.

Thank you.

Our next question comes from the line of Blake Fernandez of Scotia Howard. Your line is open. Blake Fernandez - Scotia Capital (USA), Inc. Guys, congrats on the results although I'm cursing you under my breath for hosting a 7:30 call the day after the World Series.

The Astros were supposed to have this done by now. Blake Fernandez - Scotia Capital (USA), Inc. Yeah. Exactly. I just want to go back to the lubes business. Obviously, a pretty good quarter with $36 million of EBITDA. It seems to be a run rate riding in the fairway of kind of what we would think on a full-year basis. Is there anything that drove that performance, whether it be like hurricanes, storm-related? I'm just trying to get a sense if this is a true underlying kind of run rate or if there are any one-offs that kind of drove that number.

So, on balance, Blake, I think we think it's a good run rate. As you saw in our indicators, Group I and II base oil cracks rose a little bit , and I think that was somewhat storm affected, but Group III compressed a little bit, which was sort of a flip of Pearl GTL coming back on. You put that all in balance, and we think this is a pretty reflective quarter. Blake Fernandez - Scotia Capital (USA), Inc. Okay. And if not mistaken, Rich, I mean, there is a bit of lag, too, right?

Yeah. Exactly. In the second quarter, we saw some compression in what I'll call the rack forward or from the refinery gate and the customer portion of the business. We got some of that back in the third quarter. Between the two, that's pretty ratable. So, I'm doing a half-handed job of saying, we think that $36 million is pretty ratable, and there's a lot of different bits and pieces. One of the good things about this business at the end of the day is it does produce these kind of ratable results because there's enough offsets within the business or from quarter to quarter. Blake Fernandez - Scotia Capital (USA), Inc. Got it. No, that's helpful. The second question, I'm not sure really if this is answerable necessarily, but we talked about the WTI-Brent spread being so expanded. But if you look at a lot of the regional differentials, whether it's Bakken, Permian, it doesn't seem like those discounts have been, I guess, similar to what we've seen in the past. And so, I guess, what I'm just trying to understand is as we kind of move into 4Q here, do you think it's fair to feel like maybe some of the capture rates are not going to be reflective of the old days when we saw WTI-Brent back at the $7, $8 level? I guess, what I'm asking is, are you recognizing those similar discounts in the different regions or is that really just a WTI phenomenon?

I think it's primarily a WTI phenomenon. And some of the grades, for example, Bakken at Cushing, we're seeing that trade at higher levels than we have historically as some of the other grades have. And I think this is a reflection of – in the example of Bakken is the effects of the DAPL pipeline taking barrels to a different market. So, I think there is going to have to be a reshuffling out. What it looks like now is WTI or Domestic Sweet is under pressure as a grade itself, whereas the grades aren't seeing that to any great degree at this point in time. Blake Fernandez - Scotia Capital (USA), Inc. Got it. I appreciate it. Thank you.

Our next question comes from Ryan Todd of Deutsche Bank. Your line is open.

Great. Thanks. Great quarter, guys. Maybe a couple, one a little more strategic and one, housekeeping. You mentioned a little bit of commentary on the capital budget for next year. I mean, when you look forward over the next few years, any potential as you look at the potential of 2020 IMO spec change that's coming, any thoughts about potential investments that you would be interested in making or not interested in making in your refining system to try to take advantage of that?

Specifically, in regard to IMO 2020, we don't see a major effect on HollyFrontier at this point in time. What we do expect to see is an increase in the diesel market because we think that's going to be the substitute fuel that the shipowners are going to go to. We don't move fuel oil to the Gulf Coast on a regular basis, so it's going to have very little, if any, impact upon us.

Ryan, this is George. In addition to what Tom said, we think it's going to widen out heavy crude depth. As you know, we run a lot of heavy crude between El Dorado and Cheyenne. We've mentioned a project in the past to potentially debottleneck our coker at El Dorado that would allow us to run about another 20,000 barrels a day in the heavy crude. We're continuing to engineer that project, but we haven't made a final investment decision, but it's still a project that looks attractive that we'll continue to monitor the market for.

What would be the timeline on that if you were to (27:15)?

I think it would take two years from decision to implementation. We've got time before 2020.

Yeah, the good news, Ryan, on that is it's not something we have to do at any particular time. So, particularly if we can find a supply deal or something that will underpin the economics, we can make that choice.

Okay. Thanks. That's helpful. And then maybe just one housekeeping one on cash flow. It seems like there was a decent working capital build possibly in the quarter. Can you maybe talk about what impact working capital had on the cash flow number?

Yeah, we did have a bit of a working capital build in the quarter, Ryan, now. I wouldn't call anything out being particularly noisy. We do typically see working capital kind of build and fall with crude rate a little bit too. So, particularly as we're looking into the first quarter, we'd expect to see a working capital drop, but there's nothing notable in here.

Okay. Thanks.

Our next question comes from the line of Justin Jenkins of Raymond James. Your line is open.

Thanks. Good morning, everybody. I guess, I got to start again on crude differentials. Just thinking about your crude slate in the quarter seems like the overall mix was pretty similar to what it's been recently. I guess, curious if any of the changes we've seen over the past month or two have altered the overall mix of crudes or planned mix of crudes running through the system going forward.

Not directionally at this point in time. As you can be well aware, we're on the LP and we're going to maximize crude bases on current prices. But we will be running a little bit more black wax as we go forward at Woods Cross. That's something that we're looking forward to. But for the Mid-Continent, a lot of it depends on the Canadian heavy prices on what other crudes that we run as well.

Yeah, Justin, just to give you a little more flavor here. With the cokers we have especially at El Dorado, we have a huge incentive to keep those full with heavy Canadian, so we'll take a really narrow spread to substitute out heavy Canadian with additional light barrels until we fill that coking capacity. So, that heavy Canadian part of the slate is a fairly strong base load, and then we optimize the light crude portfolio after that.

Perfect. That's helpful. And then, I guess, shifting gears to maybe the regulatory front, it seems like a lot of noise here lately on RINs, both good and maybe even more bad. Any update in terms of what you're seeing for the outlook there and maybe any initial views towards the potential corporate tax reform?

Thanks, Justin. I thought we're going to get through a call without RINs. So...

I know, right? I know.

Good for you for being late in the queue and still bringing it up. No, look, we and others are obviously disappointed and concerned that a small number of senators can cause due process to be circumvented and that the president in position promised to drain the swamp allowed that to happen. Effectively, these actually served as a veto power over some what we thought were very good proposals, intended to fix high RIN price, the problem that everybody acknowledges is an unintended consequence of the RFS program. Having said that, we're encouraged that another group of senators have stepped forward, and they're trying to bring together the administration and Members of Congress from both the biofuel and refining states to find a mutually acceptable solution. We continue to think we have right on our side and that the United States right prevails. We're going to continue to work and fight to make that so. It's not going to be easy as we all know. It's taken a lot longer than we all expected. But we're going to continue to fight on the political side. And then at the same time, we'll continue to focus on efforts we can make on the commercial side of our business as well, continue to grow our rack sales so we can capture RINs, expanding into wholesale markets to again capture more RINs, and looking at other commercial strategies like that that, again, are more in our control than the political process to mitigate our RIN exposure.

Perfect. Appreciate it, guys. Thanks again.

Thanks, Justin.

Your next question comes from the line of Neil Mehta from Goldman Sachs. Your line is open.

Good morning, guys. Great quarter. One place I want to start, George was, on Navajo where you exceeded, I think, Street expectations on both volumes and on margins. Can you just walk us through the results there and anything you'd call out?

Well, I think Jim highlighted the benefits of the projects in the turnaround work we did in the first quarter that has basically taken a refinery that most recently ran mid 100,000 barrels a day, say, 105,000 barrels a day and taking it up to the low teens, so every – basically, let's call it an 8,000 barrels a day expansion as a result of all that work. The more volume you push through a plant, as you know, the lower unit costs. I think we've been helped by some operating issues with some refineries on the West Coast that have helped drive the margins up. CBG prices in Phoenix have been especially strong as a result of that. So, that's what's been the major driver on the margins side.

Thanks, George. The second question is at the 2015 Analyst Day, you guys had come out with a plan to be aggressive around capital returns particularly in the form of buybacks. As we go into the 2017 Analyst Day, can you just talk about with margins in a better place, whether HollyFrontier thinks it can be in a position to either be more aggressive around dividend growth again, not in the form of a special dividend but at least growing the dividend or around buyback stocks?

Yeah, Neil. So, I think, look, we'll continue to return excess cash to shareholders. Our first priority remains our investment grade rating, and our second is to kind of keep and grow, to your point, a competitive regular dividend. So, any excess cash, we'll continue to look for the highest and best use of that, whether it's to reinvest in the business, whether it's to acquire a business or whether to return it to the shareholder.

All right. Thanks, guys.

Thanks, Neil.

Our next question comes from the line of Phil Gresh from JPMorgan. Your line is open.

Yes. Good morning. Just following up on RINs, did you give your RINs costs for the quarter and what your expectations would be for the full year at this point?

So, Phil, the RINs cost is roughly $90 million in the third quarter. What I'd say is our expectation continues to be – look, we can't call the market. The ethanol RIN market is up substantially quarter-to-date versus the third quarter. So, volumes being equal, you'd expect that number to be higher. Biodiesel RIN market is roughly traded even for most of the year.

Right. Got it. Okay. And I know there's been a lot of questions on Brent-WTI. Curious how you think about WTI versus WCS. That had been tight for a little while. It's widening now when you think about quality and transport. Well, what's your long-term view for that differential?

Phil, this is Tom Creery. We've seen strength in WTS basically because it's competing with Mars, and we saw some Mars being exported earlier in the year. It looks like the majority of the exports now, from what we understand, are WTI based or WTI-look-alike crudes. In fact, there's around 45 degrees. That's what's going out of Corpus right now. So, probably what we think is going to happen is that there is still going to be a demand for those sour crudes in the Gulf Coast, and they will compete against Canadian imports and foreign imports as well, so wouldn't be surprised if we saw WTS trade above WTI on a go-forward basis.

Okay. I apologize if I said WTS. I meant WCS.

Oh. I'm sorry. WCS. Maybe I misheard you so – same basic questions. I'm not sure that U.S. exports are going to have any impact on WCS prices. I think Canadian crude oil and going into the Gulf Coast is going to compete with Maya, Venezuelan crudes, and that's probably going to have a bigger impact on the differential net impact to Hardisty.

Yeah, I think we expect that differential to widen. There's more production coming on in Canada in the fourth quarter. So, that's going to be favorable. And then as we look further out in the future, as we talk about the IMO and the impact that's going to have on the fuel oil market, that fuel oil is going to have to be basically coked, which is going to fight for coker capacity with heavy crude barrels, so, again, further helping widen differential between WCS and WTI.

And to mirror George's comments, we're starting to see apportionment on the Enbridge system going into the fourth quarter, which we haven't seen in a few months, and that's just indicative of more Canadian crude coming on stream and not enough pipeline takeaway capacity to get it to the Gulf Coast or Cushing.

Right. Okay. And if I could just ask one more, I know you've kind of clarified already that you're comfortable with the run rate of the lube's EBITDA as it is. But, George, just given that you did talk about $20 million worth of maintenance and other headwinds that happened in the first half, I was never quite clear how much of that was specifically in the second quarter. But just given that headwind and the comment that there were some market headwinds there in the second quarter as well from a timing perspective, if I understood that correctly, I would have thought maybe you could even be run rating a little bit higher on the EBITDA on a go-forward basis.

Yeah, again, we'll talk about that more in December. I don't think we're ready to roll that into our long-term EBITDA forecast. As you know, every time you have something going your favor or something that went against you, that's going to revert, there is something usually offsetting that somewhere else. So, again, I think we feel comfortable in that mid-$100 million, $150-ish million EBITDA range for PCLI.

Sure. And that's before any of the synergy potential you talked about.

Yes.

That's correct. Correct.

Okay. Thank you.

And your last question comes from the line of Paul Cheng from Barclays. Your line is open.

Yes. Good morning.

Hi, Paul.

George, if I recall correctly, in the past, your WCS purchase, I think roughly about half of them is based on a sort of fixed differential to WTI. Is that contract still here or that whether for next year that you may be more exposed to the spot differential given that some people may indeed think that WTI, WCS could widen quite meaningfully over the next couple of years?

Yeah. Paul, I think you have a tremendous memory for the history, but we currently have no...

Is that telling me that I'm old.

Well, we were just talking about that, yeah, but for myself though. But no, we have no fixed differentials on WCS. We're entirely at spot differential. Now, from time to time, we could put a financial instrument overlay on that to lock some of that spread in, but we typically do not do that. So, basically, think long term, as far as being a spot participant in that differential.

Yeah. And my suggestion is that don't lock it in. I think that you're better off that you just let it (40:43).

We're with you.

Yeah. And that the second question actually, maybe that is actually two more questions, if I may. One is on the M&A on the bid/ask, whether that you see the current market is still – the difference is too wide or that you think is now start to coming to a point, just maybe then more doable of a deal. And also that do you have a number what is the black wax and yellow wax you are running at what cost and how much is the syncrude you're running over there?

Okay. That's 2 a, b, c or something like that. No. On M&A, Paul, we don't see a whole lot of activity out there. I think you've seen the same deals, the transactions that we've seen. There was one transaction that we would have liked to have been the winner on, but the price was way in excess of our valuation for it. I think that is a further illustration of the discipline that we're going to impose on ourselves, but we want to grow. We want to grow prudently and economically. So, we're still looking for deals. Again, there are not a lot of deals out there. And when deals do pop up, we're going to exercise discipline. Now, as far as the question on black wax and yellow wax at Woods Cross, we're running about 20 a day. And it's about two-thirds black, one-third yellow. And yellow is growing faster than black in the field.

So, are you seeing the production in black wax and yellow wax now just have turned around and start growing again?

Yeah, I'd say it's growing but not at as fast a rate, but we're pleased with the activity we're seeing out in the Uinta Basin and the quality of the producers that are involved with that production increase.

And are you running any syncrude and what cost?

Yeah, Paul. We're running limited amounts between 2,000 barrels and 5,000 barrels a day of synthetic crudes at Woods Cross at this point in time, and a lot of that is price-dependent.

Okay. Thank you.

Thanks, Paul.

And our next question comes from the line of Chi Chow of Tudor, Pickering. Your line is open.

Hi. Thanks. Just one follow-up. You were talking about the El Dorado coker expansion project, and I think, Rich, you mentioned that you may look at a supply deal to underpin those economics. Would you consider taking or a committing to wind space on something like Keystone XL to secure those barrels?

Chi, this is Tom again. Currently, we've got a fair amount of line space both on the Enbridge and on Keystone, the old Keystone. And we feel that we have enough capacity to move crude to Cushing to support that project going forward. And if we come up a little bit short, we expect that there's going to be a fairly robust market at Cushing itself. So, transportation would not necessarily be the key driver on that decision.

Would you be looking at some sort of link to production then when you're talking about that sort of supply deal?

I'm not sure what you mean by linked production. You mean somebody delivering the barrels to us at Cushing?

Yeah, some sort of agreement with a producer. Yeah.

Yeah. No, that's all on the table, Chi. Again, like I mentioned earlier, we continue to see what the market is for this type of project, and it's economics and the security of a home for, again, roughly 20,000 barrels a day of heavy Canadian crude.

Okay. Okay. Thanks, gents. Appreciate it. (45:12)

And, Chi, just a follow-up on that as well. I'm sure that you're aware of Platte's plans to tie into Spearhead and Nebraska, so that will allow us to get crude from Canada down Express to Cushing as well that could go to that coker expansion and that'll help us optimize crude slate between Cheyenne and the Mid-Continent refiners as well.

Okay. Great. That's helpful. Thanks, Tom.

Thanks, Chi.

And there are no further questions. I would now like to turn the floor back over to Craig for closing remarks.

Thanks, everyone. If you have any follow-up questions, as always, reach out to Investor Relations. Otherwise, we look forward to sharing our fourth quarter results with you in February.

Thank you. This does conclude today's teleconference. Please disconnect your lines at this time and have a wonderful day.