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 and 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. If you would like to ask a question at that time, please press star one on your touch-tone phone. If at any point your question has been answered, you may remove yourself from the queue by pressing the pound key. If you should require operator assistance, please press star zero. We will ask that you please limit yourself to one question and one follow-up.
Additionally, we ask you pick up your handset to allow optimal sound quality. Please note that this conference is being recorded. It is now my pleasure to turn the floor over to Craig Biery, Director of Investor Relations. Craig, you may begin.
Thank you, Natalie. Good morning, everyone, 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. 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 first, 2017. Any time-sensitive information provided may no longer be accurate at the time of any webcast replay or rereading of the transcript. 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 plant 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. I'll turn the call over to Jim for an update on our operation.
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 hydrocracker in Woods Cross that is now complete. 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 lay-in cost in the MidCon was flat against WTI and under WTI by $2.20 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. Currently, we are seeing a move toward historical level as Canadian differentials in synthetic and WCS crudes are currently trading at +230 and -$13 respectively, well off their third quarter averages. Midland third quarter price differentials showed strength over the second quarter as the Brent-WTI spread provided the incentive to move barrels to the U.S. Gulf Coast for export.
In the future, we expect differentials, including the Brent-WTI, to be set by transportation and quality. Due to the effects of Hurricane Harvey, we expect to experience some relief on product inventory during the third quarter. Gasoline inventories in the Magellan system dropped by 1 million barrels to end the third quarter of 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 day supply, gasoline is at 17 days, and diesel is at 24 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 MidCon 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 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 a $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. HollyFrontier standalone CapEx for the quarter was $36 million. Due to the deferral of the Tulsa turnaround as well as other project timing, we expect to spend a total of $325 million to $350 million for both standalone 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 30th, our total cash and marketable securities balance stood at $631 million, representing a $170 million increase over our balance on June 30th. 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 30th, we have a $1 billion standalone 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 base III, II, I 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. With that, Natalie, we're ready to take questions.
The floor is now open for questions. At this time, if you have questions or comments, please press star one on your touchtone phone. We ask that you please limit to one question and one follow-up. If you have additional questions, we welcome you to rejoin the queue. If at any point your question has been answered, you may remove yourself from the queue by pressing the pound key. 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-WTI differential. It seems like you're one of the more favorably positioned companies for that, and I agree with you on the long term in terms of transportation and quality. I guess one of the questions here is, what is the right transportation number? We've heard about lighter barrels maybe leading to a little bit of a quality differential. Is it a $4 long-term differential we should think about? Something closer to three? Do you have any sort of detail to offer on that?
Roger, it's Tom Creery. As you know, we're not a big international player. 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. In the long term, we're probably expecting between $4 and $5. I think that's supported by the futures market at this point in time.
I would agree with that. I just didn't know if you could give us any 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-Con and as sourced through Cushing, we have not seen any appreciable quality changes.
Great. George, maybe a question for you on PCLI. Still offering guidance for the year of $100 million-$200 million. We're three quarters through the year. Surprised you're not tightening that up a little bit. I know that you're going to really want to focus on it at the Analyst Day, 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.
I think everything's 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. 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. We hope to rectify that going forward. 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. 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 from 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 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?
Well, Chi, I think we've talked about this a little bit in the past. This is a function of the absolute crack spread as well. As you know, a lot of the things that detract from capture rate are fixed in nature. At a lower margin, the fixed cost represents a higher percentage and thus a lower capture rate. Like in the third quarter with the higher margin, the fixed costs are a 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.
A little bit of that depends on what you're defining as higher gravity, too, right? 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. 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. Then maybe one final question. Rich, do you have an outlook yet for 2018 CapEx?
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 it that direction. We'll have a full formal budget for you December 7th.
Okay. Do you think the maintenance and environmental spending will be about similar as this year? Any outlook there?
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.
comes from the line of Doug Leggate at Bank of America. Your line is open.
Thanks. Good morning, everybody. I guess, George, could I go back to your Brent TI comment that you gave to Roger? I am just curious, $4-$5, obviously, I guess that would be sustainably above what most folks have got in their numbers right now. I am just curious what is giving you confidence that we are not still seeing some wash through from the hurricane impacts? Of course, TI is a higher quality grade. If you remove the transport bottlenecks, what leads you to think TI does not narrow that gap a little bit on its quality differential? I am just curious on your conviction on that. I have got a follow-up, please.
Yeah, I think there is some hurricane effect in the prompt market. It is over $6 right now. I think, like Tom said, transportation costs, if you figured $2-$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 is where we are coming up with, call it, $5 on transportation. From a quality perspective, Brent is a good barrel. It has got a lot of distillate in it. Obviously, the quality differential between Brent and TI depends on the gasoline diesel spread as well. Nominally in the past, I have 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. was not exporting 2 million barrels a day. That is really what I was getting at, I guess. Okay. My follow-up is really on the IDR exchange. Now you have done this. I am curious on the timing. Obviously, it has been coming for a while, I guess, for you guys. Now that you are 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 am just curious, do we need to wait in December for that? Have you got something in mind that is already on the books?
No, I think we are going to continue the same strategy we have had to grow HEP in the past. We have 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. To the extent that we can substitute the third-party service providers with HEP, we will continue to do that. I think you have seen that in some of the deals we have 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 have 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.
It's going to be very competitive, again, we've got a good position to leverage there. I think there's going to be some consolidation in the MLP space that we'd like to think there's some smaller MLPs that fit us, that we can acquire and bolt on to HEP. Nothing more specific than that, Doug, and we'll continue to work across all those dimensions.
All right. Appreciate the answers, George. Thank you.
Thank you.
Our next question comes from the line of Blake Fernandez from Scotia Howard Weil. Your line is open.
Guys, congrats on the results, although I'm cursing you under my breath for hosting a 7:30 A.M. call the day after the World Series.
We asked you if you're supposed to have this done by now.
Yeah, exactly. I just wanted to go back to the lubes business. Obviously, a pretty good quarter with $36 million of EBITDA. It seems to be a run rate right in the fairway of what we would think on a full year basis. Is there anything that drove that performance, whether it were hurricane, storm-related? I'm just trying to get a sense if this is a true underlying run rate or if there are any one-offs that drove that number.
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. I think that was somewhat storm affected. Group III compressed a little bit, which was sort of the flip of Pearl GTL coming back on. You put that all on balance, and we think this is a pretty reflective quarter.
If I'm not mistaken, Rich, there's a bit of a lag, too, right?
Yeah. Exactly. In the second quarter, we saw some compression in the, what I'll call the rack forward or from the refinery gate to the customer portion of the business. We got some of that back in the third quarter. Between the two, that's pretty ratable. 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 good things about this business at the end of the day is it does produce these ratable results because there's enough offsets within the business from quarter to quarter.
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. If you look at a lot of the regional differentials, whether it's Bakken, Permian, it doesn't seem like those discounts have been similar to what we've seen in the past. I guess what I'm just trying to understand is, as we 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. 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. 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. I think there's 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.
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. When you look forward over the next few years, as you look at the potential 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 ship owners are going to go to. We don't move fuel oil to the Gulf Coast on a regular basis. It's going to have very little, if any, impact upon us.
Yeah, I think, Ryan, this is George. In addition to what Tom said, we think it's going to widen out heavy crude diff. 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 to allow us to run about another 20,000 barrels a day of heavy crude. We're continuing to engineer that project, we haven't made a final investment decision. 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 FID it?
I think it'd 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. 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. 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. I wouldn't call anything out as being particularly noisy. We do typically see working capital build and fall with crude grade a little bit, too. Particularly as we're looking into the first quarter, we expect to see a working capital draw. There's nothing notable in here.
Okay, thanks.
Our next question comes to the line of Justin Jenkins from 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 am 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 run the LP and we're going to maximize crude basis on current prices. 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. 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. It will take a really narrow spread to substitute out heavy Canadian with additional light barrels until we fill that coker capacity. That heavy Canadian part of the slate is a fairly strong base load. We optimize the light crude portfolio after that.
Perfect. That's helpful. I guess shifting gears to maybe the regulatory front. 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?
Dang, Justin, I thought we were going to get through a call without RINs, man.
I know, right? I know.
Good for you for being
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 what we thought were very good proposals intended to fix high RIN price, a 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 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. We're going to continue to fight the fight on the political side. 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 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 wanted 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-100s, say 105,000 barrels a day and taken it up to the low teens. 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 at some refineries on the West Coast that have helped drive the margins up. CBOB prices in Phoenix have been especially strong as a result of that. That's what's been the major driver on the margin 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 the buybacks. 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 buybacks? Thoughts.
Yeah, 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. 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 it's to return it to shareholder.
All right. Thanks, guys.
Thanks, Neil.
Once again, if you have any questions, you may press star one on your touch-tone phone at this time. Our next question comes from the line of Phil Gresh from J.P. Morgan. Your line is open.
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?
Phil, the RINs cost was roughly $90 million in the third quarter. What I'd say is our expectation continues to be, we can't call the market. The ethanol RIN market is up substantially quarter to date versus the third quarter. Volumes being equal, we'd expect that number to be higher. Biodiesel RIN market has roughly traded even for most of the year.
Right. Got it. Okay. 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. 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. Looks like the majority of the exports now, from what we understand, are WTI lookalike crudes. In fact, they're around 45 degrees. That's what's going out of Corpus right now. 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. 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. Same basic questions. I'm not sure that U.S. exports are going to have any impact on WCS price. I think Canadian crude oil 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 and that impact to Hardisty.
Yeah, I think we expect that differential to widen. There's more production coming on in Canada in the fourth quarter. That's going to be favorable. 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. Again, further helping widen the differential between WCS and WTI.
To mirror George's comments, we're starting to see an 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. 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 lubes EBITDA as it is. 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. 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're going to 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. Again, I think we feel comfortable in that mid-100, 150-ish EBITDA range for PCLI.
Sure. That's before any of the synergy potential you talked about.
That's correct.
Yeah. Correct.
Okay. Thank you.
Your last question comes on 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 is still here, or whether for next year that you may be more exposed to the spot differential given that some people may indeed think that the WTI, WCS could widen quite meaningfully over the next couple of years?
Yeah, Paul, I think you have a tremendous memory for the history. We currently have no.
This is telling me that I'm old.
Well, we were just talking about that, yeah. For myself, so no, we have no fixed differentials on WCS. We're entirely a 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. Basically, think long term as far as being a spot participant in that differential.
Yeah, my suggestion is that don't lock it in. I think that you're better off that to just let it flow.
We're with you.
Yeah. 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, is maybe the more doable of a deal. Also, do you have a number what is the black wax and yellow wax you are running at Woods Cross, and how much is the syncrude you're running over there?
Okay, that's the 2A, 3 and B or something like that, huh? On M&A, Paul, we don't see a whole lot of activity out there. I think you've seen the same deals that's transacted that we've seen. There was one transaction that we would've 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 though we want to grow, we want to grow prudently and economically. We're still looking for deals. Again, there are not a lot of deals out there. When deals do pop up, we're going to exercise discipline.
As far as the question on black wax and yellow wax at Woods Cross, we're running about 20 a day, it's about two-thirds black, one-third yellow is growing faster than black in the field.
Are you seeing the production in black wax and yellow wax now is have turned around and start growing again?
Yeah, I'd say it's growing, not at a fast rate. 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.
Are you running any syncrude in Woods Cross?
Yeah, Paul. We're running limited amounts, between 2,000 and 5,000 barrels a day of synthetic crudes at Woods Cross at this point in time. A lot of that is price dependent.
Okay. Thank you.
Thanks, Paul.
Our next question comes from the line of Chi Chow of Tudor, Pickering, Holt & Co. Your line is open.
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?
Chi, this is Tom again. Currently, we've got a fair amount of line space both on Enbridge and on Keystone, the old Keystone. We feel that we have enough capacity to move crude to Cushing to support that project going forward. If we come up a little bit short, we expect that there's going to be a fairly robust market at Cushing itself. Transportation would not necessarily be the key driver on that decision.
Would you be looking at some sort of linked 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. No, that's all on the table, Chi, and again, like I mentioned earlier, we'll continue 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.
Okay. Thanks.
Chi, just to follow up on that as well. I'm sure that you're aware of Platts plans to tie into Spearhead in Nebraska, so that'll 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 Midcontinent refiners as well.
Great. That's helpful. Thanks, Tom.
Thanks, Chi.
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.