Welcome to HollyFrontier Corporation's First Quarter 2016 Conference Call and Webcast. Hosting the call today from HollyFrontier is George Damiris, President and Chief Executive Officer. He is joined by Doug Aron, Executive Vice President and Chief Financial Officer. 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 Julia Heidenreich, Vice President, Investor Relations. Julia, you may begin.

Thank you, Jennifer. Good morning, everyone. Welcome to HollyFrontier Corporation's first quarter 2016 earnings call. I'm Julia Heidenreich, Vice President of Investor Relations. This morning, we issued a press release announcing results for the quarter ending March 31, 2016. If you would like a copy of today's release, you may find one on our website, hollyfrontier.com. Before George and Doug proceed with their 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 securities 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. Also, today's call might include some discussion of non-GAAP financial measures. Please see the press release for reconciliations to GAAP. Lastly, please note that information presented on today's call speaks only as of today, May 4, 2016. 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, Julia. Good morning. Thank you for joining us on HollyFrontier's first quarter earnings call. Today, we reported a first quarter net income attributable to HFC shareholders of $21 million or $0.12 per diluted share. Excluding the $56 million non-cash pre-tax inventory valuation adjustment, net loss attributable to HFC shareholders was $16 million, or $0.09 per diluted share. First quarter EBITDA excluding the inventory valuation charge was $96 million, 78% below the comparable quarter last year. This percentage decrease was due primarily to lower refining margins and costs associated with blending ethanol and purchasing RINs to comply with the RFS mandate. First quarter crude throughput was 391,000 barrels per day, slightly above our guidance of 380,000 to 390,000 barrels per day. We completed a 50-day FCC alky turnaround and modernization project at Tulsa during the quarter, impacting crude rate. We ran 27% sour and 19% WCS and black wax crude. Our average laid-in crude cost under WTI was $1.54 in the Mid-Con, $4.16 in the Rockies and $1.43 in the Southwest. For the second quarter of 2016, we expect to run 420,000 to 430,000 barrels per day of crude. We currently have a 50-day FCC alky turnaround and modernization project underway at Cheyenne, resulting in reduced rates. In the fourth quarter, we have a planned FCC alky turnaround at Woods Cross. First quarter consolidated refinery gross margin was $7.59 per produced barrel, less than half of the $16.69 recorded in the first quarter of 2015. Margins were impacted by seasonally weak gasoline cracks, and continued weakness in diesel cracks. During the quarter, costs associated with blending ethanol and purchasing RINs to comply with the RFS mandate had a significant impact as a proportion of earnings. Ethanol, which priced at more than $0.30 per gallon premium to Mid-Con gasoline benchmark in…

Thank you, George. For the first quarter of 2016 cash flow provided by operations totaled $6.6 million. Turnaround spending in the first quarter totaled $37 million and first quarter HollyFrontier stand-alone capital expenditures was $132 million. In 2016 we continue to expect to expend approximately $600 million in stand-alone CapEx and turnaround spending. As of March 31, 2016, our total cash and marketable securities balance stood at $111 million, a $100 million reduction from year end levels. Cash outflows in the quarter included $192 million in dividends and share repurchases and, again, $132 million in capital expenditures. During the first quarter, we repurchased 3.7 million shares at an average price of $34.86. We have $179 million remaining under our existing share repurchase authorization. It remains our expectation that we will continue to return excess cash flow to shareholders with the pace and volume dependent on free cash flow generation and the timing and ability to drop down assets to HEP for cash. Two key components of our business improvement plan, as George previously mentioned, were balance sheet optimization and MLP value growth. During the first quarter, we opportunistically issued $250 million of 5.875% senior notes that mature in April 2026. And last week, we closed on a three year unsecured term loan in the amount of $350 million where we were able to secure a more attractive rate of 200 basis points over LIBOR. We intend to use the net proceeds from the debt offering and term loan for general corporate purposes including capital expenditures. HEP is gaining momentum and achieving their 8% distribution growth target. In the first quarter, HEP and HFC completed a non-cash transaction for an interest in the Osage Pipeline, and HEP completed the purchase of the Tulsa tankage which resulted in an $8.7 million charge and the early extinguishment of debt associated with our financing obligation. HEP units have performed strongly, up 6% year-to-date versus the AMZ which is down around 1%. As a reminder, HollyFrontier owns 39% of Holly Energy Partners which is 22.4 million common units plus the 2% general partner interest. The current market value of our LP units is approximately $740 million as of last night's closing price and our first quarter general partner incentive distributions were $12.4 million, a 22% increase over the same quarter last year. Lastly, I will remind you that you can find our monthly WTI-based 321 indicators for our Mid-Con, Rockies and Southwest regions posted on the HollyFrontier Investor page. These indicators do not reflect actual sales data and are meant to show monthly trends, realized gross margin per barrel may differ from the indicators for a variety of reasons, you can find this data at our investor page at hollyfrontier.com. And now, Jennifer, I think we're ready to open the floor to questions.

Thank you. Our first question is coming from Brad Heffern with RBC.

Doug, on the debt deal and the term loan, I was wondering if you could talk about what the thinking was behind doing the term loan and how you're thinking about the repurchase program at this point versus how it was laid out in the Analyst Day guidance?

Sure, Brad. We had really targeted all along to try and raise about $500 million in debt in 2016. The public markets, at the time we came, crude was weakening again and we thought we had seen a window after there were some other issuers earlier that week and it turned out for a variety of reasons that that market was maybe a little softer than we anticipated and we were only able to get sort of half of that $500 million target done. So when we compared that with what the banks believe they could get done for us, while we waited for a little bit of a recovery in that investment grade market, we saw sort of the blend of some floating-rate debt as well as some fixed-rate debt as the best option available for our shareholders. And that's what we executed on. At some point that term loan, we will expect to take out over the next 18 to 24 months despite it being a three-year term loan. And now we have a benchmark piece of paper out there that the public markets can point to and say it's out there, it's trading well. Those bonds are now trading over par. So that was sort of the rationale on that. And as to Analyst Day share buyback laid out versus sort of where we are today. Obviously, we are a little behind the pace, maybe even a lot behind the pace, but I think the margin environment is also very different than what we had anticipated when we sat with you guys last September. So that said, again, we still feel pretty confidently that Woods Cross drop down is something that will happen in 2016 to HEP and it will happen for cash. We've seen a significant improvement in the MLP market and the ability to get units out of the door, which would allow a cash transaction there. So assuming that happens, I think between that and debt raises, there is a possibility of us ramping that buyback program back to the pace that you were expecting. Again, I don't remember exactly, I think we had maybe up to $1 billion this year, which feels like certainly a stretch goal at this point just given cash flow generation in the first quarter being well behind what we would have anticipated there. But at the end of the day, Brad, the message is, we are committed to returning capital to shareholders. That's obviously dependent on availability of that capital but our commitment hasn't changed.

Okay. That's great color. Thanks for that. And then maybe for George, I was wondering if you could delve into the performance of the Rockies during the first quarter. Capture versus the index was the lowest it's been for a couple years. It didn't seem like your laid-in crude cost changed real substantially quarter-over-quarter. So was it local market pricing related or was it again ethanol and RINs, any color there would be helpful?

No. I think the RINs and ethanol as we discussed in general also applied, especially in the Rockies. So, I think that's the biggest explanation for it, Brad.

The crude price was also a factor. I mean we had WCS advantage there, but I think we had been running closer to $8 to $10 discounts in the Rockies that now was starting to look more like $5, Brad. So, the crude diffs weren't as strong in the first quarter as they had been in previous.

Yeah. Understood. I was just thinking about versus the fourth quarter, I think that the discount was pretty similar. So, I was wondering what sort of the sequential decline was, but it sounds like maybe it's just the ethanol and RINs explain most of it?

Yeah. Ethanol this quarter was a big deal as you can imagine with the lower crude price in the quarter. Ethanol obviously isn't as tied to crude costs as gasoline. So, ethanol traded at a significant premium to gasoline and thus the negative ethanol blending margin. So that was the biggest quarter-to-quarter sequential difference.

Okay. And just one quick one if I could verify something. Once Woods Cross expansion is online, that IDR giveback that you guys did a couple years ago, the $1.25 million a quarter, that will come back into the cash flow stream, is that right?

That's correct.

Okay. Thanks.

Your next question comes from Paul Sankey with Wolfe Research.

Hello everyone. Could you just continue little bit on ethanol, a lot of people are worried about RINs being short next year. Do you guys – is that a concern for you guys and if you were to go back into a more acquisitive mode at HollyFrontier, would you be looking to add marketing or would it be more in the refining side? Thanks.

The simple answer is, yes, RINs are a concern. I think that when the latest RVOs were set, they were set a little bit higher than originally anticipated. And I think that was by design. The EPA's intending to hit if not exceed the blend wall. But also their desire is to dry up the pool of RINs that are available for refiners to carry over from year-to-year. So, all of that is intended to drive ethanol use higher than the blend wall. I don't know if that is a realistic expectation from the EPA. I would be inclined personally to say it's not. Also they're trying to motivate the use of other renewables as well, including biodiesel which, as you probably know, biodiesel RINs can be applied towards your ethanol RIN obligation. As far as on the acquisition front, Paul, I think we're interested in acquisitions. I'm not sure how – it's not a top priority for us versus our business improvement plan. So, we'll continue to stay focused on that. We would be primarily interested in refining assets and if those refining assets come with some retail or marketing subsidiary or division, we would be interested in that, but again it wouldn't be our primary requirement.

Understood. So basically – go ahead, sorry.

Sorry, Paul. What I would say is, owning a marketing division or retail doesn't fix the fundamental problem of RINs and ethanol blending here. I mean, if ethanol blending isn't economic, like it wasn't in the first quarter, whether you own retail or not it's still garbage. And I'm sorry for this being a soapbox but it's the most absurd legislation that it will, as you point out, if we get to a shortage again, I think as we saw in 2013 or 2014, my memory is a little unclear. Congress, if this gets too far out of whack, is willing to act. They won't let this get to a point where there's just not enough RINs and you start paying absurd prices. So, I think we take a little bit of comfort in knowing that there's some practical limit before it gets to absurdity. And we're continuing to work hard in Washington to see what can be done. Our first choice would be a full repeal of the RFS. That's maybe beyond optimistic but there are other things that we are working on both as a company and individually as well as an industry through AFPM to do something about just this absurd rulemaking.

Yeah. I mean, for the record, we think it's totally stupid as well. I just was trying to gauge the extent to which you felt it was a threat to your business and appreciate your answers. Thank you.

Thanks, Paul.

Your next question comes from Doug Leggate with Merrill Lynch.

Thanks. Good morning, everybody. George, obviously a lot of moving parts in the quarter. You're signaling a fairly nice rebound in utilization, but can you give us some idea what you think the lost opportunity cost was in the first quarter, as a result of construction downtime and the other disruptions that you might have had in the quarter?

I think our LPO for the quarter was low. Doug, I think our plants ran fairly well with the possible exception of Cheyenne. We had some issues around the cat cracker just prior to the turnaround. But I think I'd quantify the LPO at around $20 million for the quarter.

Got it. Did you have any – just as a follow-up to that, did you have any deliberate run cuts besides the planned maintenance, George, or as a result – economic run cuts, if you like?

Yeah, we had some nominal run cuts in the middle of February for about a week or so. Cracks went negative in the Mid-Con so we cut about 5,000 barrels per day for about a week.

Thank you. My second question, if I may, is, and I'm afraid it's also on ethanol and RINs. I'm just wondering what – we realize that obviously it's still going to be a challenge until they figure things out, but what was the trend so far in the second quarter because obviously that was a fairly sizable hit in Q1?

The trend again is getting better on the ethanol blending because again crude prices in the first quarter were low and ethanol again does not move in sync totally with crude price. So as crude price is recovering and as gasoline crack recovers, gasoline price is pushed up by both the crude price and the gas crack, the ethanol blending margin improves. So, I think it's still slightly negative but not negative to tune of the $0.30 per gallon that we saw in the first quarter.

Great. Thank you. A lot of folks might have overlooked that. Thanks a lot, George.

Thank you, Doug.

Your next question comes from Chi Chow with Tudor Pickering Holt.

Great. Thank you. I guess, back on the buybacks real quick. Doug, given your comments to, I think, Brad's question earlier, can we expect the buybacks to be more opportunistic in nature rather than ratable?

I wouldn't think about that way, Chi. I think for the most part we are agnostic to price at this point at least within reason. It's really more about cash flow generation. And whether that cash flow comes from operations or from dropdowns to HEP, I think I wouldn't think about them being sort of opportunistic versus ratable. It's really – this quarter we generated $6 million or effectively nothing in cash from operations. So depending on what you see for second quarter, third quarter and then beyond, presumably it will be higher than that. We hope substantially higher than that. If it's not, then pace would be much lower than we hope or expect. And if we start to see that ramp up significantly, then again I think buybacks will follow suit. And then similarly, timing on dropdown of what could be $200 million-plus dropdown to HEP in terms of the Woods Cross expansion. Obviously, that'd be another area of cash flow that would be available for buybacks.

Doug, do you have a specific timing on the Woods Cross drop?

Yes, I think I would say late third quarter or early fourth at this point, Chi. I mean we've got to get that unit started up running and sort of optimized before I think either party would have it make sense to drop that down.

Right. And that, I guess, expected $200 million level of drop, what does that imply on the multiple?

We'd stay sort of in the, what I'd call a market multiple. So what you're seeing now is sort of seven to nine times is where most refining MLP dropdowns have come in the last three to six months. There are some exceptions, one notable with a deal that was outside that range but seven to nine feels to us like the market today.

Okay, great. And then one final question on CapEx, Doug, did you just say this year is $600 million, is that right, stand-alone CapEx to HFC?

Inclusive of turnarounds. That's right.

Okay. Where do you stand on the Tier 3 gasoline spending by refinery?

Well I think at El Dorado, we're finishing up. So I think that money has pretty much been invested. At Navajo, probably be spending money through the next year or so, through February of 2017. And then at Tulsa, we're pretty well set. Maybe another couple quarters of cash to invest in that project. And then at the smaller projects we're deferred because they're smaller refineries.

So thought of another way, Chi, most of that capital is in the 2016, sort of $500 million of CapEx that we referenced already, maybe a little bit of spillover, as George talked about, into 2017 with Cheyenne and Woods Cross being in the out years because of their small refinery status.

Okay, great. Thanks. Appreciate it.

Your next question comes from Roger Read with Wells Fargo.

Hi. Thanks. Good morning.

Good morning, Roger.

I guess if you could maybe talk about diesel demand that you are seeing within your operating footprint. Obviously the year started off weak, but numbers look better recently. I was just wondering if you could give us a little more granularity on what you're seeing?

I think that pretty well summarizes it. I mean, it's weaker than it has been in the past in our larger customer segments, trucking and the railroads. I'd say probably around 10%-ish decline in those sectors, maybe a little bit more for the railroads. Obviously, we didn't have a very cold winter, not that that impacts our diesel demand in the regions we operate in, but it definitely does on the East Coast. So that contributed to the overall industry overhang of diesel. But we're encouraged by recent increases, especially in the ag sector, as the farmers get out and start planting.

Okay. And have you have you done anything yield-wise, any adjustments to go more heavily to gasoline or away from diesel, or reprocessing diesel into gasoline?

Yeah. I think most of that we did last year from a purely operational perspective, Roger. Changing our cut points between distillate streams and gas oil and naphtha streams both in the crude units and other downstream units like the cat cracker where you can make those cuts. What we're focused on now, as we talked about in our prepared remarks, is some of our opportunity capital projects are geared towards more gasoline production. The Tulsa FCC modernization that we talked about, that we just completed. The similar project we're doing at Cheyenne to do the same type of yield improvement and incremental capacity creep.

And I would add that we're already at the top of the peer group with I think close to 53% gasoline versus I think the average is maybe slightly below 50% or right at 50%. So we'd love to squeeze another 10% gasoline into the pool, but we just don't think that that's feasible and think we're already at the top of the heap, Roger.

Okay, and just a last question, with the slow decline underway, some might even say a rapid decline, but definitely decline in U.S. crude production. Are you seeing any changes in crude availability at this point across any of your refineries?

I'd say the short answer to that is, no. I think where we are most concerned is around the Woods Cross expansion as we've talked about before, availability of wax crude and other crudes to feed our expansion. But having said all that, we have secured additional sources, as we said in our prepared remarks, and are working with other suppliers and transportation pipeline service providers to ensure we have what we need to keep that expansion full.

Okay. Thank you.

Your next question is from Phil Gresh with JPMorgan.

Yes. Hi. First question is just on the RIN, sorry to come back to this, but could you give us the 1Q actual RINs cost as well as last year's, and then how your full-year expectation would line up relative to last year?

Yeah. I think on the RIN cost it really hasn't changed much over the last few quarters. It runs about mid-$40 million a quarter.

Okay. So you're not expecting a step up year-over-year?

Well, Phil. What I would say is, we've seen it be as high as $54 million in a quarter, at least over the last year-and-a-half. I think as George said, mid-$40s million, Q1. That is, you do think there's some averaging that goes on in terms of the RIN cost, where you purchase them, so some carryovers that might have been used in previous years. So what I would say is that approximates sort of mid-$50s million RIN price for that $46 million we spent this quarter. Current market is higher than that in the low to mid-$70s million. So, as we burn through our lower cost RINs and start getting into the higher price RINs, you'd expect that number to creep up into the next quarters going forward.

Okay, got it. That's helpful. On the OpEx side, costs were very low in the quarter in particular in the Southwest region which is below the run rate of last year. Was there anything one time in the quarter on the Southwest OpEx?

No, nothing one-time. I would highlight that a big portion, say about 40% of the decreased op cost was due to natural gas or fuel costs. So, that is running about $2 a million for natural gas.

Sure. Okay. Last question is just the $200 million incremental EBITDA number that you talked about, it sounds like a lot of that is obviously in process and so I assume not much was achieved in 1Q. But maybe you could just clarify that and then is the $200 million kind of more of a run rate that we should essentially be expecting by yearend? Or how should we think about that?

I think that's exactly right. That's a year-end run rate. And I think, again, the two biggest pieces of that are the Woods Cross expansion that we've highlighted in the past as $80 million to $100 million of that $200 million. And as far as the rest of it, we tried to give you a feel for that with the Tulsa modernization being $20 million and the El Dorado crude expansion be another $20 million. So those are the largest components of that.

Got it. Okay. Thank you.

Your next question comes from Jeff Dietert with Simmons.

Good morning.

Good morning, Jeff.

I was hoping you could talk a little bit about asphalt and what kind of prices you're seeing. I guess second and third quarter are the primary quarters, I think sometimes you sell some of this in advance. Could you talk about your pricing and remind us of your volumes. I assume they are going up with the discounts that we are seeing for Canadian heavy?

Yeah. I think our yield of asphalt typically runs about 1% to 2% of our crude rate. I think asphalt demand is looking pretty strong so far this year. I think, when you have a low price environment, the fixed state budgets go further obviously at a lower cost of asphalt. Asphalt is typically running about 80% of WTI. So $130 a ton, so if you want to divide that by 5.5 to get it to dollars per barrel. But in addition to asphalt, we sell a lot of roofing flux out of Tulsa, and that typically commands a appreciable premium, say $100 to $150 a ton over asphalt.

And so, with the recent increase in oil prices, is that squeezing asphalt margins for the second quarter or have you been able to sell forward some volumes and lock in better margins?

Well, usually, with a lot of these asphalt contracts, Jeff, there is an escalator that's associated with the crude price. So it should be agnostic to – the margin should adjust for the increase in crude price.

All right. Thanks for your comments.

Thank you, Jeff.

Your next question comes from Evan Calio with Morgan Stanley.

Hey. Good morning, guys.

Morning.

Yeah. My first question is on the Woods Cross expansion. I mean are all those changes that drive incremental EBITDA in 2Q, or is there some phase-in tied with fall maintenance? And related, I know you have volumes out of UNEV, what's your assessment of the effect of that ramp-up on those local markets, given current conditions?

Evan, could you go back to the first part of your question? I'm not sure I followed what you were getting at there.

Yeah. Sorry. Just trying to understand when the incremental EBITDA that you discussed for the full year – are all the units up and running in the second quarter or is there – are some of those elements in, I guess, the third quarter and around fall maintenance or turnaround season?

Sure. I think if you want to model it in, I would stay on the conservative side and say that the EBITDA starts in the third quarter. So that 80% to a 100% run rate that we just talked about, I'd model, say, 40% to 50% of it in the second half of this year. And then the 80% to 100% starting for full year of 2017. And then, I think, on your UNEV question and the impact on local markets, we would view the majority of our expansion, gasoline and diesel production going down UNEV. We might be able to squeeze some more into the Utah and Idaho markets. But those are well-served now obviously. So, incrementally, I think it's safe to assume that the majority of the expansion volume is going to go down UNEV.

Great. And then a follow-up question I had on M&A. I mean, would you say that your view on potential M&A is now tempered? I mean, that's what it sounded like incrementally from your prior response. I know there's been some private assets on the market and your focus appears your projects and the buyback priority given various uncertainties on the macro.

Yeah. Well, I think the view on M& A is it's very opportunistic, you never know when an asset is going to become available. So, I think if and when assets come available that are attractive to us, we're going to look at them and, obviously, when we're in a tighter refining margin environment like we are now, it makes you think even harder about it. But again these properties don't come up available for sale very frequently. So, again, if an asset comes up that's appealing to us, we're going to pursue it.

That's great. If I could squeeze one more in, I know you guys have had – Doug shared your view on WTI-Brent differentials, but what's your view here for the rest of the year? A little bit wider, I know the industry has recently exited turnarounds in the Mid-Con, Roger had mentioned declines. So, how do you think about the contribution of the differential, light differential in 2016?

As far as the Brent-WTI spread, I see it being around the $2 level it is now. Same thing with the coastal differentials for WTI, say, in Houston in LLS, all those should be in about that $2 region. I think fundamental transportation costs would argue for a wider differential for WTI in Houston, but I think there's excess capacity both from Cushing and Midland to get WTI barrels from those two locations to Houston. So the differential is trading below full transportation costs. But I still think $2 is a good number.

And Evan, I'd echo that and say that, obviously, we read what you guys write and appreciate that there's a sort of trend towards preference for Gulf Coast refining and sort of citing that the lower U.S. production could lead to tightening of that spread. And we've seen that some already, as George talked about. We've seen some fluctuation in that spread and short-term you can kind of see anything in our opinion. At the end of the day, if you're an inland producer, do you really want to put a barrel on a pipe, pay a tariff to move it to the Gulf Coast, and then get a lower net back ultimately when you get there. And so we think, as we've said now even dating back to the time when pipelines were being reversed in 2013 and 2014, that eventually that spread should look like a transportation differential. And so we think our geography suits us well in terms of being close to the crude barrel, depending on which refinery we're talking about. And our guess is probably slightly more educated than most, but that's where we think it is, as George said maybe $2 this year. And probably going between flat to $4 long-term, just depending on where the crude is being produced and what different discounts are there.

Great. Doug, and you can put me down on the RFS being incredibly flawed camp as well. I appreciate it.

We'll be sending you a petition to sign.

And your next question comes from Paul Cheng of Barclays.

Hey, guys, good morning.

Good morning, Paul.

I have a couple questions, hopefully pretty quick. Doug, the first one, when looking at – look like on a TIN number basis you have a tax expense, even though your pre-tax income will be a loss if we excluding the minority interest from the pre-tax income. Is that some kind of tax adjustment that negatively impacting you guys?

Yeah. Paul, we saw your note this morning and as we work through the math, think maybe somebody had the signs reversed. We calculated our effective tax rate being about 34% for the quarter and that's slightly below what you would have expected to see as a 38% or so tax rate, because HEP, which we get favorable tax treatment on, was a larger percentage of our earnings this quarter. So, we'd be happy to work through that with you. But that – the HEP earnings being a larger percentage, we also had a small number in terms of manufacturing tax deduction that slightly lowered the rate. But we show it at 34% and Julia would be happy to walk through that with anyone.

So I will take it offline. One of my associate will call Julia on that.

Great, thank you.

Second one, on ethanol, just want to make sure that, George, when you are talking about $36 million, that's really just on the blending economic loss?

That's correct.

That's not including the additional RIN cost you pay, right?

That is correct.

And I don't know because it seems like I have not heard other people that in this quarter cite it as a major issue, because based on the number that it seems like your margin realization loss by about $1 per barrel. We haven't heard other people citing in that magnitude at least. Just curious that is it the way how you guys sell your product to your customer is different than some of your peers? Or is it really uniquely in your market that is causing you guys to have a much higher blending loss than other people?

No, we don't think so, Paul. I mean, we are not – we are buying ethanol at market, and we're selling our products at market. So it's the same market that everybody else is buying and selling into. Again, it's a big proportional impact on us because, again, margins are small. So you're dividing a relatively fixed number, in the RIN charge anyway, by a smaller gross margin number. So the percentage looks exaggerated because, again, you're dividing by a small gross margin number, if you will.

Let me ask you in another way that what is the percent of your gasoline sales is net gasoline and how much is that just including ethanol when you sell?

Well, we've said in the past that we blend about half and so about half bulk is clear barrels.

And some of your peer actually when they sell that they will in the in the invoice they separate out and say what is the net gasoline price and what is the ethanol price. I presume you guys don't do that. That's why that you couldn't pass through fully. And why the industry is not moving in that direction? If everyone basically they'll have to – I mean, when you sell the finished gasoline, why not just break it out between what you pay for for the net gasoline and what is the ethanol and just become a pass-through?

Yeah. We just – remember again, Paul, this is the first quarter in a longtime that ethanol margins have been negative. Again, it was driven primarily by a low crude price dragging down the gasoline price with it. And I think the other relevant point here to remember is, even peers that have retail associated with them, they are buying ethanol and blending it as well. And again, we are not overpaying for ethanol and we are not underselling...

No. I mean, George, I think I understand what you just say. I am just saying that for the industry it seems that you are trying to make money by the net gasoline by your manufacturing, not by taking the (48:40) on ethanol. Why not the industry move into the system, so that when you send an invoice to your customer, you charge them what is the net gasoline and then the ethanol become a pass-through add on sort of like the fuel surcharge by the transportation company. So by doing it this way you eliminate that fluctuation. Yeah, I mean, when oil price is high you may give up some branding economic, but when oil price is low you that don't have this kind of big loss. But anyway, so that may be a stupid idea from me. But anyway, thank you for your time.

Thanks, Paul, for your thoughts.

Your next question comes from Ed Westlake with Credit Suisse. Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker) Yes. Good morning. A long discussion, I mean some of the other folks in the industry have been flagging ethanol. So it is out there. I just had a quick small question on it though. Where in your accounts are you putting it? Is it in refining operating expenses or someone else?

It's in cost of goods sold. Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker) Okay. So then on your refining operating expenses, they went from $236 million to $228 million. Obviously natural gas came down a lot. You're targeting reliability and cost improvement of around $195 million from the Analyst Day. Maybe just walk us through your delivery milestones in terms of some of the refining operation improvements, because that's a big chunk of the $700 million?

Yeah, I think in round numbers our OpEx reduction target was right around $100 million. Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker) Yeah.

And I think what we've said in the past is, we achieved about $30 million of it last year and I think you're seeing some of that come through in the first quarter here. One of the reductions we had in operating cost that was about the same magnitude as natural gas was lower maintenance related, what we call XO or extraordinary projects. So that spend was about, again – that savings was about the order of magnitude of lower fuel cost this quarter. Do you remember, Julia. About $10 million, Ed, for the quarter. Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker) And so, but you should think it should be – I mean it's just I'm am not seeing it in the headline numbers. I mean I appreciate there's lots of other moving parts in (51:15).

Yeah. Julia has the breakdown that she can provide. But again, overall we're doing well in the OpEx portion of our business improvement plan and a lot of that, as you noted, is reliability related. When you run your plans reliably, you need less maintenance cost and less of this XO project category that we just finished talking about. Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker) Okay. And then on the opportunity investments, I mean, obviously you've talked through some of the bigger larger capital projects and obviously having a good year this year in terms bringing some of those on, but as you think about that other bucket which was much smaller, any sort of updated cadence in terms of when you'd expect them to hit between now and the longer term target?

As far as opportunity cost, Ed, I think the best way to think about that is.... Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker) Opportunity investment, sorry.

I'm sorry opportunity capital. Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker) Yeah.

Sorry. I think – thinking about that as being $50 million of EBITDA each year from last year through 2018. So, we're going to get $200 million in that bucket in four $50 million annual additions. Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker) And in terms of, I mean, (52:31) is it more difficult to see in terms of your confidence, has it changed since the Analyst Day?

I think if anything, I'm more optimistic in what we are seeing because of projects like the El Dorado crude expansion that we just highlighted in our prepared remarks. And that one was a phenomenal effort by our operations and engineering teams again to get 6,000 barrels per day of additional crude rate out of a unit that we've run historically at 138,000 with nominal – and I'm talking less than $1 million – of capital. So, that's really an outstanding application of intellectual capital to replace capital investment. Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker) Okay. And then final one from me. Lubes, just any color on how margins were in Q1 and Q2?

I think Q1 the margins were a little bit better because crude price was lower. And whenever there is a crude movement, lubes prices are stickier than the crude price. Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker) Okay, so somewhat of a benefit in a quarter versus the normal run rate.

Actually, Ed, I think the crack was still very good, but crack was flat to down slightly. Fourth quarter was actually pretty good too.

We actually made basically 1 percentage point more, but cracks were marginally down. So net-net it was a wash basically versus the previous quarter. Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker) Okay. Thanks very much.

And your final question comes from Faisel Khan with Citigroup.

Good morning, it's Faisel from Citi. Just wanted to understand, on the ethanol and RIN questions that have been asked ad nauseam, there was nothing out of the ordinary, the industry norm, that took place with you guys this quarter versus all the other companies that are reporting this quarter. Just want to make sure I got that right.

That would be our expectation.

Okay, got you. Good. And then just going back to the RIN price and how you expect to have a bigger impact, you expect the cost to be higher as we go through the year. I would have thought that with gasoline demand sort of being higher this year than last year, there would be more opportunity to generate RINs in the market because of discretionary blending. So, I'm just trying to understand, is that opportunity not there as gasoline demand has grown year-over-year, or is there something else?

I think the biggest difference is the RVO. The RVO that was published in November was higher than anticipated so that drove the RIN price from roughly $0.50 per RIN at that time to the $0.70 level that it is now.

Okay. And then...

Faisel, the other point is when you look at first quarter, ethanol margins were negative. So you blend, you sort of compare the two, you compare the cost of the RIN versus blending.

Sure

That's the other component.

Okay. Understood. And then just on the Navajo refinery, it ran very well in the quarter, especially versus last year. I was trying to understand the product mix a little bit. It looks like you actually produced on a percentage basis more distillate in this quarter versus last quarter, and gasoline was down a little bit too. So, I was trying to understand what's taking place there.

That's quarter-on-quarter or year-on-year?

Over last year, year-on-year?

Yeah. I think one of the things you're seeing there is we implemented a project last year that allowed us to draw more diesel off of the crude tower. And that diesel draw allowed us to increase our crude rate. So, maybe on a percentage basis, the distillate yield went up, but on an absolute volume basis that allowed us to run more crude at the refinery.

Okay. Got it. Thanks for the time.

Sure, Faisel.

And we do have a follow-up question from Neal Mehta with Goldman Sachs.

Good morning, guys.

Good morning Neal.

Doug I want to kick-off with you on just leverage levels and I think in the past you talked about net debt to EBITDA being one turn being the target level. Is that still the right level for you guys, one times ex-HEP.

Yes, Neal. I'd say as a blanket statement, that's true. In an acquisition for a period of time would you go higher than that if there were a reason to do so, I think potentially but probably not more than 1.5 times for that instance. And then obviously the big question is what is EBITDA? But what we laid out at Analyst Day I think was generally $1 billion of debt f in the outlook time we were looking at which was from now to 2018. And I think we still feel like that's the appropriate amount of leverage.

That's great. And then my last question is just operational performance thus far in the second quarter. I know it's early, but on a turnaround adjusted utilization rate, is everything tracking towards plan?

Yes. Everything is going well.

Okay, great. All right thank you, guys.

Thank you.

We have no further questions in queue at this time. And I would like to turn the floor back over to Julia for any closing remarks.

Thank you everyone for joining us today. As always if you have any follow-up questions or would like to discuss any of these other items in the Q&A in detail, I'll be around all day. Just reach out. And with that we look forward to sharing our next quarter results with you in August. Have a good day.

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