Welcome to HollyFrontier's Second Quarter 2018 Conference Call and Webcast. Hosting the call today from 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, Refining & Marketing. At this time, all participants have been placed in a listen-only mode and the floor will be opened 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 Biery, Director, Investor Relations. Craig, you may begin.

Thank you, Cathy. Good morning, everyone, and welcome to HollyFrontier Corporation's second quarter 2018 earnings call. I am 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'd 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 states 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 reconciliation 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 Damiris.

Thanks, Craig. Good morning, everyone. Today, we reported second quarter net income attributable to HFC shareholders of $345 million, or $1.94 per diluted share. Certain items detailed in our earnings release increased net income by $87 million on an after-tax basis. Excluding these items, net income for the current quarter was $259 million, or $1.45 per diluted share, versus adjusted net income of $116 million, or $0.66 per diluted share, for the same period last year. Adjusted EBITDA was $485 million, an increase of $179 million compared to the second quarter 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 million, driven by consistent Rack Forward sales volumes and margins. Rack Forward EBITDA was $52 million, representing a 12% EBITDA margin. Rack Back EBITDA was driven by weakness in the base oil markets and planned maintenance at our Mississauga Refinery. Rack Forward EBITDA is expected to be $190 million to $210 million 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 III base oils and our Rack Back and Rack Forward segments. Yesterday, we closed the previously announced acquisition of Red Giant Oil Company. Founded in 1903, 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 longstanding 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 million to $8 million in annual EBITDA and is part of our strategy to…

Thank you, George. For the second quarter, our crude throughput was 463,000 barrels per day, slightly above our guidance of 440,000 barrels per day 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 crude discounts. Our Navajo plant ran approximately 112,000 barrels per day in the second quarter. 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 was $4.41, slightly higher than the $4.18 in the second quarter of last year. The increase was driven by maintenance on our FCC at El Dorado that lasted 15 days. All 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 third quarter of 2018, we expect to run between 420,000 and 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 second quarter 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 $11.80 in the Rockies, $1.60 in the Mid-Con and $4.55 in the Southwest. In the second quarter of 2018, we continued to see healthy economies, 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 8.1 million barrels, roughly 1.5 million barrels lower than March 31 levels. Diesel inventories ended the quarter at 6.5 million barrels, which compared similarly to first quarter levels and approximately 0.5 million barrels lower than last year levels. Days supply of both gasoline and diesel in the group remain below five-year averages despite high refinery utilization. Second quarter 3-2-1 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 second quarter. In the Canadian heavy market, second 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 112,000 barrels per day at Navajo and 56,000 barrels per day by 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. Second quarter consolidated gross margin was $16.57 per produced barrel sold. This represented a 46% increase over the $11.36 recorded in the second quarter of last year. The increase was driven by improved laid-in crude cost in the Southwest and Rockies and small refinery exemption at our Woods Cross refinery. RINs expense for the quarter was $56 million, which is net of the $25 million 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 2018. And with that, I'll turn the call over to Rich.

Thank you, Tom. Our second quarter results included a few unusual items. Pre-tax earnings were positively impacted by $107 million lower of cost or market benefit, as well as the $25 million reduction in RINs costs resulting from the Woods Cross refinery's 2017 small refinery exemption. These positives were partially offset by $15 million 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 second quarter of 2018, cash flow provided by operations was $394 million, inclusive of turnaround spending of $20 million. HollyFrontier's standalone capital expenditures totaled $45 million for the quarter. As of June 30, our total cash and marketable securities balance stood at $980 million, a $198 million 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 second quarter, we returned a total of $87 million of cash to shareholders, comprised of a $0.33 per share regular dividend totaling $59 million as well as the repurchase of approximately 467,000 shares of common stock totaling $29 million. As of June 30, we had $123 million authorization remaining in our stock repurchase program. As of June 30, we have $1 billion of standalone debt outstanding and no drawings on our $1.35 billion credit facility, putting our liquidity at $2.3 billion and debt-to-capital at a modest 15%. HEP distributions received by HollyFrontier during the second quarter totaled $37 million, a 12% increase over the same period in 2017. HollyFrontier owns 59.6 million HEP limited partner units, representing 57% of HEP's float with the market value of $1.8 billion as of last night's close. For the full year of 2018, we reiterate our expectation for $380 million to $440 million of both standalone capital and turnaround cost at HollyFrontier Refining & Marketing, $70 million to $90 million at HollyFrontier Lubes & Specialties, including the scheduled turnaround at our Mississauga base oil plant in the fourth quarter, and we have increased our expectation for HEP's CapEx to $60 million to $70 million driven by new and potential projects in the Permian Basin. With that Cathy, we're ready to take questions.

Thank you. Our first question comes from Brad Heffern, RBC Capital Markets.

Hey, good morning, everyone.

Good morning, Brad.

Good morning, Brad.

George or maybe Rich, I guess can 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 billion of cash versus the $500 million target you've talked about in the past, and I think probably good visibility on generating more. So, any thoughts about how repurchases should trend over time.

Sure. I'll take a stab, then Rich will chime in. I think, Brad, we've been very open that we want to grow our company for the various reasons we've 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 contemplate transactions that benefit our company. To the extent we can, we will return excess cash to shareholders through share repurchases as we laid out in the capital allocation strategy.

Okay. And then, I guess, on the captures this quarter, that 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 you know anything special that happened in the second quarter or thoughts on the trajectory of those going forward?

Hey, Brad. It's Rich. So generally speaking, I think you 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.

I'll just chime in a little bit here too. Remember in the first quarter, we had our turnaround in Tulsa. So, we're liquidating inventories which 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 will use in the fourth quarter during the El Dorado turnaround and also kept us from making some higher value products like CBG in Phoenix in premium gasoline, so that offloads need to capture as well.

Okay. Got it. And then Rich, just a couple of accounting questions, so you guys called out the $15 million 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 is this negative OpEx number in Rack Forward this quarter, can you walk through what that is? Thanks.

Sure. So on Woods Cross, Brad, where this has flown through is in operating expenses. We're anticipating total repair costs of $30 million to $40 million. In the quarter, we expensed roughly $25 million and we went ahead in a crude portion of what we expect insurance recoveries will be roughly $10 million. So that accrual offset part of the spend and that flows through in Rockies' OpEx at the end of the day. 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 the portion of that as well, so that's the impact you're seeing there. Importantly, there is no EBITDA or net income, operating income affected the – it'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 Cheng with Barclays.

Hey, guys. Good morning.

Good morning, Paul.

George, I'm looking at the Southwest, I understand you have the FCC and planned outage, but the margin capture seems really low. Is there anything other than the FCC outage that you can say why the margin capture is so bad?

No, I think that's the majority of it, Paul. Again, I think, it goes – when you had 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 run back full?

No, I think that's a major issue again, Paul.

When you say 17 days is that, is all the impact is on that 17-day or the unit is down for 17 days, but the actual impact is larger than 17 days. That's what I'm trying to get at?

Yeah. Paul, this is Rich. I mean, so the units down for 17 days. To George's point, we had some associated units down which were impacting our ability to make the really high margin products, so 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 market like Phoenix, Paul, it's typically 10 days, so – but it is all tied to that specific event again at Navajo.

Have you guys had any internal rough estimate what was the opportunity cost loss relate to that incident?

Yeah. Paul, I don't think we're going to go there.

Okay. That's fine. And which that – you're saying that the total repair is going to be $30 million, $40 million, so we should assume that you have another $15 million you're going to expand in the third quarter?

Yeah, $10 million to $15 million, Paul, but yes.

And how about the insurance?

So, we'll make – we include roughly $10 million 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.

Yeah. So we really don't know that it probably may not be this year I would imagine by the time that you negotiate with the insurance company that to proceed the coming barriers next year, right?

We don't know that for sure. Paul, 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.

Right.

Payments have started. Just the exact timing for future payments is not something we can predict right now.

Right. And which – do you guys have business interruption insurance in a particular incident?

Yeah.

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, so far that what you booked is just on the property actual repair, you haven't booked any BI?

Correct.

Okay. And that, have you started 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. Very good. Thank you.

Thanks, Paul.

Your next question comes from the line of Matthew Blair with Tudor, Pickering, and Holt.

Hey. Good morning, everyone.

Morning, Matthew.

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 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 service 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 is being trucked and railed into the area. Currently, we think we have sound economics even if alternate supply is coming by pipeline from 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 in our product markets in the Artesia 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 two pretty distinct products?

No, I think directionally that will occur. But there are quality constraints to how much of that No. 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 that 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. Manav Gupta - Credit Suisse Securities (USA) LLC 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 oils, 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. Manav Gupta - Credit Suisse Securities (USA) LLC That's fair. The second part is, we are seeing big Cushing draws and Cushing inventories now about 60% below last year. And I'm trying to understand what's driving the dynamics at Cushing, well, 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 are actually seeing depletions at Cushing? That's something I'm failing to reconcile, if you could help me out.

Manav, this is Tom Creery. 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 first quarter of next year that Cushing is going to be full as additional crude comes on stream from Bakken, Niobrara, Saddlehorn and places like that. So we're sort of seeing 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. Manav Gupta - Credit Suisse Securities (USA) LLC Fair, guys. My last question, as you announced a couple of very exciting projects, one was the Delaware distillate 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 Orla 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. Manav Gupta - Credit Suisse Securities (USA) LLC Thank you so much, guys. Thank you for answering my questions.

Thank you, Manav.

Thank you, Manav.

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

Hey, good morning, guys.

Good morning, Neil.

Hi, Neil.

Hey, George, I want to follow up on your comments around M&A and I think you said there is 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 $0.5 billion range. Small deal takes almost as much time and effort as a bigger deal, but at the end of 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 expectation that some of these deals that we're seeing and working on will come to fruition, but again there is 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 in 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, Canada you said a 168,000 barrels a day, 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, we have Enbridge Line 3, we have a couple of competing factors that could move the differential?

Right.

Neil, it's Tom. Yeah, I think those are pretty representative run rates. Definitely, our goal is to get more Permian crude back into the Mid-Continent, into 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 done on the Enbridge system that you referred to. Like everyone else, we understand limitations on pipeline capacities coming. So 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 we look at those, it's probably 2021-2022, somewhere in there. So we expect differentials to hold at these levels. Going forward, that's the $20 to $25 number.

Okay.

I'll just chime in a little bit extra, Neil, here. So remember (35:14) in a day is what we're capable of doing at Artesia, the Permian crude. We have the pipeline capacity to (35:22) Cushing that primarily goes to El Dorado. We comfortably do 50,000 barrels a day in that pipe and can get above that, and as Tom says we're working to run it at a higher level sustainably into the future. And then on the WCS side, El Dorado is capable of running 50,000 barrels a day of WCS and Cheyenne 30,000 barrels a day to 35,000 barrels a day and we'll run it to the extent it's economical. If not, we're not afraid to sell the barrel in Cushing, it makes more sense to sell it there than 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 the 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 stocks, so you must think it's undervalued. So just talk about something to help us frame the way you think about the value of the company.

Go ahead.

Neil, the big mover there to, I think you've kind of highlighted right is in that Analyst Day evaluation right, we made a lot of assumptions around crack spreads, crude spreads. If we're 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 that time, we thought those assumptions were pretty conservative and certainly in today's market environment, they look very conservative. We do think the stock has room to go.

Yeah, the differentials, as Rich said, that we had in that Analyst Day presentation, we're nowhere near the $15 Permian depths we're seeing now and the $29 WCS depths we're seeing now and that we feel fairly confident we're 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, I mean, on what kind of Rack Backward EBITDA we should be expecting on a go forward basis, it's been pretty big headwind for the past few quarters and I know you mentioned the base oil...

Yeah, Phil, our expectation over the long term for Rack Back is, it's going to be plus or minus zero; it's not going to be a large contributor of 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 Rack Forward part of the business.

So specifically for the second half that you expected to get closer to neutral or other maintenance or other market headwinds that you think will continue to drive that.

Yeah, Phil, the base oil oversupply, it certainly looks like that it's going to persist for the balance of the year. And then to your point, we've got to turnaround in the fourth quarter on the CEW there (38:54) so that's also going to affect the numbers.

Okay. In the Southwest, I know people already asked about the capture. Just asking in 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&L?

No, I think on the crude side of the equation, we saw the benefits that we expected from the crude differentials of the market. Remember, it's a little bit lagged, but I think on the lag basis, we've got what we expected.

And for you guys, is the lag typically one month?

That's about right.

Okay. And then last one just on the Southwest, the operating costs were high, is that just the flow through effects of the FCC issues and things like that, I mean? Or if 1Q is pretty low, 2Q is pretty high, so how do you think of a real normalized run rate there on the OpEx?

Yeah. Phil, you're right, you've kind of hit on it. So we had some maintenance issues in the second quarter 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 million to $50 million 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&A question, but I just wanted to see if I get pushed a little bit on this. Do you have any line-up 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, well, you're in that more, should we just expect that you continue to carry an elevated level of cash or do you plan to reload the $123 million remaining buyback that you have in terms of authorization?

Yeah. Doug, I don't think we want to get any more specific on where we are with any deal flow. Just leave it, 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 keep extra (41:15) dry powder. When we see deal flow that we (41:19). But again, it takes a lot of things to line up as we all know to actually turn the 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?

Yeah, I think it's a fair statement (41:42) your question, we will reload the repurchase option when we need to would 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.

Yeah. I think over long haul, Doug, these differences are going to be set by transportation costs. So whatever the transportation cost is typically from the Permian to the Gulf Coast, $2 or $3.

$2 or $3 [multiple speaker] (42:37). And then the incremental pipeline capacity we're seeing is $4 to $5. So as they – to your point, Doug, look, these 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 – to 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, $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 way 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.

Yeah. Okay. All right, guys. Just wanted clarification there. Thanks.

Thanks, Doug.

Thank you.

Your next question comes from the line of Roger Read with Wells Fargo.

Yeah, good morning.

Hey, Roger.

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 just 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 $2 a barrel of kind of shipping costs?

I think that's right. I think the only other thing you need to add in there is you'd have to go across a dock, that'll cost another $1 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 PCLI, do you think we should see sort of – 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 and you've got a better feel for all the moving parts in it?

So, yeah, Roger, for the turnarounds, 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, $190 million, $200 million, $210 million 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 the Rack Back business to be breakeven, maybe a little bit positive on an EBITDA basis.

Okay. So no major updates here anyway.

Nothing really, Roger. Yeah.

Okay. Appreciate it. Thank you.

Thanks, Roger.

You do have a follow-up question from Paul Cheng with Barclays.

Guys, on El Dorado, the turnaround, you said mostly in the third quarter or the fourth quarter?

Mostly in the fourth quarter, it will start late third quarter.

And then I have some difficulty that reconcile why third quarter the throughput will be so low, that 420,000 to 430,000 [barrels per day] on the crude? You don't have any other turnaround as I believe, so why that it would be so low?

I think 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 third quarter. That's what you're seeing primarily in the crude rate guidance for the upcoming quarter.

You said El Dorado or are you talking about Navajo, the FCC?

I'm talking about El Dorado.

We had some other – so, Paul, we also had some other downstream unit problems elsewhere that kind of – those peaked in July and they were not just El Dorado and Navajo. So that's what you're really seeing in that crude guidance for the third quarter.

So that means that July, you actually run pretty – quite poorly in order for that to happen?

Yes.

For July. Yeah.

All right. And, George, I think at one point at least that you believed your current capacity is actually just slightly over 500,000 barrel per day in some sake nameplate that previously I think is lower. (47:54) And you think that you should be able to run on a rolling 12-month basis with how a major incident than say 450,000 to 470,000. Do you still believe given your experience now here that you actually would be able to achieve that?

Absolutely. That's our expectation.

You are far below that, right?

That's correct.

Yeah. And Paul, this is always going to be a tougher year given the turnaround at our two largest plants. So I think that color, the full and we're always going to color the full year run rate, but to George's point we fully expect that 450,000 to 470,000 through the cycle is a good number.

So what's higher benchmark or that from outside that we can track to see whether that you are on tie-up there to achieve that?

Well, I think, Paul, we can even look at the second quarter crude rate as an example. We ran into the 460,000s with Woods Cross plant being down, that's roughly 30,000 barrel per day crude unit. So we didn't have the Woods Cross incident, we'd be in the 490,000 plus. 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 could run this fleet at 450,000 to 470,000 as we guided during our Analyst Day presentation even including the impact of turnaround.

The final one I think Centennial that now you're using the capacity should be about 60,000 barrel per day, 65,000 barrel per day. So what's the hurdle we need to overcome in order for you to get to that 65,000 barrel 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. (50:25)

I'm sorry?

So you're saying that it's a trucking issue.

Part of it is a trucking issue. Yeah, the trucking issue and part of it's just a logistical issue of getting the barrels into Centurion and making sure that we can move them. As you'll recall in the first quarter when we had very much higher throughputs through the Centurion pipeline because of the Navajo situation. So it is possible that we have to make sure it's sustainable.

I see. Thank you.

Thanks, Paul.

Thanks, Paul.

You do you have a follow-up question from Phil Gresh with JPMorgan.

Yeah, 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 that kind of calibrate how we should think about that as we try to normalize our thinking for the back half?

Phil, so it's not -I don't have a great answer for you on this. But, historically, we run – if we run 100%, you can take crude rate and we were typically in three – 105%, 110% of sales of refined product at the end of the day. Over time we'd expect that to be representative, and clearly, we've had some noise up and down in the last couple of quarters we're managing around turnaround. So I think that probably is the single best mark, I can give you. Does that help?

Phil, one other thought specific to the half that you asked Phil 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 fourth quarter. So we will run that gas oil off during the fourth quarter turnaround at El Dorado.

So you're building it overall in the Mid-Con, you're building in the three quarter, and you'll be drawing in the fourth quarter kind of the reversal in the first half?

Yeah, we built it already. That's correct.

Yeah. Okay. Thanks a lot.

Thank you.

Thanks, Phil.

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 the call. If you have any follow-up questions, as always, reach out to Investor Relations. Otherwise, we look forward to sharing our third quarter results with (53:04).

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