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Welcome to HollyFrontier Corporation's Fourth Quarter 2018 Conference Call and Webcast.
Hosting the call today from HollyFrontier is George Damiris, President and Chief Executive Officer. He is joined by Rich Voliva, Executive Vice President and Chief Financial Officer; Jim Stump, the Senior Vice President of Refinery Operations; and Tom Creery, President, Refining and Marketing. [Operator Instructions] Please note that this conference is being recorded.
It is now my pleasure to turn the floor over to Craig Biery, Director, Investor Relations. Craig, you may begin.
Thank you, Carina. Good morning, everyone, and welcome to HollyFrontier Corporation's Fourth Quarter 2018 Earnings Call.
This morning, we issued a press release announcing the 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 shareholders of $142 million or $0.81 per diluted share. Fourth quarter results include a lower cost or market inventory valuation adjustment that decreased pretax 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 Products 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% EBITDA 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 a cyclical low. We anticipate continued pressure on the base oil cracks into 2019. For HollyFrontier, we expect the negative Rack Back EBITDA to moderate with no planned 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 noncash gain related to the acquisition of the remaining interest in the Salt Lake City and Frontier Pipelines. HEP EBITDA was negatively impacted by lower UNEV volumes and unplanned maintenance on a 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 a $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 dividends and share repurchases.
Now I'll turn the call over to 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 FCC 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 crude 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, leading 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 the 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 406,000 barrels of crude oil composed of 40% premium 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 of 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 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 Indonesia -- 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 averaged 58,000 barrels per day at our plants in the Mid-Con and Rocky regions.
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 via the Centurion pipeline at our El Dorado refinery.
Midland differentials averaged fourth quarter at $8.88. And currently, we seen the -- see the same differential trading at flat to Cushing through to the new pipeline capacity coming onstream earlier than expected. We anticipate this differential to widen into the summer months and then revert to the current levels in the third quarter this year as current pipeline capacity comes on onstream.
Fourth quarter consolidated gross margin was $22.17 per produced barrels 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 8 -- $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 stand-alone 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. The 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 the 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 stand-alone 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 partner 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 the full year of 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 are expecting a tax rate of 23% to 25%. And with respect to Sonneborn, we anticipate $25 million to $30 million of onetime integration costs in 2019.
And with that, Carina, we're ready to take some questions.
[Operator Instructions] Our first question comes from Brad Heffern with RBC Capital Markets.
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 we'll see recovery.
Hey, Brad, it's Rich. So look, in the fourth quarter, there were really two things going on that George mentioned. One was macro and one was micro. On the micro side, we had a turnaround in 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 basal 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 some of our competition. We believe either late '18 or early '19 is the cyclical low really driven by the supply-demand balance. Supply coming on during 2018, and the debt that should trough here around the turn of the year, kind of much the same way that we think about 2016 was the cyclical low in the refining product markets. So we're thinking that in 2019, we'll see some year-over-year improvement versus 2018, and we'll continue to improve from there in the long run. So looking to our business, we're expecting improvement in 2019 versus 2019 (sic) [ 2018 ], primarily driven by the absence of that planned maintenance. So we're going to -- I think we're going to struggle to see the Rack Back portion reach its breakeven in 2019.
I think, Brad, one other point to add that was specific to the fourth quarter was a significant drop in crude oil prices during that time. So that translates into base oil pricing slightly lagged, but still translates pretty well. And on top of everything else that Rich just mentioned, it caused a virus to really go hand-to-mouth and not go along on inventory, especially with the year-end coming.
Okay. Got it. 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's a desire going forward to maybe start burning 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 using the 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. And exactly as you said, right, we've added some much more stable cash flow streams and PCI in 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 reexamine 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 waiver for Woods Cross on hand already. I was just wondering if you've received any of those or if conversely, you've been denied any of them.
No, I think with the government shutdown, that's 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.
Your next question is from Blake Fernandez with Simmons Energy.
Rich, just going back on your comments on lubes. Is there any way you could help kind of frame up the impact of the turnaround, maybe the lost opportunity just so we get a sense of what the true underlying performance would have been?
We aren't -- so Blake, it's a fair question, but we're not big fans of doing LPO calculations because they're academic exercises at 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 million to $410 million. It's a little bit below I think what we were originally estimating. I know you mentioned the turnaround at Tulsa East. Is there anything else in there whether it be 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 -- say it in the first quarter, so far. So rather than running full out, like we typically do, there wasn't much margin on the last few -- last increment of -- crude runs. But like you said, the biggest item by far is the Tulsa turnaround.
Your next question is from Manav Gupta with Credit Suisse.
I know it's only been 20 days since you acquired Sonneborn, but 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?
Yes. I think like you say, Manav, it's very early, 3 weeks in. But we remain confident on both those fronts for the base EBITDA as well as the synergies. We think there's 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 was a very quick question. I noticed that in the Mid-Con region, your heavy sour crude fronts, I mean, as a percentage dropped from like 15% to 11%. Obviously, there was a lot of incentive to that heavy sour. Was there any restriction because of -- each should drop from like 15% to 11% on the heavy sour crude oil?
I think you maybe seeing the impact of the El Dorado turnaround there, where 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.
Your next question is from Phil Gresh with JPMorgan.
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 similar to the guidance you were able to give for the Rack Forward? Obviously, that's bounced around quite a bit in 4Q. As everyone's noted, a pretty significant headwind.
Hi Philip. Look it is the lubricants business, the Rack Back partly with base oil. Again, they're a lot like Refining so we can't predict crack spreads. 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 2019 -- or excuse me, 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, there's not that much for Sonneborn. But just in general, is this a fair way to think about the go forward? And -- or is it a normal maintenance year in terms of the turnaround spend in there? How should we think about that?
I think for our Refining business, this is a very high turnaround year. And on the Lubricants side, we do not have a turnaround at Mississauga, so this is probably pretty reasonable. In Sonneborn, the incremental capital I think 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 year.
Okay. My last question will just be on the OpEx in Refining. It turned out, 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 a $5.50 per barrel long-term targets. 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 a reliability issue. And obviously, the decreases are denominator as well and results in higher unit costs. So we're making progress in some areas, as Jim highlighted. We're doing great at certain of our plants, like Cheyenne. You guys have followed the progress along with us over the last 2 years or so. That plant has seen significant improvements during that time period. It is running, as Jim said, average 47,000 barrels per day versus a capacity of 50,000. So doing well there. Similar story at Navajo. But some of our other plants need to step it up to get to that same level, and that's what we're working on.
Your next question is from Neil Mehta with Goldman Sachs.
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 buybacks?
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. I mean, our ability to fund the assets back in -- as a 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 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.
Yes, that's fair enough. Yes, and then just a follow-up, it's more -- just a macro question. Two spreads has been top of mind for investors. Brent/WTI, which the 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 basin against some of these near-term headwinds around heavy crudes being taken out of the market.
Hey, Neil, it's Tom. I'll jump in here. I'm going to start with the Brent TI question. Going forward, we look at it -- the forward markets for Brent TI. We've been pleasantly surprised that they've been -- they trading out at higher rates. I think we're pushing $9 or $10 now. It looks like when we look into the future, it's continuing there. I guess what we're attributing that to was a little bit of weakness on WTI at Cushing, coupled with strength in the Brent market as we continue to see the situation in the Middle East or cutbacks 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 viewpoint that 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 corner system, they tended to overcorrect the problem. We saw our differentials go from $47 down to $9. That low differential in the Venezuelan and Mexican issues really impacted the heavy differential on a short-term basis. And in doing so, it basically rendered rail economics coming out of Western Canada to be uneconomic. So you're seeing people like Imperial Oil shutter 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 is a transportation and quality adjustment from the Gulf Coast. And the second way we sort of looked at the variable basis to rail and saw 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 $18 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 that 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 can cause heavy barrel 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 to be on that last barrel that needs to clear, but we think it's going to be in some sort of power generation or fuel-related price market.
Your next question is from Doug Leggate with Bank of America Merrill Lynch.
This is Kalei on for Doug. Got a couple of macro questions 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.
All right. 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.
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.
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.
Your next question is from Matthew Blair with Tudor, Pickering, Holt.
Maybe to stick with the Rockies crude theme. Black wax differentials are out to $15 off of TI. A year ago, that was more $5 off of 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 it's -- 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 2 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 weather the bottleneck for light crude at Navajo.
Your next question is from Jason Gabelman with Cowen.
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 2 years. And I know you mentioned that you're adjusting 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 are 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.
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.
[Operator Instructions] There are no further questions. I turn the floor back to Mr. Biery.
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.
Thank you. This does conclude today's teleconference. Please disconnect your lines at this time and have a wonderful day.