Thank you, Carina. Good morning, everyone, and welcome to HollyFrontier Corporation's fourth quarter 2018 earnings call.

This morning, we issued a press release announcing results for the quarter ending December 31, 2018. If you would like a copy of the press release, you may find one on our website at hollyfrontier.com.

Before we proceed with remarks, please note the Safe Harbor disclosure statement in today's press release. In summary, it says statements made regarding management expectations, judgments or predictions are forward-looking statements.

These statements are intended to be covered under the Safe Harbor provisions of federal security laws. There are many factors that could cause results to differ from expectations, including those noted in our SEC filings.

The call may also include discussion of non-GAAP measures. Please see the press release for reconciliations to GAAP financial measures.

Also, please note, any time-sensitive information provided on today's call 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, and good morning, everyone. Today, we reported fourth quarter net income attributable to HollyFrontier’s shareholders of $142 million or $0.81 per diluted share.

Fourth quarter results include a lower of cost or market inventory valuation adjustment that decreased pre-tax earnings by $329 million. Excluding this item, net income for the quarter was $394 million or $2.25 per diluted share versus adjusted net income of $125 million or $0.70 per diluted share for the same period in 2017.

Adjusted EBITDA for the period was $641 million, an increase of $307 million, compared to the fourth quarter of 2017. This increase in earnings is primarily due to our ability to capture the favorable crude discounts across our refining system.

Our lubricants and specialty product business reported an EBITDA loss of $4 million, driven by negative Rack Back EBITDA in the quarter. Rack Back EBITDA was negatively impacted by very weak base oil markets and the turnaround at the Mississauga plant.

Rack Forward EBITDA was $49 million, representing a 12% EIBITDA margin. Full-year Rack Forward EBITDA was $213 million, representing a 13% EBITDA margin in-line with our guidance range.

Within the base oil markets, we believe 2018 was the cyclical low. We anticipate continued pressure in the base oil crack into 2019.

HollyFrontier expect the negative Rack Back EBITDA to moderate with no plant maintenance this year at our Mississauga base oil plant. Additionally, we closed on our previously announced acquisition of Sonneborn on February 1, further strengthening our Rack Forward business.

For full-year 2019, Rack Forward EBITDA is expected to be in the $275 million to $300 million range with an EBITDA margin of 11% to 16% of sales. Holly Energy Partners reported EBITDA of $90 million for the fourth quarter, compared to $125 million in the fourth quarter of last year, which included a non-cash gain related to the acquisition of remaining interest in the Salt Lake City in Frontier pipeline.

HEP EBITDA was negatively impacted by lower unit volumes and unplanned maintenance on the refinery processing unit at Woods Cross in the fourth quarter. We remain committed to returning excess cash to shareholders.

During the quarter, we announced and paid the $0.33 per share dividend totaling $58 million and repurchased $185 million of our stock. For full-year 2018, we returned $597 million to shareholders through dividend and share repurchases.

Now, I’ll turn the call over the Jim for an update on our operations.

Thank you, George. For the fourth quarter, our crude throughput was 406,000 barrels per day, slightly below our guidance of 410,000 to 420,000 barrels per day.

This was primarily due to unplanned maintenance of one of the SEP units at our Woods Cross refinery, which has since been resolved. For the full-year, we ran 432,000 barrels per day of crude and we successfully completed turnarounds at our Tulsa West, Mississauga, and El Dorado plants.

In the Rockies, our fourth quarter operating expense of $10.90 per throughput barrel was slightly elevated due to the unplanned maintenance at Woods Cross. We continue to make progress on our efforts to improve operations at our Cheyenne Refinery.

For the full-year of 2018, we set an annual crud rate record averaging over 47,000 barrels per day. In the Southwest, OpEx per throughput barrel was $5.36 for the quarter.

Navajo also set an annual crude rate record averaging over 109, 000 barrels per day leaving to the highest annual gasoline and diesel production ever recorded. In the Mid-Con, our operating expense per throughput barrel was $6.76 for the fourth quarter, due to the turnaround at our El Dorado refinery, which was also in the fourth quarter.

Despite a heavy maintenance year for the Mid-Con, we were able to set an annual record for gasoline production at our Tulsa Refinery. Looking to 2019, we have a turnaround schedule for the first quarter at our Tulsa East plant that is expected to last through March.

Both Cheyenne and El Dorado are scheduled for turnarounds in the fall. We expect to run between 400,000 and 410,000 barrels per day of crude oil for the first quarter.

I will now turn the call over to Tom for an update on our commercial operations.

Thanks Jim and good morning everyone. For the fourth quarter, we ran 4,600 barrels of crude oil composed of 40% Permian, and 17% WCS and black wax crude oil.

Our laid-in crude cost was under WTI by $17.39 in the Rockies, $6.66 in the Mid-Con, and $6.67 in the Southwest. In the fourth quarter 2018, we ended the year with a year-on-year increase in vehicle miles driven and good demand for products in both domestic and export markets.

Gasoline inventories in the Magellan system ended the quarter at 8.8 million barrels, roughly 3.2 million barrels higher than September 30 levels. Diesel inventories ended the quarter at 6.6 million barrels, equaling third quarter levels.

Days’ supply of both gasoline and diesel in the group finished at 28 days and 36 days, respectively. Fourth quarter 3-2-1 cracks in the Mid-Con were $14.78, $27.16 in the Southwest, and $26.67 in the Rockies.

Crude differentials widened across the heavy and sour slates during the fourth quarter. In the Canadian heavy oil market, fourth quarter differentials for WCS at Hardisty averaged $39.43 per barrel, but recently, we have seen this differential decrease to the $13 range as the Alberta Government [oil system] has reduced the volume of crude available and developments in the Venezuelan market has increased the demand for heavy crude in the Gulf Coast.

Despite [corners] the levels of apportionment on the Enbridge system remain high. We continue to be able to purchase and deliver adequate volumes of price advantaged heavy crude from Canada to meet our refining needs.

Canadian heavy and sour runs average 58,000 barrels per day at our plants in the Mid-Con and Rocky region. While our El Dorado plant was in turnaround in the fourth quarter, we were able to take advantage of favorable WCS Arbitrage economics by selling excess barrels into the Cushing market.

We refined approximately 171,000 barrels per day of Permian crude in our refining system, composed of 110,000 barrels of the Navajo complex and 61,000 barrels per day by the Centurion pipeline at our El Dorado refinery. Midland differentials averaged fourth quarter at $8.88, and currently, we see the same differential trading at flat to Cushing through the new pipeline capacity coming on stream earlier than expected.

We anticipate this differential to widen into the summer months and then revert to current levels in the third quarter this year as current pipeline capacity comes on stream. Fourth quarter consolidated gross margin was $22.17 per produced barrel sold, a 77% increase over the $12.54 recorded in the fourth quarter of last year.

This increase was driven by improved laid-in crude cost in the Mid-Con and Rockies regions, as well as strong diesel cracks in all our markets. Rent expense in the quarter was $48 million.

And with that, let me turn it over to Rich.

Thank you, Tom. For the fourth quarter of 2018, cash flow from operations was $425 million, inclusive of turnaround spending of $103 million.

HollyFrontier's standalone capital expenditures totaled $90 million for the quarter and $257 million for the full-year of 2018. As of December 31, 2018, our total cash balance stood at $1.2 billion, a $79 million increase over the balance on September 30.

We funded the Sonneborn acquisition on February 1, with cash on hand and were left with over $700 million on the balance sheet. Remaining cash balance along with our undrawn $1.35 billion credit facility puts our total liquidity over $2 billion.

During the fourth quarter, we returned a total of $243 million of cash to shareholders, comprised of a $0.33 per share regular dividend totaling $58 million and a repurchase of approximately 2.7 million shares of common stock totaling $185 million. For the full-year of 2018, HollyFrontier paid $234 million in regular dividends and spent $363 million repurchasing approximately 5.9 million shares of common stock for a total cash return of $597 million.

As of December 31, we have $1 billion of standalone debt outstanding and a modest debt-to-cap ratio of 14%. Total HEP distributions received by HollyFrontier during the fourth quarter were $37 million, a 3% increase over the same period in 2017.

HollyFrontier owns $59.6 million HEP limited partnering units, representing 57% of HEP's outstanding LP units with a market value of over $1.7 billion as of last night's close. Some additional guidance items for full-year 2019.

In capital spending, we expect to spend between $470 million and $510 million for both turnarounds and CapEx at HollyFrontier Refining and Marketing, $40 million to $50 million in our lubricants business and $30 million to $40 million of capital for HEP. We’re expecting a tax rate of 23% to 25% and with respect to Sonneborn, we anticipate $25 million to $30 million of one-time integration cost in 2019.

With that Carina, we’re ready to take some questions.

Hi, good morning everyone. George, I appreciate the comments in your prepared comments about the LSP business and specifically the Rack Back, I wonder if you could just go into a little more depth as to why you think that 2018 was a cyclical low and your confidence that will see your recovery?

Hi Brad, it’s Rich. So, like in the fourth quarter there were really two things going on as George mentioned, one was macro and one was micro.

On the micro side, we had a turnaround catalytic dewax train at Mississauga, which produces a lower Group III material and this was about half the quarter. On a year-over-year basis, just a reminder, we had turnarounds in both trains in 2018 and we do not have any scheduled maintenance for 2019.

And on the macro side, the base oil markets were really weak obviously in the third and fourth quarter, and the rate of change was particularly painful in the Group III market, where we saw some extreme behavior from similar competition. We believe either late 2018 or early 2019 is the cyclical low really driven by the supply demand balance, supply coming on during 2018 and the debt that should trough year around the turn of the year, kind of much the same way that we think about 2016, which was cyclical low in our fine product markets.

So, we’re thinking that 2019 will see some year-over-year improvement versus 2018, then we will continue to improve from there in the long run. So, looking into our business, we’re expecting improvement in 2019 versus 2019, primarily driven by the absence of that planned maintenance, but I think we’re going to struggle to see the Rack Back portion reach breakeven in 2019.

One other point to add specific to the fourth quarter was the significant drop in crude oil prices during that time. So, that translates into base oil pricing, slightly lag, but still translates pretty well and on top of everything else that Rich just mentioned, it caused buyers to really go hand to mouth and not go long on inventory, especially with the year-end coming.

Okay, got it. I appreciate the thought there.

And then I guess one on the dividend, so it’s been at the same level since early 2015, I think, and obviously in that time period you’ve added a good chunk of stable lubricants EBITDA, so I was curious if there is a desire going forward to maybe start growing the dividend or how you feel about it.

Yes, Brad it’s Rich. I think you exactly hit on how we’re thinking about it, which is, we’ve been the using buyback as our incremental form of cash return.

I think over the next few quarters, particularly as we gain some operating history with Sonneborn, we intend to review the dividend exactly as you said right, we’ve added some much more stable cash flow streams in PCLI, Red Giant, Sonneborn and our traditional fuels refining business and when you combine that with the effects of corporate tax reform, we do see the opportunity to re-examine the dividend here in the next few months.

Okay. And then just one quick one if I could.

This quarter last year you guys had the small refinery waver for Woods Cross in hand already, I was just wondering if you’ve received any of those or if, you know, conversely, you’ve been denied any of them?

No, I think with the government shutdown this kind of delayed the whole process there. We’ve submitted our applications, but there hasn’t been anything done either way to approve, which is what we expect to happen.

Okay, thanks.

Hi guys, good morning. Congrats on the headline be it there.

Rich, just going back on your comments on lubes, is there any way you could help kind frame up the impact of the turnaround, maybe the lost opportunity just so we can get a sense of what the true underlying performance would have been?

So, Blake, it’s a fair question, but we’re not big fans of doing LPO calculations because their academic exercises are best. Suffice it to say, your higher margin products were not being produced for half the quarter and you were still incurring all of your costs during that period of time, so it’s pretty material.

Got it. Okay, that’s fair enough.

Secondly, on the throughput guidance of 400 to 410, it’s a little bit below, I think what we were originally estimating, I know you mention the turnaround at Tulsa East, is there anything else in there whether maybe some economic run cuts or something like that?

Yes, I wouldn’t call them economic run cuts from a loss perspective, but the margins were seen in the first quadrant so far, so rather than running full out, like we typically do there wasn’t much margin on the last increment of [indiscernible] crude runs, but like to say, the biggest item by far is the Tulsa turnaround.

Got it. Okay.

Thank you, George.

Hi guys. I know it’s only been 20 days since you acquired Sonneborn, pretty sure you were looking through the assets during this time.

How confident are you of your initial kind of guidance of 66 million EBITDA run rate forward and 20 million of synergies at this point of time?

I think like you say, Manav, it’s very early three weeks in, but we remain confident on both those fronts for the base EBITDA, as well as the synergies. We think there is – a lot of optimization can be done between our existing PCLI business and the newly acquired Sonneborn business to allow us to be more efficient and more effective and to better serve our customer base from both companies.

Second question is a very quick question, I noticed that in the Mid-Con region your heavy sour crude runs, I mean, as a percentage dropped on like 15% to 11%, obviously there was a lot of incentive to run heavy sour, was there any restriction because of which you dropped from like 15% to 11% on the heavy sour crude oil?

I think you might be seeing the impact of the El Dorado turnaround there were we didn’t run that refinery as hard as we usually do to the turnaround and I think as Tom said in his prepared remarks, we still capitalized on the WCS arbitrage by selling the WCS barrels into the Cushing market.

Okay. Thank you so much guys.

Yes. Hi, good morning.

One, just follow-up question I guess on the rack back, is there any way to kind of calibrate how you think about the impact on the business in 2019, somewhere to the guidance you were able to give for the rack forward? Obviously, that’s bounced around quite a bit in 4Q as everyone has noted a pretty significant headwind?

Phil, hi. Look, it is – the lubricant business, the Rack Back partly with base oil.

Again, a lot like refining, so we can’t predict crack spreads, so it’s really hard to come up with numbers unlike to your point the Rack Forward side, but I think our belief here is that it’s going to be better than 2018, primarily driven by the absence of planned maintenance.

Right, okay. Second question just on the capital spending guidance, is that a fair way to think about the run rate moving forward layering in, obviously not that much for Sonneborn, but just in general is this a fair way to think about the go-forward or is it a normal maintenance here in terms of the turn around spend and how should we think about that?

For a refining business this is a very high turnaround year. On the lubricant side, we do not have a turnaround at Mississauga, so this is probably pretty reasonable and Sonneborn incremental capital we think it is $10 million to $15 million a year or so run rate.

HEP historically has been a pretty normal year. So, the one call out there would be we do have a very heavy turnaround spend here.

Okay, my last question would just be on the OpEx in refining, you know trended obviously very high in the quarter and certainly in the second half altogether, if I recall from the Analyst Day, you were expecting something around the 550 per barrel long-term target, so I just want to calibrate where you feel we are from an OpEx perspective and the path to get there?

Yes, I think we have a long way to go here yet. To be honest with you Phil, most of it is reliability related.

So, we incur maintenance expenses obviously when we have reliability issue, and obviously the decreases are denominator as well, and results in higher unit cost. So, we’re making progress in some areas as Jim highlighted, you know we’re doing great in certain of our plants like Cheyenne, you guys have followed the progress along with us over the last two years or so.

That plant has seen significant improvements during that time period and running, as Jim said, average 47,000 barrels per day versus the capacity of 50, so doing well there. Similar story at Navajo, but some of our other plants need to step it up and get to that same level and that’s where we’re working on.

Okay, thank you. I’ll turn it over.

Good morning. The first question I had was just around share repurchases, a strong number here in the fourth quarter.

As you think about 2019, how should we think about the cadence around capital returns, particularly around share buy backs?

Neal, I think we'll walk through our waterfall of cash use, first and foremost, just to protect the balance sheet and the investment grade rating and our ability to fund the assets. Second is the dividend, and we talked about our desire to review that in the next couple of quarters.

There will be grow, both organically and inorganically and last will be the return that excess cash to shareholders and as we’ve talked about, we view excess cash as that above $500 million of cash on our balance sheet.

That’s fair enough. And the follow-up is more of just a macro question, two spreads been top of mind for investors.

Brent WTI, which is a company has certainly been a beneficiary of, but also the tightening of western Canadian crude, so thoughts on how you see Brent WTI evolving over the course of 2019, especially as these Permian pipes come online and then on Western Canada how you think about the offsetting impacts of continued long-term production growth out of the base and then against some of these near-term headwinds about heavy crudes being taken out in the market?

Hi Neal, it’s Tom. I’ll jumping here, and will start will the Brent TI question.

Going forward, we look at the forward markets for Brent TI. We’ve been pleasantly surprised that they have been trading out at higher rates, I think we’re pushing $9 or $10 now.

Looks like when you look into the future it’s continuing that. I guess we’re attributing that to a little bit of weakness on WTI at Cushing, coupled with strength in the Brent market as we continue to see these situations in the middle-east or cut backs quarters coming out of OPEC, increased demand out of China.

That's what we tend to expect for the remainder of this year. As you know, we’re not a big player in the Brent market or the international markets, so it’s difficult to get a good read on it, but that’s our view point, but it should be in that $8 to $10 for the balance of the year.

On the Canadian situation, it’s a little harder to say what’s going to happen. I think the Alberta Government when they implemented the core system, they tended to over correct the problem.

We saw differentials go from 47 down to 9, you know that low differential in the Venezuela and the Mexican issues really impacted, you know the heavy differential on a short-term basis and in doing so it basically rendered real economics coming out of Western Canada to be uneconomic. So, I have seen people like Imperial Oil shatter their program and others taking a look at it.

We’ve looked at it a couple of ways on a long-term basis. The first way is that we’ve looked at it as a transportation and quality adjustment from the Gulf Coast.

And the second way, we sort of looked at the variable basis to rail and solve what that was to be the price setting mechanism as we go forward. And as a result, we sort of came up with the same number looking at it two different ways and that’s sort of in the $15 to $ 80 range for WCS differentials.

I think we’re seeing that and the other factor that’s coming into play is when you look at the forward curve on WCS you see some discounting in the fourth quarter because of IMO 2020 so the WCS in the fourth quarter of this year is trading at around minus $20. So, that’s our view on Western Canadian economics at this point-in-time.

Do you believe that IMO is going to cost having barrels to discount?

Yes, we do. That heavy end of the barrel, obviously is where the bunker fuel comes from and when the bunker fuel gets displaced from the shipping industry it has to go somewhere and I don't know what the ultimate price setting mechanism is going be on that last barrel that needs to clear, but we think it’s going to be in some sort of power generation of fuel and related price market.

Thanks guys.

Hi guys, good morning. This is Kalei on for Doug.

Got a couple of macro question, since a lot has been touched there. First, so some of your peers have been indicating that they're maximizing the production of distillates relative to gasoline, given the pricing spread there, but your sales indicate that your yield hasn't really changed.

So, I just want to get your thoughts on how you feel about the gasoline versus distillates in your markets and how you think your system will be positioned this summer?

Well, the setup to maximize diesel over gasoline has been a problem for a long time. So, that's the way we've been running our refineries and I guess when you look back in history to see how that's trended.

But I would not be surprised to see that we've been relatively constant over time because, again, that incentive has been there for a long time.

Alright. And can you talk about how you feel that your system will be positioned this summer?

I guess since you haven't changed in the past, you're not going to change now?

Yes, we don't see anything that's going to change again the way we're running our refineries. Diesel cracks have been significantly above gasoline cracks even when both are very strong.

So, we've been in max diesel mode. We run our diesel hydro treaters and isotherm/hydrocracking units full accordingly.

Thanks. And just a follow-up to Neil's question.

Just want to get your thoughts on how you guys see Rockies' grades pricing this year, whether you guys see any potential for bottlenecks at either Guernsey or Bakken? And I'll leave it there.

Thanks.

On the Rockies side – this is Tom. We probably see a continuation of what we're seeing now.

There's a little bit of bottlenecks. We see some pipelines coming on stream, which should relieve it as we move forward.

And there's some localized strength, for example, in the southwestern Wyoming crudes. They're showing a lot of strength, but that's just more on a one-off isolated market instance.

We're still seeing NDL and continue to see NDL, or North Dakota Lake Bakken, trade at a small discount at Guernsey. We expect to see that.

And that small discount at Guernsey relates to a small to medium premium under Cushing market of $0.50 to $1.00. So, we don't see any big expectation or changes going forward, and we'll just leave it at that.

Thanks guys.

Hi, good morning, everyone. Maybe to stick with the Rockies crude theme, black wax differentials are out to $15 after TI.

A year ago, that was more $5 after TI. Is that just a reflection of ongoing production growth in Utah?

And is your Woods Cross Refinery getting all the black wax it needs?

This is Tom Creery again. Yes, the differentials have widened on a spot basis, that's for sure.

And there's more crude being produced than the Uintah Basin. We're seeing a lot of rail movements coming out of the Price River Terminal headed towards the Gulf Coast, which becomes the price-clearing mechanism and that's relating into those higher prices.

Got it. And then we hear a lot about the ultralight barrels coming out of the Permian.

You have a medium sour refinery at Navajo. Could you talk about those two dynamics?

Is there any opportunity to move to a lighter slate there? And of the light barrels you do run at Navajo, are those ultralights?

Or do you need to be pretty careful about the gravity there?

It's a mix, to be quite honest. And if you'll recall, I believe it was last year, we did a capital expansion project at the Navajo Refinery that allowed us to run additional heavy crude produced from the Delaware Basin, which we...

We make light crude.

Pardon me?

Light crude.

Light crude, I'm sorry. The whole table corrected me on that one.

So, anyway – so we're maximizing as much of the lighter crude coming out of the Delaware Basin as we can. And then what we're also doing is we're utilizing some of that lighter crude to move through the Centurion pipeline to the El Dorado facility.

I'd add that we're also doing some small projects currently that help us further bottleneck for light crude at Navajo.

Hi, guys. How is it going?

If I could just ask another question about the OpEx topic. It looks like Rockies, in particular, the OpEx has been double digits for the past two years, and I know you mentioned that you're addressing that, are there any specific initiatives that you could highlight in terms of trying to bring that number down?

Well, again, I think it ultimately goes all the way back to reliability. And we've discussed the improvements we've made at Cheyenne over that period.

So, by difference, it highlights the need for improvement around Woods Cross facility. We did have an event there last year that required a significant maintenance expense to repair.

And again, we’re down for appreciable period of time. So, again, our throughput was lower than we would like, so yielding the higher unit cost that we need to move on.

Got it. And I guess if I could get your updated thoughts on M&A.

I'm wondering if you guys are looking to either continue to expand into the Rack Forward business if there's more you could integrate with your base oil production and then also your view on the refining M&A environment right now? Thanks.

Yes, so the high – a high level on M&A, yes, as Rich highlighted in our waterfall for capital uses, we still have a desire to grow and improve our company. We want to do it intelligently and prudently.

And we think the Sonneborn acquisition is a good example of that. It ties in very well with what we already have in the HF LSP segment, yet at the same time, it also brings us into new markets and new customer segments.

We continue to be pleased by the deal flow we see in that Rack Forward market. Red Giant being another example of that, that we executed on last year.

And we'll continue to look at opportunity like that to continue to bolt on logical additions to our HF LSP portfolio. On the refining side, as you know, there's not that many refineries in the U.S., about 125 in total.

They don't come up for sale very often, so it's very intermittent. And we'll look at them as they come available, but they're not as ratable as what we're seeing on the lubricant side.

Great. Thanks a lot.

Thanks, Jason.

Thanks, everyone. We appreciate you taking the time to join us on today's call.

If you have any follow-up questions, as always, reach out to Investor Relations. Otherwise, we look forward to sharing our first quarter results with you in May.