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Welcome to HollyFrontier Corporation's Third Quarter 2018 Conference Call and Webcast. Hosting the call today from HollyFrontier is George Damiris, President and Chief Executive Officer. He is joined by Rich Voliva, Executive Vice President and Chief Financial Officer; Jim Stump, Senior Vice President of Refinery Operations; and Tom Creery, President, Refining 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 third quarter 2018 earnings call. This morning we issued a press release announcing results for the quarter ending September 30, 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 expectation, judgments or predictions are forward-looking statements. These statements are to be intended -- are to be covered under the safe harbor provisions of federal securities laws. There are many factors that could cause results to differ from expectations, including those noted in our SEC filings.
The call also may include discussion of non-GAAP measures, and please see the press release for reconciliations to GAAP financial measures. Also please note that 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 third quarter net income attributable to HFC shareholders of $342 million or $1.93 per diluted share. Third quarter results included lower of cost or market inventory valuation adjustment that decreased pretax earnings by $18 million. Excluding this item, net income for the current quarter was $351 million or $1.98 per diluted share versus adjusted net income of $202 million or $1.14 per diluted share for the same period last year.
Adjusted EBITDA for the period was $613 million, an increase of $159 million compared to the third quarter of 2017. This increase in earnings demonstrates our ability to capitalize on discounted crudes and strong product margins in our refining segment.
Our Lubricants and Specialty Products business reported EBITDA of $42 million, driven by a consistent rack forward sales volumes and margins. Rack forward EBITDA was $57 million, representing a 13% EBITDA margin. Rack forward EBITDA is expected to be between $200 million and $220 million for 2018 with an EBITDA margin of 10% to 15% of sales. Rack back EBITDA was negatively impacted by cyclical weakness in the base oil markets.
Global base oil production is at an all-time high as refineries are running at higher utilization rates than previous years. We anticipate pressure on base oil margins to continue next year.
We also closed on our previously announced acquisition of Red Giant Oil Company this quarter.
Holly Energy Partners reported EBITDA of $87 million for the third quarter compared to $75 million in the third quarter of last year. This growth was driven by the acquisition of the Salt Lake City and Frontier Pipeline as well as volume growth on HEP's Permian Basin crude gathering system.
During the quarter, we announced and paid a dividend of $0.33 per share totaling $58 million and repurchased $124 million of our stock. On September 13, our Board of Directors authorized a new $1 billion share repurchase program confirming our ongoing commitment to return excess cash flow to shareholders.
For the remainder of 2018, we expect strong diesel demand, combined with favorable differentials from Midland to Canadian crudes, will continue to support strong earnings in our refining business. Now I'll turn the call over to Jim for an update on our operations.
Thank you, George. For the third quarter, our crude throughput was 442,000 barrels per day, slightly above our guidance of 420,000 to 430,000 barrels per day. As mentioned in our last call, we had some operational issues in July with our El Dorado and Cheyenne FCC units that reduced our guidance. These units returned to service in July, and the remainder of the quarter saw good operations for our fleet. We also had a successful restart of the Woods Cross units in August.
Our consolidated operating cost of $6.05 per throughput barrel was 10% higher versus the $5.51 in the same period last year. In the Rockies, our operating expense of $11.72 per throughput barrel was elevated versus the $9.48 in the same period last year due to Cheyenne maintenance and Woods Cross repairs. Our Navajo plant ran approximately 110,000 barrels per day in the third quarter. And OpEx per throughput barrel was $4.69, essentially flat, versus the $4.62 reported in the same period last year. In the Mid-Con, our operating expense per throughput barrel was $5.07, slightly higher than the $4.63 in the third quarter last year. Both our El Dorado and Mississauga refineries were down for turnarounds in October and are both currently in the process of restarting and will return to normal operations in November. We expect to run between 410,000 to 420,000 barrels per day of crude oil for the fourth 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 third quarter 2018, we ran 442,000 barrels a day of crude oil composed of 37% Permian and 20% WCS and black wax crude oils. Our laid-in average crude cost was under WTI by $9.96 from the Rockies, $3.55 from the Mid-Con and $9.12 from the Southwest.
In the third quarter of 2018, we saw a continued economic growth on both domestic and international markets. This and high exports of gasoline helped to support the demand for refined products.
The gasoline inventories from the Magellan system ended the quarter at 5.7 million barrels, roughly 2.4 million barrels lower than levels on June 30. Diesel inventories ended the quarter at 7.5 million barrels, some 1 million barrels lower than the second quarter levels. Days supply of both gasoline and diesel in the group finished at 20 and 35 days, respectively.
Second quarter 3-2-1 cracks in the Mid-Con were $18.90, $22.53 in the southwest and $28.75 in the Rockies. Crude differentials widened across the heavy and sour slates during the third quarter. In the Canadian heavy market, third quarter differentials for WCS at Hardisty averaged over $22.25 per barrel, but recently, we have seen this differential widen to more than $45 per barrel as pipeline capacity limitations continue to impact prices.
Despite the high levels of apportionment on the Enbridge system exceeding 45%, 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 71,000 barrels per day at our plants in the Mid-Con and Rockies. We refined approximately 162,000 barrels a day in Permian crude in our refining system, composed of roughly 110,000 barrels per day at the Navajo complex and 52,000 barrels per day via Centurion at our El Dorado Refinery.
Midland differentials averaged the quarter at $12.65, and currently, we see the same differential trading at 750, as a result of increased requirements for line fill. We anticipate the differential to widen once again with this incremental demand being filled and stated of water levels until late 2019 when additional pipeline capacity comes on screen.
Third quarter consolidated refinery gross margin was $19.41 per produced barrels sold, a 38% increase over the $14.05 recorded in third quarter of 2017. This increase was driven by improved laid-in crude cost in the Southwest and Mid-Con regions. Our rent expense for the quarter was $72 million.
And with that, I will turn the call over to Rich.
Thank you, Tom. For the third quarter of 2018, cash flow provided by operations was $402 million, including turnaround spending of $40 million and the $121 million negative impact from working capital, primarily due to building inventories ahead of the El Dorado turnaround. HollyFrontier's standalone capital expenditures in the quarter totaled $60 million.
As of September 30, our total cash and marketable securities balance stood at $1.076 billion, a $96 million increase over the balance on June 30.
During the quarter, we returned a total of $182 million of cash to shareholders, comprised of a $0.33 per share regular dividend totaling $58 million, as well as the repurchase of approximately 1.8 million shares of common stock for $124 million.
As of September 30, we have $1 billion of standalone debt and no drawings under our $1.35 billion credit facility, puts our liquidity at a healthy $2.4 billion and debt to capital at a modest 14%.
Total HEP distributions received by HollyFrontier during the third quarter were $37 million, an increase of 13% over the same period in 2017. HFC owns 59.6 million HEP limited partner units, representing 57% of HEP's LP units with a market value of $1.8 billion at last night's close.
For the full year of 2018, we continue to expect -- to spend between $400 million and $430 million for standalone capital and turnarounds at HollyFrontier refining and marketing; $80 million to $100 million at HollyFrontier lubes and specialty products, including the scheduled turnaround of Mississauga base oil plant; and $45 million to $55 million of capital for HEP.
And with that, Carina, we're ready to take questions.
[Operator Instructions] Our first question is from Paul Cheng with Barclays.
George, on the buyback authorization, $1 billion. How should we look at that? If the market condition is similar to what we've seen, is the third quarter pace is a reasonable run rate going forward?
Paul, I don't think there's necessarily a run rate. As we've discussed, we're going to continue to return excess cash to shareholders. As we're well aware forecasting the market is pretty much impossible in our business, so it's hard to say what the rate is going to be. But again, we hope that the -- what we did in the third quarter is an indication of our commitment to return cash to shareholders going forward.
No, I totally understand. That's why we tried saying that, "Yes, the market condition remains similar," should that be a reasonable proxy? Or that is still not a reasonable proxy?
I think, Paul, that all depends again on what else we see available to us. We've been pretty consistent with our capital allocation strategy of first and foremost, reinvesting in our existing business, things like turnaround and sustaining capital and the like.
Again second is dividends. We view those first 2 as pretty much nondiscretionary. Then you get into, again, the discretionary buckets, of which there are 3: growth projects to further improve our asset base; M&A activity; and the end of the buybacks. So we want a balance between that portfolio of opportunities.
And then final one on the refinery throughput, the third quarter definitely is better than what we initially expected. And so when we're looking at in the fourth quarter and going forward, maybe It's more like next year. George, are you still comfortable with saying that on a 12-month basis that you would be able to run at 450,000 to 470,000 barrel per day on the crude throughput?
Absolutely, Paul, that's our expectation. When we don't have a turnaround activity, we expect to run at capacity, which is 500,000 barrels a day. We're blessed to be in markets that are not short of product with the incremental barrel comes from somewhere else. So we typically don't have market constraints to our ability to run crude. And as you said, what happened in the third quarter, and I think Jim described it very well in his prepared remarks. Also, when we had our second quarter earnings call, we signaled the issues we had in July. The market responded accordingly. But again as Jim said, August to September, when the margins, both the crack spreads and crude disk were the widest. Our operation teams did their best. And we ran at the high end of the range of where we expect it to be.
Your next question is from the Manav Gupta with Crédit Suisse.
I had a couple of quick questions. In the past, you guys have indicated that you would like to expand your refining footprint. And there are news out there that Pasadena refinery is up for sale, and a global major is interested. So I just wanted know if your views, if you look at that asset and if you passed it and why?
Well, I don't think we want to get in any specifics on individual assets. I think your first statement is correct, we still have a desire to grow across all 3 of our businesses, refining, midstream and lubricants. And I think it's fair to say we look at almost everything that comes out of the market, and we'll act according to what we see and what we like.
Yes, that's fair. And on the lubricants, you're indicating that the rack back margins are a little weaker because of higher runs. But would that in any way inhibit your desire to grow in that business? Or you would actually like to take advantage of the weaker rack back margins to grow your lubes footprint in this environment?
No, I think we would like to grow our lubricants business, both in the rack back and rack forward. Our preference would be on the rack forward. That's where the majority of the EBITDA comes from, and that's where the margins are stabler and higher. That's one of the strategies that we have for our existing business is to continue to forward integrate from rack back into rack forward with the Red Giant acquisition being one example of how we're actualizing that strategy.
And on the RINs side, the RIN price is now down to $0.07 per gallon. So is there -- would you like to reissue at some point a RIN cost guidance, which will be materially lower than what you're spending in 17 and '18?
No, Manav, we're not going to guide. The most impossible thing for us to call is the RIN price. Right, that's impossible for us to guide spending there. We do expect keep -- please keep in mind that the way we account for RIN is on a weighted average cost of inventory basis. So we do -- effectively, what we see running through the P&L lags to the market. So we'd expect to see our cost of RINs trending down in the near term, next few quarters. Beyond that, I don't think we have any more visibility than anybody else does to what the RIN price will do.
That's fair, but do you think this headwind is finally being neutralized now? Or do you think it can come back from the dead and trouble the refiners again?
That's always a tough one to call because you're in the government affairs realm, and you never know what's going to happen in Washington. But we expect what we're seeing now to continue but obviously, no guarantees.
And the last one, the sour crude has slipped to a contango. Do you expect that to help the Cushing overall inventory situation and Cushing to build just because the economics now works in the favor of storing crude at Cushing?
Yes, Manav. This is Tom Creery. Yes, with the markets looking from backwardation to contango is certainly is going to help the Cushing market to build inventories. We're still forecasting a slow build through the course of next year and probably peaking sometime in the fourth quarter.
Neil Mehta with Goldman Sachs.
So first question for me is just on Western Canada, certainly a big part of the performance that we saw, that performance we saw in the Mid-Continent. Can you talk about getting access to those barrels? And so first of all, thoughts on apportionment and that how that's impacted your ability to actually procure barrels? And in general, how we should think about the number of WCS that you're able to put into the facility? I think you mentioned there was 71,000 barrels a day, but just can that grow over time. So that's my first question, I have a follow-up.
Yes, Neil, it's Tom again. We don't see any big changes in the apportionment level on the Enbridge system going forward. As you're well aware, until line 3 gets expanded, there's not much that they can do. And the only other clearing mechanism at this point in time is rail, which is averaging around 225,000 barrels a day and hopefully getting to 250,000 by year-end. So that's not going to be a big game-changer. So we expect apportionment to stay at these levels for the foreseeable future. And our ability to get more barrels, it's difficult as you can well imagine, to supersede the process that's in place to get more barrels through the Enbridge system. We've got some other deals in place and that have been in place that helped us move some barrels around in the system to get over and above our apportionment levels, and we're working with trade partners. But other than that, there's not a lot of growth potential at this point in time that we can see. And I think everybody is faced with the same conditions.
How do you think that -- how do you see that WCS differential evolving over time? Obviously, it's particularly weak now because of PADD 2 turnarounds. But do you see that tightening up and to what level, as you get into 2019 and then again into 2020?
Yes, the other big factor is storage in Alberta is now full. So I think they've got 75 million barrels of WCS either in caverns or tankage. So there's not a lot more out left that can happen there. So in terms of maybe production based, if we're lose some production over the course that may help apportionment. We saw this morning that Syncrude traded at $31 under, so It's probably going to get worse before it gets better.
Yes, Neil, Looking -- looking out, Neil, I think $40-plus differentials aren't going to be sustainable forever. But for the near term through 2019, I think there's not going to be any pipeline capacity until probably late '19 at the earliest. Probably more likely in that 2020 with Line 3 project being the most likely. And then once you get into 2020, you're starting to talk about potential IMO impact on those heavy barrels because again, those are the barrels that contain the bunker fuel that's going to be impacted by IMO 2020.
Yes, this is tough picture for sure. The follow-up question I had was on gasoline margins. Diesel looks really good right now, gasoline effectively breakeven in parts of the country from margin perspective. You view this as seasonal weakness or refiners just running too hard at their demand problems. Can you just talk about what you're seeing on the screen, and how that affects the way you think about managing your product yield as well?
Yes, I think -- I can't remember our markets are different than the ones you are referencing. With our crude advantages, we'll just still continue to make gasoline. The incentives are there to optimize and maximize diesel over gasoline. And we, and I'm sure all of our peers, are doing whatever they can to continue to do that. But at the top part of your question, we think this is a seasonal. I think there will be run cuts in those regions, where again they are breakeven, to get back in balance. I think we're hearing some European refiners, especially hydroskimmers, are cutting back on the margin as well. So once you get to 0, I think you start seeing that corrective mechanisms come into place, and supply start to get cut back accordingly.
Doug Leggate with the Bank of America Merrill Lynch.
This is Kalei on for Doug. So my first question, just given the blots in WCS that began over this year, I think this sure is quite familiar with your heavy exposure but may not be so much with your Canadian light crude exposure. Like you mentioned Syncrude diffs are blowing out. I just wanted to know if you could remind us of your exposure to this Syncrude benchmark.
Yes, Kalei, it's Tom. We do produce supplies of synthetic crude and move it down the Express or to the Eastern refiners in the Mid-Con when economic conditions dictate. But usually what we found is that the heavy oil is a better choice for us based on economics. So we do, do that. But we do have a consistent movement down the Express pipeline to both Woods Cross and Cheyenne refineries. So we do have some exposure to it, but our exposure is much more heavily weighted to the heavy barrel.
Sure definitely. Would you able to quantify?
I think probably to Tom's point, it varies depending on the interrelationship with other light crude at the time. So there's not a consistent answer to that.
For sure, next question. Can you just give us your outlook on Midland spreads, and how that will evolve through the end of 2019, in light of the 2 early service announcements on Plains and Epic?
Sure. We thought, as everyone else did, we set some pretty wide differentials pushing $18, and then they came into $3 on the basis of both Epic and Sunrise. As Sunrise is finishing up their line filling procedure, we see the differentials tend to widen out $6 to $7. We expect that to continue in the foreseeable future until late 2019 when more pipe capacity comes on.
[Operator Instructions] Your next question is from Jason Gabelman with Cowen.
I wanted to ask a question about Cheyenne and Prop 112. I'm just wondering how much of the crude sourced into Cheyenne is local. And if Prop 112 does in fact pass, is there a concern that your crude that -- the cost of supplying crude into the refinery will increase, whether that's due to higher cost of locally sourced crudes, or if you have to source incremental crude from the Bakken and that if tightens up?
Yes. Well, we don't see that as an issue, Jason. Very little of our crude to Cheyenne comes from Colorado. So most of it comes from other states in the area, whereas Tom just mentioned, from Canada by the Express pipeline.
And if I could just push back a little bit on that, if there -- if it does pass, I mean, even if your crude is sourced from another state, is there a concern that maybe differentials tighten up from where those other crudes are being sourced from, and that would increase the cost of supply into the plant?
Not really. On the grand scheme of things with what's going on at Guernsey, the Guernsey market, with Bakken being so constrained to get to Cushing and highly discounted, what's going on at Colorado is really rounding error.
There are no further questions at this time. I'll now turn the call back over to Mr. Biery for closing remarks.
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 fourth quarter results with you in February.
Thank you. This does conclude today's teleconference. Please disconnect your lines at this time and have a wonderful day.