Welcome to HollyFrontier Corporation's Fourth Quarter 2015 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 call over to Julia Heidenreich, Vice President, Investor Relations. Julia, you may begin.

Good morning, everyone, and welcome to HollyFrontier Corporation's fourth quarter 2015 earnings call. I'm Julia Heidenreich, Vice President of Investor Relations. This morning, we issued a press release announcing results for the quarter ending December 31, 2015. 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 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 the 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. Today's call may also include discussion of non-GAAP measures. Please see the press release for reconciliations. Also please note that information presented on today's call speaks only as of today, February 24, 2015. Any time-sensitive information provided may no longer be accurate at the time of any webcast replay or re-reading of the transcript. And with that, I'll turn the call over to George Damiris.

Thanks, Julia. Good morning and thank you for joining us on HollyFrontier's fourth quarter earnings call. Today we reported a fourth quarter net loss attributable to HFC shareholders of $44 million, or negative $0.24 per diluted share. Excluding the $144 million non-cash pre-tax inventory valuation charge, net income attributable to HFC shareholders was $44 million or $0.24 per diluted share. Fourth quarter EBITDA, excluding inventory valuation charge, was $161 million, 21% above the comparable quarter last year, due to higher crude throughput. Fourth quarter throughput was approximately 407,300 barrels per day versus our revised guidance of 395,000 to 405,000 barrels per day. We ran 26% sour and 18% WCS and black wax crude. Our average laid-in crude cost under WTI was $0.93 per barrel in the Mid-Con, $4.35 in the Rockies and $0.91 in the Southwest. Consolidated refinery gross margin was $9.91 per produced barrel, 8% below the $10.76 per barrel recorded in fourth quarter 2014. Contributions from strong winter gasoline cracks and the $19 million bio-fuel tax credit were more than offset by a $12.5 million RIN charge associated with the November 30 increase in RFS targets, a $26 million hit from negative ethanol blending economics, and a $36 million year-end inventory revaluation charge. Combined, these effects knocked approximately $1.50 per barrel off realized margins on a consolidated basis. Full year 2015 operational results highlight the benefits of the reliability and process safety initiatives. We achieved a record 97.6% refinery utilization rate, 6 percentage points above 2014. The Southwest and Mid-Con systems recorded full year utilization rates in excess of 100%, and the Rockies showed a 5% improvement compared to 2014. 2015 earnings benefited from gasoline market strength. Our 52% weighting towards gasoline production drove a 15% increase and a full year realized margins of $16.07 per barrel. Optimizing…

Thanks, George, and good morning. For the fourth quarter 2015, cash flow provided by operations totaled $76 million. Turnaround spending in the fourth quarter totaled $33 million, taking our full-year turnaround expense to $89 million. In 2016, we expect to spend approximately $116 million on turnarounds. Fourth quarter HollyFrontier's standalone capital expenditures was $193 million, taking our full year capital expenditures to $609 million compared to our $600 million to $650 million budget. For 2016, we expect to spend about $500 million on CapEx. Included in that is some carryover spending that was not completed in 2015 and approximately $50 million in additional environmental costs associated with Tier 3 compliance. As of December 31, 2015, our total cash and marketable securities balance stood at $211 million, a $416 million reduction from September 30 levels. Cash outflows in the quarter included $321 million in dividend and share repurchases, and $193 million in CapEx. Through 2015, we returned a significant portion of our cash earnings to shareholders. During the fourth quarter, we repurchased 5.2 million shares at an average price of $48.22. For the full year 2015, we spent $743 million on share repurchases, reducing our overall share count by 16 million shares. Year-to-date 2016, we've executed an additional $129 million on share repurchases, buying back 3.7 million shares at an average price of approximately $35 per share. We have $179 million remaining on our existing share repurchase authorization. And last week, we announced our $0.33 per share quarterly regular dividend which puts our total cash yield at 4.3% as of last night's close on the dividend. As a reminder, HollyFrontier owns 39% of Holly Energy Partners, including 22.4 million common units, plus the 2% general partner interest. The current market value of our LP units is approximately $630 million as of last night's closing price. Fourth quarter general partner incentive distributions were $11.2 million, a 20% increase over the same quarter last year. For the full year 2015, we have received approximately $90 million in cash distributions from HEP. Lastly, a reminder that you can find monthly WTI-based 321 indicators for our Mid-Con, Rockies and Southwest regions posted on HollyFrontier's investor page. These regional indicators do not reflect actual sales data, and are meant to show monthly trends. Realized gross margin per barrel may differ for indicators for a variety of reasons. You can find the data on our investor page at hollyfrontier.com. And with that, Shelly, I think we're ready to open the line for questions.

Our first question comes from Blake Fernandez [Howard Weil]. Your line is now open.

Hey, guys. Good morning. I wanted to talk a little bit about the buyback pacing. At your Analyst Day, I know you weren't giving guidance, but you did outline kind of an outlook into 2016, something around maybe $1 billion or so. In 4Q, you certainly ramped it up as promised. I'm just curious, Doug, how you're thinking about that continuing into 2016 here as some of the margins have begun to roll over a little bit?

Sure, Blake. What I'd say is, I'll start by reiterating that we already bought back about $130 million worth of stock, or 3.7 million shares, so far in January and February. So as we look at the balance of 2016, I'd say it's certainly our expectation we'd complete our current $1 billion authorization, of which about $180 million remains outstanding. And then beyond that, it will be largely dependent on three things. First, our cash flow generation; second, our ability to raise public debt at a reasonable price; and then third, our ability to drop assets down to HEP for cash. So all three of those metrics are worse or have deteriorated from September levels. But it's important to remember that it's still February and the refining business often looks sort of weaker in January or February every year. So, I guess, I'd say that, in summary, we remain laser-focused on executing our business improvement plan that we outlined last September, as you referenced, and that share repurchases are a key component of that plan. But the volume of repurchases is going to depend some on the refining margin environment and then the availability of capital in the market.

Understood. Okay. The second question, I guess it's kind of a question on Pad 2 cracks and some of the economic run cuts that's been announced by industry, but secondly, if you could maybe tie in what you're seeing there with some of the guidance, I think I heard 380,000 to 390,000 in 1Q, which is a little bit below what we were thinking, although, I know George mentioned some downtime at Tulsa, which – I'm sorry to ask so many, but can you tie in – I thought some of the Tulsa issues were taken care of in 4Q. So I'm just trying to understand, is that a different turnaround than what you've already completed in Tulsa?

No, I think the turnaround that we have right now at Tulsa was our planned event. We did have an unplanned event in the fourth quarter in Tulsa. And that was due to trying to extend our cycle between turnarounds from five years to six years in order to incorporate the project that we were implementing at Tulsa to modernize our FCC. So, again, fourth quarter was an unplanned event. This turnaround we're currently in is the planned event to implement our turnaround and the project. So that's our primary reduction in crude rate, and it's primarily at Tulsa. We have trimmed a few thousand barrels a day here and there at El Dorado and Navajo, but nothing major.

Okay, great. Thank you.

Thanks, Blake.

Your next question comes from the line of Neil Mehta [Goldman Sachs]. Your line is now open.

Hey. Good morning, guys.

Good morning, Neil.

George, I know this was preliminary, and Doug always warns me to not type this $700 million number as gospel, but I just wanted to think about this a little bit. I mean, at the Analyst Day, you came out with the $700 million number in terms of refinery operations optimization and capital investment in terms of average annual EBITDA uplift. As you guys think about the business plan for 2016 and 2017, which of these different – the five different buckets that you kind of outlined there do you think we should say is commodity agnostic, if that makes sense, as opposed to ones which would be sensitive and how much risk is there to that $700 million number?

I would say most of the $700 million is agnostic to price. The element that's probably the most dependent on price in cracks is the opportunity capital component because obviously at $30 per barrel, you have less impetus to do yield improvement type projects to take something from petroleum, coke or fuel gas value up to crude oil value than you do when price of crude is $60 a barrel to $80 a barrel. But I don't think any of us expects crude to be $30 per barrel for the next 20 years, which is the typical term we use for project life in our analysis. So we might start out a little bit on the slow side, but I think over the long-haul these opportunity capital investments we're pursuing are going to be economical and justifiable.

And Neil, what I'd add to that is, as you think about sort of being agnostic to the price, the level set here is on that $700 million of improvement against 2014. So if margins are substantially lower or higher for that matter or different, then we're trying to back that out of what we call sort of our business improvement plan capture. And so, if we get to the end of year and we say, look, we feel like we've captured a lot of these things, we've lowered OpEx, we've seen commercial optimization, but EBITDA is flat to 2014 or worse that will be because of crack spreads being worse not necessarily because we didn't execute on our business plan. And that's, as we sort of outlined in September, would always be the challenge in trying to show that. But we think we've got a very good program to be able to do that, and know that we are achieving what we expected to achieve so far in our plan.

I appreciate that. And the second is more of a macro question. The three layers of the cake, if you could just kind of talk about each of them. So first, on diesel, what the impact of some of the slowdown in rig count has been as you look at your Mid-Con operations in gasoline, you cited a constructive outlook going into the summer, but what you're seeing from an inventory level at this point and what ultimately works it down, and then finally, any thoughts on differentials? All three would be greatly appreciated.

The differentials?

Well, I think, we'll start with diesel first. There's no question diesel is weaker currently than it has been in the recent past. And I think that's due to a number of issues both domestically and internationally. A lot of new refineries built overseas for the explicit purpose of making diesel. And then, in the U.S., we've got some hydrocracker start-up that increased diesel production. At the same time, the demand is weak. You mentioned, the oil patch, obviously with a third of the rig count we had not too long ago, all the activity associated with that was diesel driven, that demand is gone. I think there's a lot less railcars and stuff moving around, especially with coal. We've done a good job of killing the coal industry in this country, and so those railcars aren't moving as much as they used to. And I think the road truck traffic is down as well. So, lower demand and higher supply is ultimate crest at about $10 a barrel versus 20$-plus historically. On the gas side, there's no question inventories are high at this point in time. I think that's primarily been supply driven. Refining fleets run in the high-90% of utilization. And at the same time, I think demand is still relatively strong. The vehicle mile driven data is very strong, 2.5% year-on-year. You can't ask for much more than that. I think employment is strong. So we still see the demand side of the equation being relatively strong, and it's going to be a matter of people getting their turnaround done in April as we highlighted. And we have our 52% gasoline weighting that should play in our favor here when cracks improve starting with the turnaround season here. As far as crude depths, there's not much of a talk about our crude depths in the $30 environment. There's just not that much room or spread at $30 as there is at $60 or $80 or $100. We're still very encouraged by the Canadian crude depths. We're seeing double-digit crude depths in the $30 WTI crude oil, that's pretty encouraging. We run about $80,000 to $100,000 barrels a day of heavy Canadian crude, so about 25% of our slate can be heavy Canadian crude. So that plays well, but as far as Permian depths and Rockies depths and all those depths, with all the pipeline depths has been put in place, they are very compressed and we expect them to be for the foreseeable future until price picks up and production picks up accordingly.

All right. Thank you, George and Doug.

Thanks, Neil.

Your next question comes from the line of Phil Gresh [JPMorgan Securities LLC]. Your line is now open.

Hey, good morning.

Good morning, Phil.

First question is just on the Southwest region. If we look at the capture rate that you've seen in that region, it's been down for four consecutive quarters. Obviously there are some variables here in the fourth quarter that perhaps were one-time, but maybe you could just help us calibrate that fourth quarter performance and how you would think about what a reasonable cash rate is considering tightening of crude differentials, et cetera, in that region?

Yeah, Phil, capture rate – it's such a – what I'd call, analyst concept although I appreciate that's the way you guys model it. I mean, as we think about what's gone on there, I think the biggest issue trending negatively has been compression of the TI and TS spread and then the Midland to Cushing spreads. The plan is actually running extraordinarily well. I knock on wood as I sort of say that superstitiously, but Navajo has done great in sort of bottlenecking some problems in terms of running crude that they've had, and average crude rate I think for 2015 was north of 100,000 barrels a day. So in terms of a trend, as George highlighted, we had a few things that worked against us in the fourth quarter that were significantly pronounced on really some RINs and biodiesel, a few other things that I think are likely one-time in nature, certainly we hope that to be the case. In terms of modeling capture going forward, I think Julia has probably got a better handle on that. Julia, do you have anything to add or subtract from that?

Yeah, I do just think I would reemphasize the fourth quarter capture was pretty sloppy because of an inventory year-end write-down. Most of that $36 million impacted Navajo and again the RIMS and biofuel. If you adjust for all of those things, I think it's far more normalized and in fact slightly better than the third quarter, which was 69%. And again, I think that just looking here going out, the crude differentials are certainly going to keep that at a lower level versus when you had that $6 and $7 benefit. But nonetheless, I do still think that depending on how the gasoline diesel cracks way in, because you'll have to look we do make a little bit more diesel in the Southwest due to some improvements we made there being able to pull some more distillate out of that stream, so you just keep an eye on the inversion between diesel and gasoline, which could also play into capture rate.

Okay, thank you. I appreciate all the color on that. Second question, I guess, just coming back to the buyback, at the Analyst Day, you talked about your willingness to take leverage to roughly one times. Obviously, the macro backdrop has changed. Is there still a willingness to use the balance sheet to the same degree if things are worse? And related to that, where do you feel things are with respect to the $200 million of dropdown capital you're expecting to get per year from HEP in 2016?

Yeah, so as to the debt question, I guess, first. I would say, yes, we very much do expect to put leverage on the balance sheet. As I said, in answering Blake's initial question, that market has backed up a little bit, but I'd like to believe that somewhat temporary. I'm not sure we can be in the sort of 4.5% level that maybe we might have seen in October/November of last year for tenure. But, yes, you should expect to see us put some leverage on the balance sheet in the first half of 2016. And again, the uses of those proceeds will be for CapEx program this year, and then free cash flow generated for share repurchases, so no change there. In terms of the dropdowns, what I would say is, yes, we still very much see 2016 as an opportunity to dropdown Phase 1 of the Woods Cross expansion. That said, we do see some deals in the market. And when I say we, I mean HEP really predominantly that we hadn't seen for a good while. And so I would say that dropdowns are still very much part of the story. There might be acquisition opportunities in the market that compete with that in the near-term given some of the distress in the MLP market that we've always got the ability to sort of time the dropdowns from HFC, and so do I think $200 million of cash sales to HEP in 2016 is still possible, yes, likely I might back off of that number some just because I think HEP may see a few other deals that it hasn't seen in the last few years. You got to take advantage of while they're there.

Sure, understand. Okay, thank you.

Your next question comes from the line of Brad Heffern [RBC Capital Markets LLC]. Your line is now open.

Hey. Good morning, everyone.

Good morning, Brad.

Doug, just following-on on the repurchase questions. I'm curious, at year-end, the cash balance is really quite low and you said you've repurchased a decent amount in the first quarter as well. I guess, what is the minimum cash level in this environment and given that I would assume cash flow generation has been relatively weak given where cracks are, have you been funding those repurchases off the revolver?

So, no, we haven't. We used cash flow generation through the fourth quarter and cash on the balance sheet for share repurchases. We haven't borrowed yet for that. As you point out, we had $1 billion undrawn revolving credit facility, which provides certain liquidity to us. And I think we've always said, a targeted $500 million of cash on the balance sheet was what we had anticipated having as go forward safety capital. I think some combination of that and revolver capacity, particularly in our lower crude price environment gives us some comfort. So I don't want to be pinned down to a specific number, Brad, but somewhere in this geography, in that, call it, $250 million of cash and $500 million of revolver availability where your liquidity was never below three-quarters of $1 billion or so. It feels comfortable to us that there might be 90-day periods of time where we're above that or below that. But again, that gets back to us talking about wanting to add a little bit more permanent capital to the balance sheet and that's something we would expect to do in the first half of this year.

Okay, thanks for that. And then, I guess, circling back to the first quarter guidance, understand there's some turnaround activity in that. Have you guys chosen to make any sort of pure economic run cuts just given the context in the environment?

Yes, again, relatively minor. A few thousand barrels a day here and there at El Dorado and Navajo.

Okay. And then one more, if I could. On the ethanol blending front, you called out the headwind that that had in the fourth quarter. Is that something that you see bleeding into the first quarter as well?

No question. I mean, we've got ethanol trading at a premium to gasoline, roughly $0.20 a gallon. So for every gallon of gasoline you blend, you use 10% ethanol. That's about $0.02 on a blended gallon basis.

Okay. I'll leave it there. Thanks.

Okay, thank you.

Your next question comes from the line of Ryan Todd [Deutsche Bank]. Your line is now open.

Thanks. Good morning, guys. Maybe if I could ask a couple on the capital side. Could you give us an update on the status of some of the projects that were targeted for year-end, start at the Woods Cross expansion, and maybe the additional scope work that you talked about during the first quarter 2016 and the Cheyenne hydrogen plant. Are those up and running and any change in outlook to the EBITDA contribution from those?

Yeah, I think we'll start with the big one first on the Woods Cross expansion project. There's no change from the last guidance we provided. We said we were going to finish construction and start commissioning in the first quarter, ramp up the plant in the second quarter and get to full run rates and EBITDA potential in the third quarter. So we're still on schedule there. I think same thing for the incremental projects around the expansion to allow us to run alternative crudes to the black wax baseline which the project was based. The Cheyenne hydrogen plant is up and running, as is the El Dorado naphtha fractionation project. So both of those two are doing what they're supposed to be doing and operating quite well. And we look forward to further optimization based on the increased capability those two projects give us.

Great, thanks. And then, maybe a follow-up to an earlier question on the opportunity capital program. I mean, if you look – you had given some level of guidance in terms of the opportunity capital and the EBITDA generation over a three-year view. Given the environment that we're in, I guess, both – you referenced before about the crude environment, and I guess the product environment as well. Is there is there any shift to the pace of that? Should we expect to see the pacing be the same? Do you – as long as crude prices remain at $30, do you just defer some of the capital on that? Do you spend it now on the view that crude prices will recover relatively soon or is there opportunities within that bucket that would allow you to accelerate those versus maybe other commodity sensitive ones?

Yeah, we don't see much change due to the current pricing environment for those projects. We're still thinking in terms of putting $100 million year to work to get $15 million per year of EBITDA. So roughly again two-year simple paybacks. Yeah, the current crude environment makes you double-clutch a little bit on some of these projects. But you have to take a longer-term perspective, again, that crude is not going to be $30 per barrel forever. And these projects are very economic and give us a lot more capabilities than we would otherwise have without them.

Great. I appreciate it. I'll leave it there. Thanks.

Okay, Ryan.

Your next question comes from the line of Doug Leggate [Bank of America Merrill Lynch]. Your line is now open.

Hey, guys. It's actually Kalei Akamine on for Doug. Couple questions. First one, just on marketing. Maybe this is for George. So refineries are generally bullish on gasoline in 2016, I just wonder if you could address the record level of gasoline stocks that we have currently and are you guys finding gasoline storage or takeaway becoming tighter at this point? And maybe, could you explain how the switch from winter to summer spec could exasperate this trend? And finally, how this may frame your expectation for the seasonal margin in the summer?

Okay. Well, again, I think we do have a lot of inventory in the system currently. I think that's primarily due to the efficiency of the industry refining fleet and running at nearly 100%, high-90%s anyway, utilization rates. And as you say, in the summer or in the winter, you can make more gasoline due to butane blending and other high RVP blending components. This is nothing new. I mean, we go through this every year, every winter to varying degrees. It seems like every other year the Magellan system that pick out a specific one for our Mid-Continent refinery spills and inventories get high. But as soon as the RVP changes, those high RVP barrels that our inventory have to come out. And when they come out and the butane blending seizes that decreases supply and the underlying demand is still strong as evidenced by the vehicle miles traveled again. We view that as all positive for the crack going forward in the second and third quarters.

I'd add something to George's commentary, because obviously there's been a lot printed and a lot of concern about gasoline inventories and concern of the outlook for refineries. I did a little work this week in looking and comparing sort of ownership of refining assets in the United States in, say, 2008, 2009 time environment. The last time we really saw a downturn in this business and oversupply for extended period of time in the market and compare that to today and you guys might already realize this. But by our estimation, there's about 4.2 million barrels of capacity that's gone from being owned by integrated oil companies to now being owned by independent refiners. And so the two big ones there are Marathon and Phillips, which came public as independent companies in 2012, and then you saw Tesoro buy Carson, you've seen PBF buy Chalmette recently as well as Torrance. That adds up to about 25% of the refining capacity in the United States that used to be owned by integrated oil companies, now owned by independents. And so, I think, if you look back to just two weeks ago and some announcements when we saw margins get pretty weak on gasoline for very short period of time, and you saw Phillips and others make announcements about discretionary run cuts, we mentioned a few thousand barrels a day within our own. I'd say, perhaps different from some of our peers in other sectors in the energy space, refining has gotten to be extraordinarily disciplined. And so you couple that with, as George has talked about, what we think will be very good demand for gasoline, especially at this lower price heading into the summer. And sure, again, we've got to be reminded, it's February, there are seasonal weakness, but I think those dynamics will carry us through to what should be maybe a better gasoline margin, and certainly the forward strip or most of those that are looking expect right now.

Thanks for that, guys. Second question, just want to throw another one at the buyback. So just looking at 1Q, obviously the margin environment has deteriorated and is likely going to affect your cash generation ability, but your stock is at the lowest level in a year. Can you just talk about your appetite for buybacks with this in mind? Thanks.

Yeah, I'm not sure how I could say it much differently than I already have. We've again already bought back 3.7 million shares so far this year, acknowledging that price is obviously lower. We've got an intent to put some debt on the balance sheet, and then again the pace of the buybacks is going to be dependent on our cash flow generation, the ability to raise debt, and then the ability to fund dropdowns at HEP. It's not a matter of if we'll be buying back shares, it's just going to be the pace will be dependent again on cash flow generation, which is what I would think you guys would expect and hope from us.

Thanks, appreciate it.

Your next question comes from the line of Jeff Dietert [Simmons & Company]. Your line is now open.

Good morning. Jeff Dietert with Simmons.

Hi, Jeff.

Hi. I was curious you did see a little bit of an increase in your medium and heavy crude feedstocks in the fourth quarter. I assume that's probably continuing in the first quarter as those discounts have been more attractive then the lighter crudes. Can you talk about your flexibility to shift incrementally towards medium and heavy crudes that are trading at better discounts?

Sure. I think, most of that flexibility resides at El Dorado and Cheyenne, where we have decent-sized cokers. And I think, like you said, to the extent that we can, we're running as much WCS as we can at both those facilities. Navajo doesn't have access to WCS, and we don't run WCS at Tulsa. We run the WTI primarily for our lubes business. So, again, those are two plants that give us the flexibility to run the Canadian crude. And we can run some other Canadians as well, but primarily it is WCS.

Got you. You talked about economic run cuts, some barrels at El Dorado and Navajo. Can you talk about some of the challenges perhaps logistical challenges associated with cut and runs? I'm assuming you're buying crude 30 to 60 days in advance and your crude inventories, I assume, are relatively high. So if you're not going to run, you either have to sell the barrels or store the barrels. Could you just talk about that complexity a little bit?

Yes, it really hasn't been much of an issue for us, especially at El Dorado where we're connected to Cushing. We can either store it in our tankage there or sell it, and then again these aren't big cuts, a few thousand barrels a day here or there. So we've been able to contain them, and we've had a positive role that gives us economics to tank them and use them for future months.

Got you. And you talked earlier about your high gasoline yield relative to peers. Has this been an intentional strategy or are you more just doing the best with the legacy assets that you have in making investments there that are most advantageous?

Yeah, it's a combination of being lucky and being good. We'd take what we have, as you said. We had a good project to modernize our FCC that played out regardless of the gasoline diesel spread. And we implemented the project and positive gasoline diesel differential just made that project even better.

Thanks for your comments.

Thank you.

Your next question comes from the line of Chi Chow [Tudor, Pickering, Holt & Co.]. Your line is now open.

Hi, thanks. Doug, the effective tax rate for the quarter appears to be very low. I think you mentioned that the biodiesel lending cart is flowing through margins. What are the other factors that were impacting tax rate in the quarter?

Yeah, Chi, the biggest impacts for us there were, we had been accruing through September at sort of a higher expected statutory rate. Fourth quarter was lower than expected, so ended up with a lower – what feels like a lower effective tax rate. So think sort of HFC earnings a little lower in the fourth quarter, HEP actually a little higher, but as you know, that's a pass-through to unit holders there. And so think that that is one-time anomaly sort of that was a function of where we were through the first nine months versus where we ended up in the fourth quarter.

Okay. And then what's the guidance on tax rate going forward this year?

Statutory sort of 35% is what we're modeling.

Okay, great. And then, on I guess any sort of growth at HEP whether it drops or acquisitions with the yield where it's at, how do you think about financing growth there in the current MLP environment? And on any drops, it sounds like you're definitely focused on bringing cash back to the (43:54), is that correct?

Well, so to the last question, on new assets, so take example the Woods Cross Phase 1, yes, it'd be a preference to take cash because you've got a high basis asset whereby taking cash you don't have any tax leakage. Whereas on more legacy assets, you may be preferred to take units, so you don't have the friction of the tax. What I would say is, the yield environment or the unit prices improve certainly at HEP, but still not at a level where you would be real excited about issuing units. So we've still got a fair amount of debt capacity there. We're at, I think, just north of four times debt-to-EBITDA. So there is some additional capacity. I think, we wouldn't need to be issuers of equity in 2016 at HEP, certainly for Woods Cross drop down there have to be an equity component. And whether that was to the market or to HFC, it's just going to depend on a number of different factors. I think that market is starting to show a little bit of, again, positive reception to those like HEP that they have a steady stream of growth and are starting to be better recognized than they were in the last 30 days to 60 days. But, listen, we're like everybody else, we're going to have to watch that market and sort of look at what the opportunity set is, what the capital looks like, and that certainly more uncertain today than it was a year ago.

All right. Okay. Thanks, Doug. Appreciate it.

Thank you, Chi.

And your last question comes from Johannes Van Der Tuin [Credit Suisse Securities]. Your line is now open. Johannes M. L. Van Der Tuin - Credit Suisse Securities (USA) LLC (Broker) Hi. Thank you for taking my call. A couple of quick questions. First, on the balance sheet. Given the additional worries people have about the macroeconomic environment, I know you're not here right now, but if you did ever become a bit more balance sheet constraint, how would you go about managing that through the cycle? Would you look at first kind of maybe slowing down the pace of buybacks or would it be a slowdown in growth CapEx or are there other levers that you would pull?

Yeah. I think, all of those are possibilities. I mean, as you say, today we have zero debt on HFC's balance sheet. So we're not at all constraint. But that being said, of course, you've got to look – even when you are or aren't capital constrained, it's been our history to be good stewards of capital. And you've got to look hard at your CapEx programs and do the projects that are the most advantageous to you going forward. There are – as George mentioned, there's lots and lots of more good ones that we've started to evaluate and see as possible. You'd love to do all of them in 2016, but that's not realistic first from an execution standpoint and secondly from an available capital standpoint. And so, we said at our Analyst Day, projects like Woods Cross Phase 1 of that nature are few and far between, and we're going to be more focused on projects in that $25 million to maybe up to $50 million capital range. Is there a possibility of one or two that could be higher than that in the next few years? Yes, but otherwise, we're going to be cautious in what feels like a tougher environment than we've been in the last few years. On the buybacks, I think, sort of reiterating, yeah, to expect $750 million of buybacks, which is what we did last year, or $780 million. It's going to be dependent on free cash flow generation. So if you look back through really all of the history of Holly and Frontier and then the predecessor companies, you'll find us to be on the more conservative side in the industry. I think that still stands true today. And we talk about adding leverage. We would expect that to be in the one times EBITDA range. So you just don't find yourself having to manage the balance sheet beyond that. So I'm not sure if I've answered your question. But I think most would agree we're among the very best and most conservative in understanding that this can be a cyclical business. Johannes M. L. Van Der Tuin - Credit Suisse Securities (USA) LLC (Broker) That's very helpful. Thank you. And second question goes to winter grade gasoline. I mean, there is a sense that in the market currently a lot of those inventories are really winter grade inventories that were built up in December and January when runs were much higher. My understanding, and this could be incorrect, is that winter grade gasoline like all gasoline, the molecules deteriorate over time, it can't be preserved from a year-to-year basis on an indefinite sort of period of time. Is that the case? And if that's so, is it really just all inventories must go situation, in which everybody really needs to push those winter grade inventories into the market basically now all they can, or are there some ways that you can preserve the value there for some future period?

Well, I think let's start with the shelf life question. I don't think that what you've been led to believe is true that there is a limited shelf life on gasoline. I think the bigger issue is the cost of continuing to store that gasoline. If you don't get it out by the time the RVP changes, you have to tank that barrel for a whole year or almost a whole year till the RVP season gets back to that spec. So it's really the cost of carrying that through a whole year that drives people to sell the barrel rather than continue to store it. Johannes M. L. Van Der Tuin - Credit Suisse Securities (USA) LLC (Broker) Okay. But you think that the net effect is still the same where people just really want to sell it now because the cost is too prohibitive to carry it into next season?

That's true. Tanks cost money at the end of the day. It's round numbers, call it $0.50 per barrel per month. So if you're going to store for a year, it's going to cost you roughly $6 a barrel to store the barrel for a year. Johannes M. L. Van Der Tuin - Credit Suisse Securities (USA) LLC (Broker) Okay. That makes sense. Thank you very much.

Sure.

And your last question comes from Roger Read [Wells Fargo]. Your line is now open.

Good morning. Thought I hit star-1 earlier but I guess I had messed up on that. Anyway, a couple questions to ask you just because it hasn't been hit on this call and I think it's been on every other one. As you think about the octane issues out there, can you give us an idea of what may have changed a little bit, maybe an idea of how much of some of the gasoline that's in storage might be more octane than something else and how we should think about sourcing that as we go into this summer?

Yeah, as far as octane, I don't think much has changed year-on-year. For octane, we still view octane as going to be at a premium going forward. I think a lot of that has been driven by the composition of the crude that the U.S. refining fleet is processing. It has more naphtha in it and it tends to be a lower quality naphtha that basically means it's lower octane or produces lower octane gasoline as a result. So we still view octane as going to be tight this year. I don't think anything much has changed from last year to this year to change that forecast. As far as what's in storage now, I think some higher octane gasoline components could be in storage, especially since they tend to be lower RVP so can make the transition from the high RVP winter to the lower RVP summer. But I don't see that being as a big percentage of what's in storage now.

Okay, thanks. And then, you talked earlier about the economic run cuts just being a few thousand barrels. I was curious if you had made any changes in the yield in that environment as well, so not just removing barrels from the market but also moving barrels to a different part of the yield?

Yeah, no question. Like all refiners, we use our LP models daily, if not more frequently than that to optimize our crude slate as well as our product mix not only between gasoline and diesel, Roger, but also between light products and heavy products. There are times when asphalt has been a very good product for us, especially when the heavy sour crude is wide enough and asphalt can be a better product for us at times and even light products.

Thanks. That was kind of where I was going to go in the next. Any thoughts on the asphalt market as you go into the summer?

I really don't see much material change there either year-on-year. The supply of high quality asphalt is less than it had been, say, in the last five years or so. Again, due to the crude slate, the lighter shale oil crude don't make good asphalt. So as they've made their way into the U.S. crude slate, they don't produce high quality asphalt, so the supply of high quality asphalt is not as prevalent as it used to be. And we still run again a lot of WCS primarily at Cheyenne and El Dorado again. And we make a lot of high quality asphalt at those two facilities.

All right, that's it for me. Thank you.

Thank you.

Thanks, Roger.

And your next question comes from Jeff Dietert [Simmons & Company]. Your line is now open.

Yeah, maybe quickly regionally, could you talk about when you make the shift from winter grade to summer grade? How much time is left to bring these winter grade inventories down?

Yeah, I can't quote all the RVP timing changes by region, Jeff. But I think it's just safe to say that it's happening now, and it will continue to ramp up over the months to come. We can get you the RVP schedules by region or by state if you'd like, but I just can't recite them off the top of my head.

In the South, don't they start in March, or is it more of an April event?

I think it's – go ahead, Tom.

I think – this is Tom Creery. You're correct. We get varying layers of when the grade changes start. And you're correct, we're going to start here and gearing up for March changeover that will be the first tranche and then go from there.

Okay.

Why don't you let us, Jeff, get you the exact schedule so that you know for a fact rather than just from poor memory.

Okay. Got you. But generally speaking, it's earlier in the south and later in the north, correct?

That's right.

That's correct.

Yes.

All right. Thanks for your comments.

Sure.

There are no further questions at this time. I'd like to turn the call back over to Julia for closing remarks.

Thanks, everyone, for joining us this morning. If you have any follow up questions, please reach out to Investor Relations and, with that, have a good day.

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