HF Sinclair - Earnings Call - Q3 2017
November 1, 2017
Transcript
Speaker 0
Welcome to the HollyFrontier Corporation's Third Quarter twenty seventeen Conference Call and Webcast. Hosting the call today is the HollyFrontier is George Demeris, President and Chief Executive Officer. He is joined by Rich Balva, Executive Vice President and Chief Financial Officer Jim Stump, Senior Vice President of Refinery Operations and Tom Creery, President of Refining and Marketing. Please note that this conference is being recorded. It is now my pleasure to turn the floor over to Craig Breery, Director, Investor Relations.
Craig, you may begin.
Speaker 1
Thank you, Natalie, and good morning, everyone, and welcome to HollyFrontier Corporation's third quarter twenty seventeen earnings call. This morning, we issued a press release announcing results for the quarter ending September 3037. 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, 11/01/2017.
Any time sensitive information provided may no longer be accurate at the time of any webcast replay or rereading of the transcript. And with that, I'll turn the call over to George Demiris.
Speaker 2
Thanks, Greg. Good morning, everyone. Today, we reported third quarter net income attributable to HFC shareholders of $272,000,000 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 $70,000,000 on an after tax basis. Excluding these items, net income for the quarter was $2.00 $2,000,000 or $1.14 per diluted share versus $75,000,000 or $0.42 per diluted share for the same period last year.
Adjusted EBITDA for the period was $454,000,000 an increase of 119% compared to the third quarter of twenty sixteen. This increase was principally driven by higher refinery production and higher realized margins, combined with $23,000,000 of earnings from our PetroCanada 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 $36,000,000 and operating costs were $56,000,000 Our first eight months of EBITDA annualized to $141,000,000 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
Speaker 1
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 $5.7 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 twenty eighteen. We had scheduled maintenance in October on the gas oil 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.
Speaker 3
Thanks, Jim. For the third quarter of twenty seventeen, 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 $2.2 in the Rockies and $0.50 in the Southwest. The Brent WTI differential 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 $2.3 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 1,000,000 barrels during the third quarter at roughly 6,000,000 barrels. Diesel inventories were down by 1,500,000 barrels over the same time to close at 6,300,000 barrels. In terms of days supply, gasoline is at seventeen days and diesel is at twenty four days. Each of these ratios is at or near six year lows.
This and higher demand in the Gulf Coast post Harvey helped keep 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 twenty sixteen. We continue 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 twenty sixteen.
RINs expense in the quarter was $90,000,000 driven by higher biodiesel and ethanol RIN prices. For the fourth quarter of twenty seventeen, we expect to run between 910,000 barrels per day. With that, let me turn the call over to Rich.
Speaker 4
Thank you, Tom. Third quarter included a few unusual items. Pretax earnings were positively impacted by 111,100,000 lower of cost to market benefit, which was partially offset by $4,200,000 in PCI integration related charges. The table detailing these items can be found in our press release. PCLI's adjusted EBITDA for the quarter was $36,000,000 We remain confident in our expected annualized EBITDA range of 100,000,000 to $200,000,000 for 2017.
The third quarter of twenty seventeen cash flow from operations was $312,000,000 including turnaround expense of $25,000,000 and HollyFrontier's standalone CapEx for the quarter was $36,000,000 Due to the deferral of the Tulsa turnaround as well as other project timing, we expect to spend a total of $325,000,000 to $350,000,000 for both standalone capital and turnarounds for the full year of 2017. Additionally, we expect to spend 40,000,000 to $50,000,000 of capital at HEP, exclusive of acquisitions and $20,000,000 to $25,000,000 for PCLI. As of September 30, our total cash and marketable securities balance stood at $631,000,000 representing a $170,000,000 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 $1,000,000,000 of standalone debt and no drawings under our $1,350,000,000 credit facility.
This puts our liquidity at a healthy $2,000,000,000 and debt to cap at a modest 18%. Yesterday, HollyFrontier and Holly Energy Partners closed their previously announced IDR simplification transaction. HFC now owns 59,600,000 HEP limited partner units, representing a market value over $2,000,000,000 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 one, two and three base oils.
Going forward, we will continue to publish these lubricant indicators monthly along with the WTI based three:two:one 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.
Speaker 0
The floor is now open for questions. Our first question is coming from Roger Read from Wells Fargo.
Speaker 5
I guess maybe if we could come around really to the Brent TI differential. It seems like you're one of the more more favorably positioned companies for that. And I agree with you on 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?
Speaker 3
Yeah, Roger, it's Tom Curry. As you know, we're not a big international player, but the information that we've gained in talking to other traders and our counterparts, we realize the 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.
Speaker 5
Yeah, 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 WTI barrel through your system?
Speaker 3
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.
Speaker 5
Okay, great. And then George, maybe a question for you on PCLI, offering guidance for the year of 100,000,000 to $200,000,000 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 could 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?
Speaker 2
I think everybody everything is on pace for our expectations, Roger. We've said that our annualized number so far is 141. Obviously, the midpoint of our range is 150,000,000 We mentioned on our last call that we've achieved those results despite some operating issues at the plant. We're to the tune of $20,000,000 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 feed 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.
Speaker 5
Okay, great. Thank you.
Speaker 0
Your next question comes from the line of Chi Chao from Tudor Pickering. The
Speaker 6
margin capture rates across your refining system were noticeably higher than recent history relative to our indicators. Were there any kind of one time type of items in Q3 that contributed to that performance? Or do you think this is more the norm on operations going forward?
Speaker 2
Well, think, Gee, 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 higher the fixed cost represents a 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.
Speaker 6
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?
Speaker 3
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.
Speaker 2
And a little bit of that depends on what you're defining as higher gravity too, right? So between forty two and fifty, 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 usually think.
Speaker 6
Okay, thanks. And then maybe one final question, Rich, do you have an outlook yet for 2018
Speaker 4
CapEx? The Qi, 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 push it that direction. We'll have a full formal budget for you December 7.
Speaker 6
Okay. Do you think the maintenance and environmental spending will be about similar as this year? Any outlook there?
Speaker 1
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 three and some other issues.
Speaker 6
Okay, great. Thanks. Appreciate it.
Speaker 2
Thanks, Chi.
Speaker 0
Our next question comes from the line of Doug Leggate with Bank of America. Your line is open.
Speaker 7
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, dollars 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's giving you confidence that we're not still seeing some wash through from the hurricane impacts.
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 its quality differential? I'm just curious on your conviction on that. And I've got a follow-up, please.
Speaker 2
Yes. I think there is some hurricane effect in the prompt market. It's over $6 right now. I think like Tom said, transportation costs, if you figure it's $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.
And 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 normally, in the past, I thought that Brent is a better quality barrel than TI, even a quality TI barrel that comes from Midland.
Speaker 7
Yes. 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 2,000,000 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 of but do we need to wait in December for that? Or is have you got something in mind that's already on the books?
Speaker 2
No, I think we're going to continue the same strategy we've had to grow HEP in the past. We've mentioned in the past that we spend about $1,000,000,000 at HFC moving things around. Not all of that's 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 to buy pipelines that 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 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's some smaller LPs 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.
Speaker 7
All right. Appreciate the answers, George. Thank you.
Speaker 3
Thank you.
Speaker 0
Our next question comes from the line of Blake Fernandez from Scotia Howard. Your line is open.
Speaker 8
Guys, congrats on the results. Although I'm cursing you under my breath for hosting a 07:30 call the day after the world.
Speaker 1
Yes, just supposed to have this done by now. Exactly.
Speaker 8
I just wanted to go back to the lubes business. Obviously, pretty good quarter with $36,000,000 of EBITDA. It seems to be a run rate right in the fairway of kind of what we would think on a full year basis. Is there anything that drove that performance, whether it were like hurricane, storm related? I'm just trying to get
Speaker 7
a sense if this is
Speaker 8
a true underlying kind of run rate or if there are any one offs that kind of drove that number?
Speaker 4
Unbalanced Blake, I think we think it's a good run rate. As you saw in our indicators, Group one and two base oil cracks rose a little bit. I think that was somewhat storm affected. But Group three compressed a little bit, which was sort of a flip of Pearl GTL coming back on. You put that all on balance, we think this is a pretty reflective quarter.
Speaker 8
Okay. And if I'm not mistaken, Rich, mean, there's bit of a lag too, right?
Speaker 4
Yes, exactly. So we did in the second quarter, we saw some compression in the, what I'll call,
Speaker 3
the rack forward or from
Speaker 4
the refinery gate to the customer portion of the business. And 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 is pretty ratable and there's a lot of different bits and pieces. One of the
Speaker 2
good things about this business at
Speaker 4
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.
Speaker 8
Got it. Now 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 $7.08 dollars level?
I guess what I'm asking is, recognizing those similar discounts in the different regions or is that really just a WTI phenomenon?
Speaker 3
I think it's primarily a WTI phenomenon. In 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's going to have to be a reshuffling out. What it looks like now is WTI or domestic suite is under pressure as a grade itself, whereas the grades aren't seeing that to any great degree at this point in time.
Speaker 8
Got it. I appreciate it. Thank you.
Speaker 0
Our next question comes from Ryan Todd of Deutsche Bank. Your line is open.
Speaker 9
Great, thanks. Great quarter, guys. Maybe a couple, one, a little more strategic and one housekeeping. On 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 2020 IMO spec change that's coming, thoughts about potential investments that you would be interested in making or not interested in making in refining system to try to take advantage of that?
Speaker 3
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 ship owners 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.
Speaker 2
I think Ryan, this is George. In addition to what Tom said, we think it's going to widen out heavy crude diffs. As you know, we run a lot of heavy crude between El Dorado and Cheyenne. We've mentioned the project in the past to potentially debottleneck our coker at El Dorado to allow us to run about another 20,000 barrels a day Canadian 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.
Speaker 9
What would be the timeline on that if you were to FID it?
Speaker 2
No, I think it'd take two years from decision to implementation. We've got time before 2020. Yes.
Speaker 4
The good news, Ryan, on that is it's not something we have to do in any particular time. So particularly if we can find a supply deal or something that will underpin the economics, we can make that choice.
Speaker 9
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?
Speaker 1
Yes, we did have a bit of
Speaker 4
a working capital build in the quarter, right now. I wouldn't call anything out as 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'll see we expect to see a working capital draw, but there's nothing notable in here.
Speaker 0
Our next question comes from the line of Justin Jacobs from Raymond James.
Speaker 10
I guess I got to start again on crude differentials. Thinking about your crude slate in the quarter, it 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?
Speaker 3
Not directionally at this point in time. As you can be well aware, we run the LP and we're going to maximize crude basis 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.
Speaker 2
Yes, 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 light crude portfolio after that.
Speaker 10
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 potential corporate tax reform?
Speaker 2
Dang, Justin, I thought we're going to get through a call without Rich.
Speaker 10
I know, right? I know. Good for
Speaker 2
you for being late in the queue and still bring it up. Now look, we and others are obviously disappointed and concerned that a small number of senators can cause due process to be circumvented and that a President that promised to drain the swamp allowed that to happen. Effectively, these actions served as a veto power over some what we thought were very good proposals intended to fix high RIN price, a problem that everybody acknowledges is an unintended consequences of the RFS program. Having said that, we're encouraged that another group of senators have stepped forward. 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 in 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 RAC 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 of the political process to mitigate our RIN exposure.
Speaker 11
Perfect. Appreciate it, Thanks again.
Speaker 2
Thanks, Justin.
Speaker 0
Your next question comes from the line of Neil Banta from Goldman Sachs. Your line is open.
Speaker 11
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?
Speaker 2
Well, 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, say 105,000 barrels a day and taken it up to low teens. So every basically, call it, an 8,000 barrel a day expansion as a result of all that work. The more volume you push to a plant, as you know, the lower unit costs. I think we've been helped by some operating issues at some refineries on the West Coast that have helped drive the margins up. CPG prices in Phoenix have been especially strong as a result of that.
So that's what's been the major driver on the margin side.
Speaker 11
Thanks, Stuart. The second question is at the twenty fifteen Analyst Day, you guys had come out with a plan to be aggressive around capital returns, particularly in the form of the buybacks. As we go into the twenty seventeen 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 buybacks? Yes,
Speaker 4
Neil, I think we'll continue to return excess cash to shareholders. Our first priority remains our investment grade rating. And our second is to keep and grow to your point a competitive regular dividend. So any excess cash will continue to look
Speaker 3
for the highest and best use of
Speaker 4
that whether it's to reinvest in the business, whether it's to acquire business or whether it's to return it to the shareholder.
Speaker 11
All right. Thanks, guys.
Speaker 9
Thanks, Neil.
Speaker 0
Our next question comes from the line of Phil Gries from JPMorgan. Your line is open.
Speaker 11
Yes. Hi, good morning. Just following up on RINs. Did you give your RINs cost for the quarter and what your expectations would be for the full year at this point?
Speaker 4
So Phil, the RIN cost was roughly $90,000,000 in the third quarter. What I'd say is our expectation continues to be, look, we can't call the market. It's up the ethanol RIN market is up substantially quarter to date versus the third quarter. So volume is being equal, we'd expect that number to be higher. Biodiesel RIN market is roughly traded even for most of the year.
Speaker 11
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 while, it's widening now when you think about quality and transport.
What's your long term view for that differential?
Speaker 3
Phil, this is Tom Curry. We've seen strength in WTS basically because it's competing with Mars and we saw some Mars being exported earlier in the year. Looks like the majority of the exports now from what we understand are WTI based or WTI look alike crudes. In fact, they're around 45 degrees. That's what's going on at Corpus right now.
So probably what we think is going to happen is that there's 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 I wouldn't be surprised if we saw WTS trade above WTI on a go forward basis.
Speaker 11
Okay. I apologize. If I said WTS, I meant WCS.
Speaker 3
No, I'm sorry WCS, maybe I misheard you. Same basic questions. I don't I'm not sure that U. S. Exports are going to have any impact on WCS price.
I think Canadian crude oil is going into
Speaker 2
the Gulf Coast is going
Speaker 3
to compete with Maya, Venezuelan crude and that's probably going to have a bigger impact on the differential netted back to Hardisty.
Speaker 2
I 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
Speaker 3
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 pushing.
Speaker 11
Right, okay. And if I could just ask one more, I know you kind of clarified already that you're comfortable with the run rate of the lubes EBITDA as it is. But George, just given that you did talk about $20,000,000 worth of maintenance and other headwinds that happened in the first half, 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?
Speaker 2
Yes. 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's something usually offsetting that somewhere else. So again, I think we feel comfortable in that mid-one $101,150 ish EBITDA range for PCLI.
Speaker 11
Sure. And that's before any of the synergy potential you talked about?
Speaker 2
That's correct. Correct.
Speaker 10
Okay. Thank you.
Speaker 0
And your last question comes from the line of Paul Cheng from Barclays. Your line is open.
Speaker 12
Good morning. Good morning, Paul. George, if I recall correctly, in
Speaker 2
the
Speaker 12
past, your WCS purchase, I think roughly about half of them is based on a sort of fixed defense to WTI. Is that contract still here or that whether for next year that you may be more exposed to the spot defense or given that some people may indeed think that WTI WCS could widen quite meaningfully over the next couple of years?
Speaker 2
Paul, I think you have a tremendous memory for the history. But we currently have
Speaker 12
no It's me that I'm old.
Speaker 2
Well, we were just talking about that. Yes. But for myself, so 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.
Speaker 12
Yes. And my suggestion is that don't lock it in. I think that you're better off that to just let it flow. We're good here. Yes.
And that the second question actually, maybe there is actually two more questions, if I may. One is on the M and A on the bid ask, whether that you see the current market is still different is too wide or that you think is now start to coming to a point, maybe the more doable of a deal? And also that do you have a number what is the back wax and yellow wax you are running at wood cost and how much is the same crew you're running over there?
Speaker 2
Okay, that's the 2A, 3B or something like that. No. On M and A, Paul, we don't see a whole lot of activity out there. I think you've seen the same deals that transacted 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 to what we want to grow. We want to grow prudently and economically. So we're still looking for deals. They're not again, they're not a lot of deals out there. And when deals do pop up, we're to exercise discipline.
Now as far as the question on black 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.
Speaker 12
So are you seeing the production in bag wax and yellow wax now is have turned around and start growing again?
Speaker 2
Yeah, I'd say it's growing, but at a fast 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.
Speaker 12
And are you running anything crude in Woodcross?
Speaker 3
Yes, Paul. We're running limited amounts between 7,000 barrels a day of synthetic crudes at Woodcross at this point in time.
Speaker 2
And a lot of that is price dependent.
Speaker 8
Okay, thank you.
Speaker 2
Thanks, Paul.
Speaker 0
And our next question comes from the line of Chi Chao Hulse of Tudor Pickering. Your line is open.
Speaker 6
Hi, thanks. Just one follow-up. You were talking about the El Dorado Coker expansion project. I think Rich, you mentioned that you may look at a supply deal to underpin those economics. Would you consider taking or committing to line space on something like Keystone XL to secure those barrels?
Speaker 3
This is Tom again. Currently, we've got a fair amount of line space both on 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.
Speaker 6
So is it would you be looking at some sort of linked production then when you're talking about that sort of supply deal?
Speaker 2
I'm not sure what you mean by linked production. I mean, somebody delivering the barrels to us at pushing something?
Speaker 6
Yeah, some sort of agreement with a producer.
Speaker 2
Yeah. That's all on the table, G. And again, like I mentioned earlier, we're continuing to see what the market is for this type of project and its economics and the security of a home for, again, roughly 20,000 barrels a day of heavy Canadian crude.
Speaker 6
Okay. Thanks, John.
Speaker 3
And Cheesen? A follow-up on that as well. I'm sure that you're aware of Platts' plans to tie into Spearhead in 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 will help us optimize crude slate between Cheyenne and the Mid Continent refiners as well.
Speaker 6
Okay, great. That's helpful. Thanks, Tom.
Speaker 2
Thanks, Chi.
Speaker 0
And there are no further questions. I would now like to turn the floor back over to Craig for closing remarks.
Speaker 1
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.
Speaker 0
Thank you. This does conclude today's teleconference. Please disconnect your lines at this time, and have a wonderful day.