Welcome to the HollyFrontier Second Quarter 2018 Conference Call and Webcast. Hosting your call today from HollyFrontier is George Damaris, President and Chief Executive Officer. He is joined by Rich Babaloha, Executive Vice President and Chief Financial Officer Jim Stump, Senior Vice President of Refinery Operations and Tom Creery, President, Refining and Marketing. At this time, all participants have been placed in a listen only mode and the floor will be open for your questions following the presentation. Please note that this conference is being recorded.
It is now my pleasure to turn the floor over to Craig Berry, Director, Investor Relations. Craig, you may begin.
Thank you, Kathy. Good morning, everyone, and welcome to HollyFrontier Corporation's Q2 2018 earnings call. I'm Craig Biery, Director of Investor Relations for HollyFrontier. This morning, we issued a press release announcing results for the quarter ending June 30, 2018. If you would like a copy of the press release, you may find 1 on our website at hollyfrontier.com.
Before we proceed prepared remarks, please note the Safe Harbor disclosure statement in today's press release. In summary, 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, August 2, 2018. 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 Samiras.
Thanks, Greg. Good morning, everyone. Today, we reported 2nd quarter net income attributable to HFC shareholders of $345,000,000 or $1.94 per diluted share. Certain items detailed in our earnings release increased net income by $87,000,000 on an after tax basis. Excluding these items, net income for the current quarter was $259,000,000 or $1.45 per diluted share versus adjusted net income of $116,000,000 or $0.66 per diluted share for the same period last year.
Adjusted EBITDA was $485,000,000 an increase of $179,000,000 compared to the Q2 of 2017. This increase in earnings was principally driven by our ability to capitalize on discounted crudes in our Refining segment. Our Lubricants and Specialty Products business reported EBITDA of $39,000,000 driven by consistent Rack Forward sales volumes and margins. Rack Forward EBITDA was $52,000,000 representing a 12% EBITDA margin. Rest back EBITDA was driven by weakness in the base oil markets and planned maintenance at our Mississauga refinery.
Rest forward EBITDA is expected to be to $210,000,000 this year with an EBITDA margin of 10% to 15% of sales. In the long run, we expect secular trends towards higher performance engines and lubricants will drive higher margins for Group 3 base oils and our Rack Back and Rack Forward segments. Yesterday, we closed the previously announced acquisition of Red Giant Oil Company. Founded in 190 3, Red Giant Oil is one of the largest suppliers of locomotive engine oil in North America. Red Giant Oil brings great value to HollyFrontier.
With its long standing brand recognition in the railroad lubricants industry and the opportunity for supply synergies with our existing base oil business. The acquisition is expected to generate approximately $7,000,000 to $8,000,000 in annual EBITDA and is part of our strategy grow the Rack Forward portion of our lubricants business. Holly Energy Partners reported EBITDA of $82,000,000 for the 2nd quarter compared to $75,000,000 in the Q2 of last year. This growth is driven by higher volume in HEP's crude gathering system as well as the acquisition of the Salt Lake City and Frontier Crude Oil Pipelines. We expect contractual tariff escalators and continued volume growth in our Permian crude oil system to improve to drive improvements in earnings in the second half of the year.
We remain committed to our capital allocation strategy of 1st, maintaining our current assets and balance sheet strength 2nd, sustaining a competitive dividend 3rd, growing our business both organically and through transactions and 4th, returning excess cash to shareholders through share repurchases. During the quarter, we repurchased $29,000,000 of HSP shares. HollyFrontier also today also announced today that its Board of Directors declared a regular dividend of $0.33 per share. The dividend will be paid on September 20 to shareholders of record of common stock on August 23. For the second half of the year, we expect the macro environment to remain very positive.
Food differentials have widened, especially in the Permian and WCS markets and we expect them to remain wide due to logistical constraints. Crude spreads have been healthy and are supported by strong demand and low to stable inventories, especially for diesel fuel, despite high industry utilization rates. High FAD II turnaround activity in the second half of the year should also further support both frac spreads and crude differentials. With IMO 2020 on horizon, we believe our business is well positioned to benefit from both crude differentials and crack spreads for the next few years. I'll now turn the call over to Jim for an update on our operations.
Thank you, George. For the Q2, our crude throughput was 460 3,000 barrels per day, slightly above our guidance of 440,000 to 450,000 barrels per day. Overall throughput and sales of refined products were impacted by outages in downstream conversion units, some of which extended into July. Our consolidated operating cost of $5.89 per throughput barrel was 10% higher versus the $5.35 per throughput barrel in the same period last year. The increase was primarily driven by costs associated with the Woods Cross outage that started this prior March.
The repairs on the crude unit are mechanically complete and we anticipate ramping production through August and reaching full run rates by September. Cheyenne had a strong operating quarter, averaging 48,000 barrels per day of crude throughput and was able to take advantage of the favorable WCS and 12,000 barrels per day in the Q2. OpEx per throughput barrel at $5.25 was elevated due to 12 days of unplanned maintenance on our cat cracker, our FCC. This plant is currently running at normal operating levels and continues to benefit from the widening crude discounts in the Permian Basin. In the Mid Con, our operating expense per throughput barrel is $4.41 slightly higher than $4.18 in the Q2 of last year.
The increase was driven by maintenance on our SEC at El Dorado that lasted 15 days. Our work is completed and our Mid Con refineries are operating at normal levels. Our El Dorado plant is scheduled to start its planned turnaround in late September and is expected to last approximately 45 days. For the Q3 of 2018, we expect to run between 420,000,430,000 barrels per day of crude oil. I will now turn the call over to Tom for an update on our commercial operations.
Thank you, Jim, and good morning, everyone. As Jim just mentioned, in the Q2 of 2018, we ran 463,000 barrels of crude oil composed of 29% sour and 20% WCS and black wax crude oils. Our laid in crude cost was under WTI by 11 point $8.0 in the Rockies, dollars 1.60 in the Mid Con and $4.55 in the Southwest. In the Q2 of 2018, we continued to see healthy economy both domestically and internationally, which will support the demand for refined products and help to maintain levels of exports. Gasoline inventories in the Magellan system ended the quarter at 8,100,000 barrels, roughly 1,500,000 barrels lower than March 31 levels.
Diesel inventories ended the quarter at 6,500,000 barrels, which compared similarly to Q1 levels and approximately 500,000 barrels lower than last year levels. Days supply of both gasoline and diesel in the group remained below 5 year averages despite high refinery utilization. 2nd quarter 321 cracks in the Mid Con were $18.15 $30.23 in the Southwest and $28.62 in the Rockies. Crude differentials remained wide across the heavy and sour slates in the 2nd quarter. In the Canadian heavy market, 2nd quarter differentials at Hardisty averaged over $19.25 a barrel.
Recently, however, we have seen this differential widen to more than $25 per barrel as pipeline capacity limitations continue. HFC continues to be able to purchase and deliver adequate volumes of price advantaged heavy crudes from Canada to meet our refinery needs as well as being able to sell incremental barrels into the marketplace when economics dictate. Canadian heavy and sour runs averaged 78,000 barrels per day at our plants in the Mid Con and Rockies regions. We refined approximately 168,000 barrels a day of Permian Crude in our refining system composed of 100 and 12,000 barrels per day at Navajo and 56,000 barrels per day via the Centurion pipeline at our El Dorado refinery. The Midland differential averaged the quarter at $5.15 and once again, we see that same differential trading today at over $16 per barrel.
2nd quarter consolidated gross margin was $16.57 per produced barrel sold. This represented a 46% increase over the $11.36 recorded in the Q2 of last year. The increase was driven by improved late in crude costs in the Southwest and Rockies and small refinery exemption at our Woodscott Refinery. RINs expense for the quarter was $56,000,000 which is net of the $25,000,000 cost reduction resulting from the Woods Cross small refinery exemption received in the quarter. Looking forward, with widening Permian differentials and consistent discounts for WCS and black wax crudes coupled with strong distillate demand, we anticipate continued strong margins across our refining system in the second half of twenty eighteen.
And with that, I'll turn the call over to Rich.
Thank you, Tom. Our second quarter results included a few unusual items. Pretax earnings were positively impacted by a $107,000,000 lower cost to market benefit as well as a $25,000,000 reduction in RINs costs resulting from the Woods Cross Refinery's 2017 small refinery exemption. These positives were partially offset by $15,000,000 in charges net of accrued insurance claims related to the outage at our Woods Cross Refinery. The table detailing these items can be found in our press release.
For the Q2 of 2018, cash flow provided by operations was $394,000,000 inclusive of turnaround spending of $20,000,000 HollyFrontier's standalone capital expenditures totaled $45,000,000 for the quarter. As of June 30, our total cash and marketable securities balance stood at $980,000,000 $198,000,000 increase over March 31. Working capital had a neutral impact on our cash position in the quarter with an increase in accounts payable offsetting inventory builds.
During the Q2, we returned a
total of $87,000,000 of cash to shareholders comprised of a $0.33 per share regular dividend totaling $59,000,000 as well as the repurchase of approximately 467,000 shares of common stock totaling $29,000,000 As of June 30, we had $123,000,000 authorization remaining in our stock repurchase program.
As of June 30, we
have $1,000,000,000 of standalone debt outstanding and no drawings on our $1,350,000,000 credit facility, putting our liquidity at $2,300,000,000 and debt to capital at a modest 15%. HEP distributions received by HollyFrontier during the 2nd quarter totaled $37,000,000 a 12% increase over the same period in 2017. HollyFrontier owns 59,600,000 HEP HEP Limited Partner Units, representing 57 percent of HEP's float with a market value of $1,800,000,000
as of last night's close. For the
full year 2018, we reiterate our expectation for $380,000,000 to $440,000,000 both standalone capital and turnaround costs at HollyFrontier Refining and Marketing, dollars 70,000,000 to $90,000,000 at Olive Material Lubes and Specialties, including the scheduled turnaround at our Mississauga base oil plant in the Q4. And we have increased our expectation for HEP's CapEx to $60,000,000 to $70,000,000 driven by new and potential projects in the Permian Basin.
With that, Kathy, we're ready to take questions.
The floor is now open for questions. Thank you. Our first question comes from Brad Heffern, RBC Capital Markets.
Hey, good morning, everyone.
George or maybe Rich, I guess, could you talk
a little bit about the repurchase program again? I mean, I know during this quarter, you would have known that you had the Red Giant acquisition close to the finish line. And so maybe that explains a relatively modest number given the cash build this quarter, but you are sitting at close to $1,000,000,000 of cash versus the $500,000,000 target you've talked about in the past, and I think probably gives us ability on generating more. So any thoughts about how repurchases should trend over time?
Sure. I'll take a step then, Rich can chime in. Thanks, Brad. We've been very open that we want to grow our company for the various reasons we shared previously. We're pleased with the deal flow we're seeing both for our refining and our lubricants businesses as evidenced by the Red Giant deal.
But as we all know, a lot of factors have to line up to convert deal flow into actual deals like Red Giant. To the extent we can, we'll consummate transactions that benefit our company. To the extent we can, we will return excess cash to shareholders through share repurchases as we laid out the capital allocation strategy.
Okay. And then I guess on the captures this quarter, they kind
of worked the opposite way
I would have expected. In the Mid Con, you guys had downtime last quarter, but it doesn't look like that was really reflected in a capture increase this quarter. And then in the Rockies, you obviously have had downtime for a couple of quarters, but the captures there have been much higher than they have been over the past couple of years. So any thoughts about anything special that happened
in the Q2 or
thoughts on
the trajectory of those going forward?
Hey, Brad, it's Rich. So generally speaking, I think we mentioned we had several issues in downstream conversion units. And so the effect that's having, right, is on capture at the end of the day. So you're seeing high crude rates, but you're not seeing it flow all the way through. We don't anticipate these are going to be perpetual issues.
So we view them as transitory, but they clearly hit kind of across the fleet this quarter.
Yes. I'll just chime in a little bit here too. Remember in the Q1, we had a turnaround in Tulsa. So we were liquidating inventory that we'd stored in advance of that. So in the second quarter, we're replenishing a little bit of inventory as well coming out of that Tulsa turnaround.
And as Rich said, some of these operating issues, we've built some intermediates, some of which we'll use in the Q4 during the El Dorado turnaround and also kept us from making some higher value products like CVG in Phoenix and premium gasoline. So that will flow through the capture as well.
Okay. Got it. And then Rich, just a couple of accounting questions. So you guys called out the $15,000,000 net charge related to the Woods Cross downtime. Can you walk through what exactly that is and how it flows through with the numbers where we would see it?
And then secondly, there's this negative OpEx number in Rack Forward this quarter. Can you walk through what that is? Thanks.
Sure. So on Wood Cross, Brad, where this is flowing through is
in operating expenses. We're anticipating total repair costs at $30,000,000 to $40,000,000 In the quarter, we expensed roughly $25,000,000 and we went ahead and accrued a portion of what we expect insurance recoveries will be roughly $10,000,000 So that accrual offsets part of the spend and that flows through in Rockies OpEx at the end of that. On the lubes question, what happened there was during the quarter we realized we needed to reclassify some expenses to make sure we were treating all expenses appropriately. So some OpEx moved into cost of goods sold and we had to recast a portion of that as well. So that's the impact you're seeing there.
Importantly, there is no EBITDA or net operating income effect at the end of the day. That's just a reclassification from one bucket of expense to the other, if you will. Largely that was around transportation cost and how we were treating that.
Okay. Thanks all.
Your next question comes from the line of Paul Chan with Barclays.
Hey, guys. Good morning.
Good morning, Paul.
George, I'm looking at the Southwest, I understand you have the FCC and plant outage, but the margin capture seems really low. Is there anything other than the FCC outage that you can cite why the margin capture is so bad?
No, I think that's the majority of it, Paul. Again, I think it goes when you have your cat down, you have your alky down. We need alkylate to make Phoenix CBG and that's where you're seeing most of the impact on capture rate, especially on the gasoline side obviously.
And doing is that
only the 17 day or that before that you're already having some issue of that unit? And how long it take after you come back there for you to went back full?
No, I think that's the major issue.
You're saying 17 days, that is that is all the impact is on that 17 day order. The unit is down for 17 days, but the actual impact is larger than 17 days. That's what I'm trying to get out.
Paul, this is Rich. I mean, so
the unit's down for 17 days. To George's point, we had some associated units down, which were impacting our ability to make the really high end margin product. So it obviously it affects you feel the effect over the course of that month primarily, but it's pretty substantial and it hit the quarter on average.
There might be some transportation time to get products then from the refinery to a market like Phoenix Ball. It's typically 10 days. So but it is all tied to that specific event again at Navajo.
Have you guys have any internal wealth estimate? What's the opportunity cost loss related to that incident?
Yes. But I don't think we're going to go there.
Okay. That's fine. And which that you're saying that the total repay is going to be $30,000,000 $40,000,000 So we should assume that you have another $15,000,000 you're going to expand in the Q3?
Yes.
Dollars 10 to $15,000,000 Paul, but yes.
And that how about the insurance?
So we'll make we include roughly $10,000,000 of claims. We're going to go ahead obviously and claim both property and business interruption. When timing of receipt of those is unclear to us. So we'll go ahead and follow that process.
Yes. So we really don't know that it probably may not be this year, I would imagine, by the time that you proceed that coming back is next year, right?
We don't know that for sure, but we've been working pretty closely with the insurance company. We think it won't be as protracted as maybe it typically is because of that relationship we have with them. But timing is always difficult to call. Payments have started. It's just exact timing for future payments is not something we can predict right now.
Right. And Rich, do you guys have business interruption in insurance in this particular incident? Are we going to see payment on that or that is still under the deductible?
No. We anticipate some recoveries under the BI policy.
Okay. So far that what you've booked here just on the property, actual repair, you haven't booked any BI? Correct. Okay. And that have you stopped the negotiation with the insurance company on the BI yet?
Absolutely.
Any kind of timeline that you may have in mind?
Not at this point, Paul, no.
Okay. Thank you.
Thanks, Paul.
Your next question comes from the line of Matthew Blair with Tudor, Pickering and Holt.
Hey, good morning, everyone. Good morning, Matthew. So Southwest product cracks have typically been some of the best in the U. S. We're now seeing a few projects though from various midstream companies to bring more gasoline and diesel into that market.
HEP is also engaged in some of those activities as well. How big of a threat is this to Navajo's margins? And what are you doing in response? Are you thinking about moving more product over to the Phoenix market?
No. I think we plan to take our fair share of what's going on in the Permian. That's why we've announced along with HEP the Orla truck rack project. Orla is about 80 miles south of Artesia. So we already serviced that market out of Artesia.
We're going to expand that to Orla and we're looking to expand that to other markets around both Artesia and Orla as far as away as even Midland. So the closer we can get our diesel to the end user and to the specific well that uses it, the better off we're going to be, especially with the shortage of truck drivers in the area. So there's a lot of product that's being trucked and railed into the area currently. We think we have sound economics even if alternate supply is coming by pipelines in the Gulf Coast. It's almost $0.10 a gallon to reach our market from the Gulf Coast.
That's a pretty good supporting structure for our margins and our product markets in Cartigena area.
Sounds good. And then it looks like you ran a 46% sour and heavy crude slate in the quarter, but you only produced a 1% fuel oil yield, which seems pretty ideal from an IMO 2020 standpoint. It looks like you also produced a 4% asphalt yield. How do you expect to see asphalt trade in an IMO market? Are you concerned that the fuel oil might drift into the asphalt market?
Or are those 2 pretty distinct products?
No, I think directionally that will occur. But there are quality constraints to how much of that number 6 fuel oil can get into the asphalt market. Making high quality asphalt is not as easy as it may sound. And actually, we think the market right now is short of high quality asphalt, which is what we make primarily from our refineries. And to the extent that the asphalt market is impacted by IMO 2020, we think that will be more than reflected in the crude price for the WCS and other similar crudes to contain a higher percentage of those heavy end of the barrel.
Great. Thank you.
Thanks, Matthew.
Your next question comes from Manav Gupta with Credit Suisse.
Hey, guys. You kind of mentioned a little bit about the weakness in the base oil market. I think BP also mentioned a few things about it. I'm just trying to understand what's causing this weakness in the base oil market, which is impacting your Rack Back margins? And how quickly can the market recover from it?
Hey, Manav, it's Rich. So basically, we're seeing solid demand for finished products and base oil is consistent with strong macroeconomics. What's happened here is there's just a lot of base oil supply floating around globally at the moment and it's compressing base oil cracks, if you will. We don't see a lot of supply additions coming. So we'd expect that market to strengthen in the next coming years.
That's fair. The second part is we are seeing big Cushing draws and Cushing inventory is now about 60% below last year. And I'm trying to understand what's driving the dynamics at Cushing, why are the draws happening? And the other part I'm struggling to reconcile is at the same time people are announcing new pipelines out of Cushing. So why is the Cushing outbound capacity being raised when you're actually seeing depletions at Cushing?
That's something I'm fitting to reconcile if you could help me out.
This is Tom Creagh. I'll take a shot at answering that. Yes, we are seeing big draws at Cushing. However, when you look at the forecast, people are still estimating by the Q1 of next year that Cushing is going to be full as additional crude comes on stream from Bakken, Niobara, Saddlehorn and places like that. So we're starting
to see a temporary
situation and it's also fueled by
the fact that the markets are in backwardation. So it's one of those chicken and egg things. You don't build inventories in a backwardated market. You tend to reduce it. So we've got a bunch of headwinds in trying to build inventories at Cushing at this point in time.
Sure guys. My last question is you announced a couple of very exciting projects. One was the Delaware Digital Project last quarter and then now you're looking at a new refined product pipeline out of the Permian Basin. If you could just give us some color on those two projects?
No, I think again it's all those projects are targeted towards the growing demand for distillate in the Permian. A lot of that incremental source of supply right now is coming in by rail and by truck, primarily from the Gulf Coast. We think we're well positioned, as I mentioned earlier, with our Ortle project, which is connected by pipeline to Artesia, 80 miles south of Artesia. So we get into the southern ends of the Delaware Basin. We're looking at other opportunities out of both Orla and Artesia to supply the Delaware Basin and then looking at options to get from both Artesia and Orla into the eastern part of the Permian Basin.
Thank you so much guys. Thank you for answering my questions.
Thank you, Tom. Thank you, Tom.
Your next question comes from the line of Neil Mehta with Goldman Sachs.
Hey, good morning guys. Good morning, Neil. And George, I want to follow-up on your comments around M and A. And I think you said there's a rich pipeline of potential opportunities that are out there and that ultimately you do want to grow the business and the capacity across business lines. Just can you talk about the scale of those opportunities?
When we look at something like Red Giant, that's very different than something like PCLI. And so are we talking about smaller bolt on transactions, things that could be more transformative to the business? Just help us frame the way you're thinking about capital allocation.
I think we're seeing deals along the entire spectrum of size. Our preference would be to do larger deals, I think in the $500,000,000 range.
A small deal takes almost
as much time and effort as a bigger deal. But at the end of the day, it all comes down to how attractive we feel the opportunity is. We're seeing a lot of deals, as I mentioned in my previous response. So we're keeping a little more dry powder in reserve in the expectation that some of these deals that we're seeing and working on will come to fruition. But again, there's no guarantees that they will.
And if they do, again, we'll use the cash on the deal. If they don't hit, we'll return it to shareholders.
And those are more lubes and midstream more so than refining, George?
No. We're also seeing opportunities in our refining segment as well, Neil.
Okay. And then you ran 78,000 barrels a day at Canada, you said 168,000 barrels a day at Midland. Is that a reasonable run rate to think about going forward, especially on the Canada side? And then how you think about these Western Canadian differentials? They're certainly very healthy right now, but how do you see it playing out between now and the next couple of years considering we have IMO 2020, you have Enbridge Line 3, you have a couple of competing factors that could move the differential?
It's Tom. Yes, I think those
are pretty representative run rates. Definitely, our goal is to get more Permian crude back into the Mid Continent and to our refineries there and take advantage of those differentials in the short term and we're trying to do looking at several ways as well. But the Canadian, that's fairly consistent based on the premise that apportionment does on the Enbridge system that you referred to. Like everyone else, we understand limitations on the pipeline capacity is coming south. We expect some relief on that apportionment number when the Sturgeon refinery comes on, but after that, you're correct in saying that the next tranche is Tier 3 on Enbridge and then we're waiting for the big changes to come as a result of both XL and Trans Mountain.
So and when you look at those, it's probably 2021, 2022 somewhere in there. So we expect differentials to hold at these levels going forward, the $20 to $25 number.
I'll just chime in a little bit extra, Neil here. So remember, dollars 100 and 15 a day is what we're capable of doing at Artesia, the Permian crude. We have the pipeline capacity to Cushing that primarily goes to El Dorado. We comfortably do 50,000 barrels a day in that pipe and can't get above that. And as Tom says, we're working to run it at a higher level sustainably in the future.
And then on the WCS side, DORADO is capable of running 50 a day of WCS and Cheyenne 30 to 35. And we'll run it to the extent it's economical. If not, we're not afraid to sell the barrel in Cushing if it makes more sense to sell it there and then to run it at El Dorado.
One last question, if I could sneak one more in. At the Analyst Day a year ago, you guys came out with a view that the stock was worth $60 but a lot of things have changed since then. So I wanted to get your updated thoughts, maybe not a point number, but as we think about that representative valuation versus the market factors right now, you guys are making the decision to buy back at least some stock. So you must think it's undervalued. So just talk about some of the deltas to help us frame the way
you think about the value of the company.
Yes. The big number there, I think you kind of highlighted it right is in that Analyst Day valuation, right, we made a lot of assumptions around crack spreads, crude spreads. If we were wrong by a couple of bucks to the downside, it's worth a lot of money to the stock at the end of the day. And as we told you at the time, we thought those assumptions were pretty conservative and certainly in today's market environment, they look very conservative. And we do think the stock has room to go.
Yes. The differential, as Rich said, that we had in that Analyst Day presentation, we're nowhere near the $15 Permian debts we're seeing now and the $29 WCS debts we're seeing now and that we feel fairly confident are going to extend through next year, if not further.
Makes sense, guys. Thank you very much.
Your next question comes from the line of Phil Gresh with JPMorgan.
Yes. Hi, good morning. A couple of quick ones here. First, just on the lubes, you talked about Rack Forward versus Rack Back. Do you have a view on what kind of Rack rack backward EBITDA we should be expecting on
a go forward basis?
It's been a pretty big headwind for the past two quarters. And I know you mentioned the base oil.
Our expectation yes, Phil, our expectation over the long term for Rack Back is it's going to be plus or minus 0. It's not going to be a large contributor to our profit. It is weaker currently than we expect for the reasons that Rich laid out earlier. But again, we think it's important to be vertically integrated. It minimizes transportation costs, takes out some of the volatility.
But our focus is on growing the wrap forward part of the business.
So specifically for the second half, would you expect it to get closer to neutral or are there maintenance or other market headwinds that you think will continue to
do that?
Yes. Phil, the base oil oversupply is certainly the only thing
that's going to persist for
the balance of the year. And then to your point, we've got a turnaround in Q4 on the CDW there, so that's also going to affect the numbers.
Okay.
In the Southwest, I know people have already asked about the capture. Just ask it a slightly different way. Would you say that you got the full benefit of the quarter over quarter improvement in the Permian differentials? Or are there also any timing factors that influence the way that it hits your P and L?
No, I think on the crude side of the equation, we saw the benefits that we expected from the crude differentials in the market. Remember, it's a little bit lagged, but I think on the lag basis, we got what we expected.
And for you guys, it's a lag typically 1 month?
That's about right.
Okay. And then last one just on the side, as the operating costs were high, is that just the flow through effects of the FCC issues and things like that? I mean or 1Q is pretty low, 2Q is pretty high. So
how do we think of
a real normalized run rate there on the OpEx?
Phil, you're right. You kind of hit on it. So we had some maintenance issues in the Q2, obviously, that ran through OpEx. First quarter was a little bit low. So we kind of think basically the middle is the run rate.
So call it roughly $45,000,000 to $50,000,000 a quarter.
Okay, got it. Thank you.
Your next question comes from Doug Leggate with Bank of America Merrill Lynch.
Thanks. Good morning, guys. Thanks for taking my questions. George, I guess, I'm sorry to go back to the M and A question, but I just wanted to see if I could push a little bit on this. Do you have any line of sight right now on the possibility of getting something done in the kind of scale that you talked about?
Or is it more aspirational? And I guess while you're in that mode, should we just expect that you continue to carry an elevated level of cash? Or do you plan to reload the $123,000,000 remaining buyback that you have in terms of authorization?
Yes. Doug, I don't think we want to get any more specific on where we are with any deal flow. Just leave it where what we said is that we're seeing good deal flow and so we're pleased with quality and the quantity of the deals we're seeing. Again, we're going to carry extra dry powder when we see deal flow that we but again it takes a lot of things to line up as we all know to actually turn a deal flow into actual deals And that's what we can't predict and we won't predict.
Just to be clear, the elevated level of cash, should we expect that to continue until things play out one way or the other?
Yes. I think it's a fair statement, Doug. To your question, we will reload the repurchase authorization when we need to be how we'd approach
that. Okay, thanks. My follow-up is really more of a macro question. Look, obviously, there's a lot of debate over. No question differentials are very wide right now.
But at the end of the day, we're looking through the cycle. And my question, I guess, Rich, is back to you on your comments about TI Brent. There's a ton of pipelines coming on. And a year ago, Midland traded at a premium to WTI. So when you look beyond the windfall of the next year, what do you see the mid cycle Midland differential look like?
I'll leave it there. Thanks.
Yes. I think over the long haul, these debt pressures are going to be set by transportation costs. So whatever the transportation cost is, typically from the Permian to the Gulf Coast, dollars 2 or $3 dollars 2
or $3 prime firm. And then the incremental pipeline capacity we're seeing is 4 to 5. So as they to your point, those are going to be very volatile and we'd expect that to continue. Pipes come on, you end up with more takeaway than you've got production. You're going to see it compress and we have the opposite situation at the moment.
But to George's point, over the long haul, you'd expect it to go to the transportation economics. So just
to be clear, I know you and I have talked about this, Rich, but the contract rates look like they're coming in at 2.50, dollars to $2.75 from Midland to MEH. And obviously, that's cheaper than the Cushing to MEH. So when you think about the $4 sustainable spread embedded in your what Neil was talking about earlier, we're not going to assume $15 forever. Are we going to assume less than $4 at some point for a period of time or not?
I mean, you could have a period of time, that's why for sure. But again, over the long run, yes, you're seeing contract rates at $2.50 but walk up rates, which are ultimately going to set the economics are still $4 to 5.
Dollars Yes. Okay. All right, guys. Just want a clarification there. Thanks, Lois.
Thank you.
Your next question comes from the line of Roger Read with Wells Fargo.
Maybe to follow-up on Doug's last question there. If you think about longer term on WTI Brent, I mean most of these barrels are going to have to be exported outside of the U. S. In other words, it's not a Gulf Coast clearing price in the traditional sense. When you kind of factor that in, what do you kind of look at as maybe the longer term that $4 to $5 walk up plus another, I would think, dollars 2 a barrel of kind of shipping costs?
Well, I think that's right. I think
the only other thing you need to
add in there is you're going to have to go across the dock. That will cost another buck or 2.
Okay. Right. Okay. Thanks on that. And then changing back and I'm sorry
I missed part of the call earlier,
but looking at PCLI, I caught the comments about the base oil market being oversupplied, a little bit of turnaround activity. When as you look at TCLI, do you think we should see sort of a, I don't know if
I want to call
it a clean run rate, but maybe a consistent run rate where there aren't too many turnarounds going on, there's not too much noise maybe in the numbers? And then what do you look at as the kind of the earnings or EBITDA power of this business now that you've run it for a little over a year, then you've got a better feel for
all the moving parts there? So yes, Roger, the I mean, with it for the turnaround, we'll we have a clean run-in 2019 on the base oil plant. We gave guidance at the Analyst Day and we believe that guidance is still pretty good. You're talking about on the Rack Forward side, excuse me, dollars 100 and $90,000,000 $200,000,000 $210,000,000 type business and we still think we've got room to grow. Obviously, Red Giant will be additive to that.
And as George mentioned, over the long run, we're expecting our Rack Back business to be breakeven, maybe a little bit positive on an EBITDA basis.
Okay. So no major updates there anyway?
Nothing really about it. Okay. Appreciate it. Thank you. Ready
yet. You do have a follow-up question from Paul Chan with Barclays.
On El Dorado, the turnaround, is it mostly in the Q3 or the Q4?
Mostly in the Q4. It will start late Q3.
And then I have some difficulty that you reconcile why Q3, the throughput will be so low that $420,000,000 to $430,000,000 on the crew. Do you have you don't have any other turnaround as I believe. So why that it will be so low?
I think it was it's part of what Jim was getting at in his prepared remarks, Paul, we had the El Dorado incident, FCC outage in the second quarter and it did spill over into the 3rd quarter. That's what you're seeing primarily in the crude rate guidance for the upcoming quarter.
Is that El Dorado or are you talking about Navitas, the FCC?
I'm talking about El Dorado.
We had some other
to be so
Paul, we also had some other downstream unit problems elsewhere that kind of those peaked in July and we're not just El Dorado Navajo. So that's what you're really seeing in that current guidance for the Q3.
So that means that July, you actually went pretty quite poorly in order for that to happen?
Yes. For July.
All right. And George, I think at one point at least that you believe your current capacity is actually as slightly over 500,000 barrels per day in South say, the NIMP that previously I think is lower. And you think that you should be able to run on a rolling trauma basis without a major incident, say 450 to 470. Do you still believe given your experience now here, that you actually would be able to achieve that?
Absolutely. That's our expectation.
You're far below that, right?
That's correct. Yes. And Paul, this is always going to be a tougher year given the turnaround that our 2 largest plants. So I think that's that colored the full and Will was always going to color the full year run rate. But to George's point, we fully expect that 450 to 470 through the cycle is a good number.
So what kind of benchmark or that from outside that we can track to see whether that you are on path to achieve that?
Well, I think, Paul, we can even look at the 2nd quarter crude rate as an example. We ran into the 460s with the Woods Cross plant being down. That's roughly a 30,000 barrel per day crude unit. So if we didn't have the Woods Cross incident, we'd be in the $490,000,000 plus. Again, we did have the issues with these downstream units that again Jim highlighted in his prepared remarks.
We need to get those issues addressed and under control. But with all that falling in place, we still again are very confident we can run this fleet at 450 to 470 as we guided during our Analyst Day presentation even including the impact of the turnarounds.
Final one, I think Centennial that the mine you're using, the capacity should be about 60,000, 65,000 barrels per day. So what's the hurdle we need to overcome in order for you to get to that 65,000 barrels per day rate?
There's no real hurdle, Paul. It's beyond our contract volume that we do have with Centurion. So and part of the issue that we have is getting trucks underneath crude oil in the Permian Basin. As you can well imagine, there's been a shortage of trucks. So it all flows back to the wellhead and getting that back into the system and then making sure that we can, as George mentioned before, sustainably move volume through that pipeline.
And you recall that
in the Q1 we
I'm sorry?
So you're saying that it's a trucking issue?
Part of it's a trucking issue.
Yes, a trucking issue and part of it's just a logistical issue of getting the barrels into Centurink and making sure that we can move them. As you'll recall in the Q1 when we had very much higher throughputs through the Centurion pipeline because of the Navajo situation.
So it is possible,
but we have to make sure it's sustainable.
Okay. Thank you.
Thanks, Paul.
You do have a follow-up question from Phil Gresh with JPMorgan.
Yes, thanks. Just one last question on these inventory factors in the Mid Con that appeared to help the 1Q results and then hurt the 2Q results. Any way to kind of calibrate how we should think about that as we try to normalize
our thinking for the back half?
Bill, I'll say not I don't have a great answer for you on this. Historically, we run if we run 100 you can take crude rate and we're typically 3%, 105%, 110% of sales of refined product at the end of the day. Over time, we'd expect to have to be representative and clearly we've had some noise up and down in the last couple of quarters as we're managing our turnaround. I think that's probably the single best marker I can give you if that helps.
One other thought specific to the math that you asked Bill is we did build gas oil toward El Dorado as a result of the FCC outage, but also in anticipation of the crude unit outage we're going to have at El Dorado in the Q4. So we will run that gas oil off during the Q4 turnaround at El Dorado.
So you're building overall in the mid kind of building in 3rd quarter and you will be drawing in the Q4 kind of a reverse of the first half?
Yes. We've built it already. That's correct.
Yes. Okay. Thanks a lot.
Thank you. Thanks, Paul.
At this time, there are no further questions. I will now turn the floor back over to Craig Biery for any closing remarks.
Thank you, everyone. We appreciate you taking the time to join us on the call. If you have any follow-up questions, as always, reach out to Investor Relations. Otherwise, we look forward
to sharing our Q3 results with
Thank you. This does conclude today's teleconference. You may now disconnect your lines at this time and have a wonderful day.