HF Sinclair Corporation (DINO) Q2 2013 Earnings Report, Transcript and Summary

Welcome to HollyFrontier Corporation's Second Quarter 2013 Conference Call and Webcast. Hosting the call today from HollyFrontier Corporation is Mike Jennings, President and Chief Executive Officer. He is joined by Doug Aron, Executive Vice President and Chief Financial Officer; and Dave Lamp, Executive Vice President and Chief Operating Officer. [Operator Instructions] Please note that this conference is being recorded. It is now my pleasure to turn the floor over to Julia Heidenreich. Julia, you may begin.

Good morning, everyone, and welcome to HollyFrontier Corporation's second quarter earnings call. I'm Julia Heidenreich, Vice President of Investor Relations. This morning, we issued a press release announcing results for the quarter ending June 30, 2013. If you would like a copy of the press release, you can find one on our website, www.hollyfrontier.com. Before Mike, Dave, and Doug proceed with their prepared remarks, please note the Safe Harbor disclosure statement in today's press release. In summary, it says statements made regarding management expectations, judgments or predictions are forward-looking statements. These statements are intended to be covered under the Safe Harbor provisions of federal securities laws. There are many factors that could cause results to differ from expectations, including those noted in our SEC filings. Today's statements are not guarantees of future outcomes. Today's call may also include a discussion of non-GAAP measures. Please see today's press release for reconciliations to GAAP financial measures. And lastly, please note that any information presented on today's call speaks only as of today, August 7, 2013. Any time-sensitive information provided may no longer be accurate at the time of any webcast replay or rereading of the transcript. And with that, I'll turn the call over to Mike Jennings.

Great. Thank you, Julia. Good morning. Thanks for joining us on HollyFrontier's second quarter earnings call. Today, we reported second quarter net income attributable to HFC shareholders of $257 million or $1.27 per diluted share. Our second quarter EBITDA was $521 million, which landed about 15% below the previous quarterly EBITDA of $611 million. Current quarter earnings were impacted by lower refining margins, narrowing crude diffs and refinery downtime within the HFC system, as well as higher regulatory costs. On a per barrel basis, our second quarter consolidated refinery gross margin was $20.28, which is about 13% below the $23.32 per produced barrel that we realized in the first quarter. Weaker diesel cracks in the Southwest and the Mid-Con regions more than offset higher gas cracks observed during this quarter. Since quarter end, margins have been softer, with the average Mid-Con 3-2-1 crack for the third quarter-to-date at about $20 compared to nearly $37 in the third quarter of last year. Still, crack spreads remained fairly solid despite what has been a large decrease in the inland coastal crude differentials. Generally, we're seeing refined product demand more or less in line with the past 12 to 18 months, and we have some measured optimism that a stronger U.S. economy and housing market will drive consumption increases, particularly on the diesel front, as we go forward. Our second quarter financial performance was affected by some onetime items, which included lower-than-expected crude throughput due to unplanned maintenance downtime and higher expenses related to pension plan termination and retirement of high-coupon debt. Dave and Doug will further elaborate on these items. A recurring discussion on these second quarter earnings calls has been impact of the Renewable Fuel Standard and, as a related matter, the potential for relief from this obligation. When speaking about…

Thanks, Mike. Second quarter throughput for HollyFrontier was 381,000 barrels per day with a total charge of 419,000 barrels a day. The crude slate was 21% disadvantaged crudes, mainly black wax and WCS, and 21% sour. The average laid in crude cost under WTI for our system was $3.82 per barrel. The Brent-WTI differential was $9.12 for the quarter. Just some other crude facts here. The WCS was about $19.16 under, WTS was $0.06 under and North Dakota light was $1.30 under WTI. Total refining and operating costs for the quarter were $254 million. Operating costs were higher due to charges related to the termination of our pension plan, repair costs related to unplanned outages at El Dorado and Cheyenne refineries, and a higher natural gas price. Total lost opportunity for the quarter was $169 million, the majority of which was from unplanned events in the Mid-Con. For the Rockies region, throughput was 71,000 barrels per day and 77,000 of total charge. Disadvantaged crudes were approximately 49% of the crude slate and 1% sour. Average laid in crude cost for the Rockies region was $9.46 under WTI. Refinery operating costs were $7.14 per barrel. At our Cheyenne Refinery, we had 2 unscheduled FCC outages and an alky outage, which resulted in lower crude rates versus planned. For the Mid-Con region, throughputs were 206,000 barrels per day and 226,000 barrels of total charge. Disadvantaged crudes were approximately 16% of the slate and 3% sour. We ran about 7,000 barrels per day of Christina Lake, a high-acid number crude, which sold at an average discount to WTI for the quarter of approximately $4.50 a barrel -- excuse me, WCS for the quarter of $4.50 per barrel. Average laid in cost for crude was $3.06 per barrel under WTI for the Mid-Con, and…

Thanks, Dave. For the second quarter of 2013, cash flow provided by operations totaled $203 million. Second quarter capital expenditures totaled $87 million, excluding HEP's $11.8 million capital spend. Turnaround spending in the quarter totaled $90 million, and we maintain our full 2013 CapEx guidance of $400 million to $450 million, and are slightly raising our turnaround spending budget to approximately $200 million due to turnaround discovery work. As of June 30, 2013, our total cash and marketable securities stood at $2 billion versus $2.5 billion at March 31 of this year. HollyFrontier debt totaled $191 million, excluding non-recourse debt to HEP of $799 million. In the second quarter, we distributed $163 million in dividends to shareholders and declared $61 million in dividends, which were paid early in the third quarter. Year-to-date, we repurchased approximately 3.2 million shares at an average price of $46.13, leaving $356 million of our current repurchase authorization remaining. Also worth noting, our July 31 share count stood just below 200 million shares outstanding. Since our July 2011 merger, HollyFrontier has returned more than $1.7 billion in capital to shareholders through regular dividends, special dividends and share repurchases, including today's announced dividends. I'd like to mention a few additional nonrecurring charges that impacted the quarter. All of the following numbers are pretax. We incurred a $31 million charge related to the termination of the company's defined benefit retirement plan and expect to incur an additional $9 million for final termination in the third quarter of this year. Additionally, the company recorded a loss of $22.1 million due to the redemption of our 9 7/8% notes due 2017 in the third quarter of this year. In the quarter, we also recognized a $10.6 million insurance settlement relating to the Tulsa fire that occurred last summer. Lastly, I'd like to update you on our quarter-to-date crack spreads. These are all based on West Texas Intermediate crude, not on the advantaged crude oils that we run in our refineries. For the Rockies region, the gasoline crack spread averaged about $19 for July, and the diesel crack spread, $22 for July. Moving to the Mid-Continent, the gasoline crack spread averaged $18; the diesel crack spread, $21; and the lubricants at our Tulsa Refinery averaged $58 for July. Lastly, for the Southwest region, the gasoline crack spread averaged about $19 for July; and the diesel crack spread, $22. With that, Laurie, I believe we're ready to take questions.

[Operator Instructions] Our first question comes from the line of Arjun Murti of Goldman Sachs.

First question was just on maintenance activities going forward. Your coming through a period here where you've had a bunch of planned downtime and I think, unfortunately, some unplanned downtime. Can you provide an outlook for the rest of this year and maybe 2014? On the unplanned part, clearly part of the business. All companies have it. Is there anything that makes you more concerned that you have to spend a bunch more money to address issues that you may have found? Or can we just chalk it up as "stuff happens" and hopefully won't going forward?

Well, for the rest of this year, we have the Cheyenne turnaround, which is a crude unit reformer and diesel hydrotreater, to address. And that's a fairly major turnaround, but that will be complete in the fourth quarter. As far as next year goes, it's pretty -- I'll call it a lighter year, although we do have some outages that are -- like an FCC outage at El Dorado that we have to complete. So that's the biggest one we have next year. As far as the lost opportunities go, I will say things happen. But I think we try to minimize these events every day as best we can. I don't think we have a systemic cause that has to be addressed in any way. It's just good plant operations every day that prevent these kind of things.

A little more color on that, Arjun. We had a cat cracker turnaround at the Navajo Refinery early in the year, which is a gas oil building event, and also had 2 cat cracker unplanned outages at Cheyenne and El Dorado. It was a bit of a perfect storm in that our company accumulated these intermediates, all of which needed conversion capacity, and we lost a lot of crude rate as a result, starting with an extended turnaround at Navajo and sort of a train of events across different plants. We think that's a pretty unusual situation and don't think that we're more susceptible to unplanned downtime than the industry.

That's great. And then, the RINs comments are interesting, and I think we read the EPA announcement, very similar to you all. It was remarkably clear on recognizing the blend wall and the limitations of the current rules. But they didn't actually, at least as of now, change the 2014 requirements. So I'm curious if you can provide any comments on how you'll approach your RIN strategy. It seems like they're going to change the rule for the better, but they haven't actually done so yet. Are you still looking to increase your amount of blending capacity and reduce your exposure to having to purchase RINs? Any color there would be helpful.

Yes, absolutely. I mean, that's a core part of our strategy, is to try to blend more ethanol. In so far as the RIN makes a difference, we make jet fuel as opposed to ultra-low-sulfur diesel at the margin. And we're obviously doing those things in terms of rack pricing to try to offset those impacts of the RIN. So I think we've got a lot going on internally and marketing-wise, a lot going on in terms of our government relations in Washington as well. And so you're right, the EPA didn't go so far as to make changes for 2014. It wasn't our expectation that they would. But looking forward through the next, call it, 6 months, I think they've made, as I said, explicit recognition that there's a problem. And the blend wall is sort of so extreme next year that we believe they will act and mitigate that, making E10 the likely resting point, at least for the foreseeable future.

Your next question comes from the line of Paul Cheng of Barclays.

Doug, on -- maybe I missed it. If I did, then I apologize. Did you say that -- how much is your RIN cost in the second quarter?

Paul, we didn't. As we look at where our peers are in terms of that disclosure and where the industry is sort of heading, we feel like we're already at a disadvantage in that refiners are the obligated party having to buy RINs. And so telling the market what we've purchased or what we have left to purchase and what that cost is, is not something that we feel like we're going to provide going forward. What I think you could glean from Mike's comments and from what we've said earlier, Paul, is that we have about half of our total manufacture is -- half of that gets blended, the other half we have to purchase. And I think we said in previous calls that at an $0.80-or-so RIN cost, you would expect us to spend somewhere in the $125 million to $150 million annually. Beyond that, I think you'd look to previous presentations and guidance.

Okay. And Mike, earlier, that you say in your market, you start to believe that the bulk of the RIN cost is being passed through. I just want to make sure that I understand, is that when you sell the neat gasoline without ethanol, let's say you sell to airport, that basically is the airport, not seaport. And the corresponding airport and seaport as a branded gasoline that when you sell, your neat gasoline would be several pennies higher than that. Is that what you're referring to?

Okay. I'm referring to prices at the racks, not our own company pricing. And then generally speaking, the clear or neat gasoline in these racks and markets that we serve is reflecting the difference in the RIN cost. So at the today's prices, maybe a $0.10 higher than the blending -- or then the E10 blended price.

Okay, very good. Dave, earlier that you say the opportunity cost for the outage is about $169 million, primarily in El Dorado. Do you have a -- what's the component about the unplanned outage?

Well, unplanned outages were -- as we mentioned, El Dorado was a big piece of it. Cheyenne was the other one. Both El Dorado and Cheyenne were FCC related. And Tulsa then also had a crude unit outage, which caused the starvation of downstream units, which had a large impact. Those were the main drivers of the $169 million.

So the $169 million, you said, include the planned outage or it's just the unplanned outage?

No, just the unplanned, just unplanned.

Oh, that is just unplanned?

Yes.

Do you have a rough breakdown between Cheyenne, El Dorado and Tulsa in terms of percentage? What percentage out of that $169 million?

Well, it's -- the Cheyenne was about $20 million, El Dorado was about $66 million and Tulsa was around $70 million.

So Tulsa -- now Tulsa is actually even bigger in terms of the impact?

Yes. Tulsa and El Dorado were pretty close to each other, but they're both large.

I see, okay. And do you have -- what is the estimate? We think -- because I think this relate to the lost profit, right?

Yes.

Is that including the repair costs?

In some cases, yes. In some cases, no. We had mentioned an operating cost, that we incur a higher operating cost to repair 2 FCCs. So a lot of it...

Do you have data that you can share?

A lot of it doesn't have repair costs, Paul, but some does. And we will call those out.

Okay. What is the incremental repair cost then?

I don't have that number off the top of my head. It's small by comparison to the lost margin opportunity, Paul. If it's 10% or 20%, that would be a big number.

Okay. Two final question. One, in July, did you buy any stock back?

There's a relatively small number under a 10b-5 program, Paul. That was included in the total year-to-date number that I gave previously.

Okay. Is that because that you are in a quiet period? Or do you just -- how are you looking at that?

Yes, it's -- again, that's 3 point -- I don't have exact breakdown of what was in the second quarter versus July. But the -- it's more difficult when you can't actively manage that program. 3.2 million total includes -- I would tell you -- I want to say it's a few hundred thousand shares purchased in the month of July.

Okay. A final one. Doug, do you have a number? What is your market value of inventory in excess of the book?

We do, Paul. It was $405 million above the book value.

Your next question comes from the line of Chi Chow of Macquarie Capital.

Mike, in your remarks, you mentioned that you think that E10 may be the resting point on RINs next year. Do you believe the RIN price then will stabilize in 2014 kind of where it's been trading at this year, say, $0.80 to $1? Or do you think the price will trend differently going forward?

It's obviously speculative, Chi. I think the one thing that has driven RIN prices this year is people, market participants have been buying and holding these in anticipation of addressing the 2014 obligation. And if you look at the blend wall, that's probably been an intelligent strategy. If E10 is a resting point, I think the pressure is off. And in theory, more of an administrative value of the RINs becomes appropriate as opposed to a premium that reflects shortage. I don't how the market will actually trade, but I do believe that people were buying and holding in advance of an expected blend wall in 2014.

Okay, great. That's helpful. Doug, on your crack spread hedges, was there a gain or a loss in the second quarter you can disclose, both realized and unrealized?

Yes, there is. We had realized from the -- well, I'll call it accounting hedges. So that was the crack spreads, $6.6 million. That was slightly offset by some crude hedges that we have in excess of our base levels of inventory. The net number for the quarter, all in, was, let's see here, about $7 million positive, total, which includes unrealized gains on the accounting hedges of $3.7 million. So pretty small numbers in any case, Chi.

Okay, okay. And the unrealized, was that a gain also, the $3.7 million?

That's correct. That's correct.

Yes. Yes. And any changes on your hedge positions going forward?

We've added some 2014 ultra-low-sulfur diesel hedges. We've got about 17.5 thousand barrels sold for 2014 in the $28.25 range.

$28.25. Is that pretty ratable on the volumes through the year?

It's completely ratable. It's 14 -- it's 17.5 thousand barrels a day times 365.

Your next question comes from the line of Roger Read of Wells Fargo.

Just want to follow up maybe a little bit on the dividend, the share repurchase program. I mean, obviously, I understand where you are at the moment. Historically, you've talked about maybe shifting from a -- the special dividend, maybe shrinking it and a larger, regular dividend. Can you just sort of update us on your thought process right there?

Yes, the regular dividend, we've grown pretty significantly over the last couple of years. With continued ability to do that, I think we continue on that path. When that starts to consume the special, I can't really project. We've looked at our total dividend payout as a function of our earnings statement and, obviously, our balance sheet capacity to make those payments. We're in a very good position in both respects right now, but it is something that we look at quarterly. So I guess what I'd say as underlying themes, we continue to be a returns-focused company. Cash returns to shareholders are a big part of that in our view, and our expectation going forward is that we're going to continue to emphasize those. At what levels and at what point the regular subsumes the special, I can't really speculate on.

Okay. And then maybe how you think about the share repurchase program within the overall process. In other words, is there a potential to ultimately up that, maybe back off the special? Or just what pressure could that put on the overall dividend policy maybe is a better way to ask that question.

Yes, that's a function of price. And we -- we're commercial about our repurchase program. We consider the 3 pieces in terms of regular, special and repurchase all as investments in shareholder value. But we buy more stock when it's cheaper is what I would tell you. And if it gets materially cheaper, then it could be emphasized to a greater degree. It's just depends on price.

Okay. And then my last question, kind of again sticking with this whole cash flow focus. Capital expenditures, I mean, obviously, you know where we're going to be for '13. A lot less turnaround is coming next year. So maybe, less opportunities for sort of elective spending. I understand what you're going to do in terms of the Wood River expansion, but where else can spending go? Is it generally going to trend lower over the next year? Or should we expect it to be at kind of similar levels? Within whatever framework you can put that would be helpful.

I think that we're going to push that to the November call. We've got -- obviously, the Woods Cross expansion is going to be in fairly high spend mode next year. Beyond that, we still have some compliance activities in terms of wastewater and air emissions. Whether there are additional projects or not, we really don't have that answer yet. So I think we'll push the capital discussion to the third quarter call.

Your next question comes from the line of Robert Kessler of Tudor, Pickering, Holt.

I want to see if you could provide some comments about the Canadian spreads and market. Obviously, the narrower spreads in the Canadian prices has an impact on your market. A lot of maintenance going on there on the upstream side. And at the same time, of course, new refining capacity at Whiting pulling more out of the market for Syncrude in the short term, and then presumably bitumen by year end. So in light of all the changing dynamics there, can you give us some color on what you see as the outlook for Canadian diffs?

I don't know that we have a great crystal ball that's any better than yours. The -- one comment we'll make is production is increasing bitumen. And that is -- we view that as positive. And the price-setting mechanism is freight to the -- ultimately to the Gulf Coast, which is highly constrained. So we think we're not in a bad position considering those factors, but who knows where it'll go.

I just would add to that. We -- because of that uncertainty, we've disclosed in previous calls that we've tried to have a bit of a foot on first and a foot on second base by doing some forward contracts with producers at what we consider to be attractive rates. Julia, I don't know if we have -- we -- I know we've got it in previous transcripts, but 45,000-or-so barrels a day contracted in the sort of $23 a barrel range, which has been sort of right in the middle of where the market's been. It's been higher, it's been lower. We see that as an attractive crude, particularly at our El Dorado and Cheyenne refineries. And I think that there will continue to be volatility in that, as there is in TI-Brent. But are well contracted, on some volumes anyway, for the next few years.

And one thing that might add some additional insight, and this may be master of the obvious, but look, the Canadian barrel is going to trade somewhat in sympathy with the Brent-TI spread. And if you think about the Canadian in context of my end [ph] delivered Gulf Coast and then transportation costs, a lot of that crude has been attempting to get on the rails. And with a Brent-TI spread of $10 or $15, that's a pretty easy transaction. But when Brent-TI comes in considerably, as it has, that rail shipment is less economic. And therefore, the differential against TI has to widen. Obviously, that's a benefit to us. So I do think it's affected significantly by what the inland to coastal sweet diff is going to be.

And on that inland to coastal sweep diff, I mean, obviously, if you look today, it seems like the Cushing-to-coast or Cushing-to-LLS differential is still technically at or above the cost of transport. Do you foresee a scenario in the short term, whether it's due to line fill or otherwise, where you might have a narrowing below the cost to transport between those 2 markets? Or would that be a firm floor even in the short term?

I don't think there's any firm floor in this business. You've got the potential for some cost economics. Obviously, in line fill scenarios, the price is completely inelastic because you have to produce the line fill barrels. So there will be volatility near term. But longer term, as we've said expressly, we think that the transportation costs will be reflected in the differentials.

Your next question comes from the line of Jeff Dietert of Simmons.

You guys had a nice sensitivity table in one of your recent presentations on RINs cost versus blending economics, a little different look than I think some have had. And we could look at Bloomberg and get a general idea on where RINs prices are. They may vary from region to region, but at least we can get in the ballpark. Could you talk about the blending economics and kind of where they were in 2Q and what you're seeing in the current market?

Well, they've been very strong, Jeff. It's -- lately, ethanol is in the $2.30 range. Gas is $2.80, somewhere in that, at a wholesale level. So you've had a pretty good blend incentive depending on transportation, to get the ethanol, too, wherever you're blending to. In our markets, it's been as high as $0.30 and as low as $0.05. And it's -- moves all over the place. But pretty strong incentive to blend.

And more incentive in 3Q than 2Q or the other way around?

It got a little narrow in the beginning part of 2Q, but then widened out. And right now, it's kind of at the current numbers I was telling you.

Your next question comes from the line of Sam Margolin of Cowen.

I wanted to circle back to an announcement you had last quarter about the Navajo rail facility. And recently, there have been some pretty optimistic results out of -- around where you're at there and also all over the Permian. And I was wondering if there's been any sort of progress made or indications that it's easier to find partners, both on the loading side for supply and then maybe even for offtake as well, given the increase in production outlook in the area.

Well, as we've developed the project, basically what we were offering basically to the market, a service of supplying and loading crude into a customer's railcar. We are still in the process of developing that market to see if there's some interest in that and then tie it to our Permian Basin gathering system. And where -- as production grows to a certain level, that could be a key outlet. We really haven't made much progress in terms of securing any customers that will lead us to proceed with the project, but continue to evaluate it.

And just one last thing, touching on RINs, and I realize at the risk of broaching some competitive areas where you can't really comment. I thought that in addition to the 2014 comments, you had the 2013 extension as well. And if the expectation is that 2014 is going to be eased for gasoline producers and merchant refiners, if there's any change in strategy, just day-to-day, in terms of purchasing activity? In other words, if you have that extension, it's unclear why anybody would be buying a RIN right now at all if you think that 2014 is going to be addressed.

Yes, that's on the other side of the line, I'm sorry, but we're [indiscernible].

It's all right. Okay.

Your next question comes from line of Blake Fernandez of Howard Weil.

I had a question for you. I know you've already addressed the CapEx in '14 maybe being addressed later in the year. But I wanted to focus specifically maybe on Woods Cross Phase 2. It seems like that's really one of the key drivers for incremental CapEx into the future. And it looked -- I'm just trying to kind of clarify what's needed in order to get that project kind of launched? And if you could give me a sense of maybe lead time? It looks like prospective completion will be in '16. Does that -- would that need to launch in '14 or '15 in order to accomplish that?

Well, currently, we're in development of the Schedule A, which is the front-end engineering of that particular Phase 2. So that work has to be completed, and that includes pilot plant work to ensure that we can make quality the lubes that we believe we can from the feedstock we have. To make the project really go any further than that, go beyond that, we'll get a good, solid cost estimate out of that and have a design basis and then have security around knowing that we can make the quality lubes. We still have an issue on supply of black wax, and that's the -- fundamental to the project, is having enough black wax secured to allow us to capture the yields that we're talking about. So those are the major impediments. I think we'll address most of those issues, with the exception of probably the black wax supply, this year. But the black wax will be a continuing saga on additional supply.

Okay. So it sounds like there is a chance some of that spending, if approved, could fall into next year then?

It's possible.

The only other one I had for you is on the buybacks. I'm not sure if this will be for Doug or Mike, but it looks like, obviously, your appetite has increased as of late. And with the authorization at about $350 million, it seems like you'll exhaust that fairly quickly at this run rate. I'm just curious, is there any time frames or markers we can think about a board approval of additional authorization?

Blake, I would say that similar to our RINs comment, I mean, we're -- we don't want to be pinned down to what level, what price and what volume. As Mike sort of said, we view it as opportunistic. We saw a chance, when we saw the shares selling off hard during the second quarter, to be pretty active and aggressive. And what I would say is our board evaluates dividends and other distributions, including share repurchases, quarterly, when we meet with them. I don't think getting an additional authorization, if we saw value in buying the shares, would be a difficult task with them. But it's going to be a bit dependent again on where share price is and what other opportunities exist.

Your next question comes from the line of Doug Leggate of Bank of America Merrill Lynch.

Mike, I'm sorry to be on the dividend, share buyback issue, but if I could just again take a step back from this and ask you that, we've seen differentials come in quite a bit. And it seems that with the special dividend policy, you've been kind of treating that as a windfall. But your commentary sounds pretty optimistic that we're going to reopen again and see something of a sustainable differential. So what -- why not be more committed to this inability of the kind of cash flows you're seeing, given your balance sheet, by backing away from the special one to more balance between the ordinary and the buyback?

Well, Doug, I guess it just reflects an underlying conservatism and sort of a pragmatism in the way we view our business. And in these cyclical businesses, you sometimes see a company out there that's going to claim to grow earnings $15% a year irrespective of the cycle. And 2 or 3 years into it, it ends up being a failed strategy. Our view is not that. We're not independent of the operating environment, the margin environment, in terms of our cash distribution strategy and our cash distribution strategy. And it also allows us more flexibility in terms of our share repurchase program. And getting the timing right in terms of both external investments and investments in our stock has big difference in terms of level of returns generated. So I guess we value the flexibility. And yes, we do think, long term, that this business has good sustainability and better margins than in history. But that's a longer-term view. And at any given point in time, things can be different than that. So we want to retain the flexibility to be opportunistic.

Doug, I would add to that, that we've raised our regular dividend 5x since we've been a merged company and stand at sort of a top quartile yield among our peer group, and don't hold our heads in shame about the regular dividend. We continue to expect to grow that over time.

Yes, I kind of understand that, fellows. I guess what I'm thinking, I mean, to your point, Mike, you took advantage of share price pullback in the second quarter. You don't really get any sustainable benefit from special dividends, but you would do by reducing your share count. So I guess I'm just kind of wondering why the special and why not a little bit more allocated to the buyback. I guess that was really what I'm saying.

Yes, and the simple reason for that is that in a quarter where the shares are priced strongly and perform strongly independent of a buyback, our inclination would be to buy less. And we get to the quarter end, and we find that we've grown the liquidity position, grown the balance sheet. And the shareholders are wondering, what about shareholder distributions? The dividends provide a steady distribution to address that with the repurchase program being more opportunistic.

My follow-up is really reflecting on some of the other companies that reported in terms of what's going on with butane and various different feedstock opportunities, I guess. Haven't really heard you guys talk much about incremental projects beyond Woods Cross? And I'm just curious, things like alkylation units and taking advantage of the butane prices and so on, is there anything in the pipeline that we haven't really explored or you haven't shared with us yet in terms of where you're -- how you can continue to incrementally invest in that existing plants rather than acquisitions? I'll leave it there.

Certainly. Yes, we've looked throughout our system, as most refiners do. And then we have a list of projects, many of which will never get funded, frankly. But some which probably will. And we look particular at those that have a feedstock advantage that we feel is durable. I'll give you an example. Our Cheyenne Refinery is located within 1,000 miles of the Hardisty merchant point for Canadian crude. And it's set up with a coker, but is short gas oil conversion capacity. Through time, that refinery probably would reward investment in further cracking capacity, be it hydrocracking or cat cracking, and we're looking at that hard in the context of what we expect future crude differentials to be as well as local refining margins. So we look toward projects that will increase liquid yield, that will take advantage of feedstock differentials, not necessarily generic expansions in refining capacity. But we're not ready to showcase any of those yet. And there may be some that come forward, if they meet our own internal thresholds, and we'll talk about those with the market when we're ready.

Remember too, we have Tier 3 gasoline specs coming too, which sometimes creates some opportunities for these type of investment that Mike is talking about. We always try to find ways to make money with those regulations with our capital programs, and I think some of those will come out of that Tier 3 specs.

Got it. I just got to ask you the final question. Is there any plans to hold an Analyst Day to maybe share some of that stuff with us? And I'll leave it at that.

Yes, when we get to the point of having information to share, we'll do a good job of sharing that with the marketplace. But for the time being, we're going to stick with what we've said our strategy is. Our expansion is principally focused on Woods Cross at the time being. That project has been pretty well documented. The Phase 2 project that's potentially behind it has also been pretty well documented. And obviously, one of the gating items is getting crude supply for that project. So yes, we will do a good job in communicating with the market as to what incremental internal investment might come. Right now, we're not ready to do that.

Your next question comes from the line of Ed Westlake of Credit Suisse.

Yes, thanks very much for the update, particularly on the opportunity costs in the first half. Because obviously, as -- we love to see what the assets will do when they're up and running properly in the second half and into next year. A quick question just on that potential for sunk cost economics comment that you mentioned. I mean, how likely do you think that, that is, when you're thinking about pipeline tariffs given that they are so important, particularly to your sort of Southern Mid-Continent assets. Obviously, in the North, Canadian and Bakken might trade on other fundamentals, but any color on that sunk cost economics and pipelines would be helpful.

It's tough to gauge. I think during line fill periods, you can probably count on it. Or at least, that has been our experience in the past. When you think back to the Keystone line fill, to the Magellan Longhorn conversion line fill, those things tend to consume crude differentials very rapidly, and then things tend to revert. As to how this plays out going forward and what the likelihood is, obviously, dependent on just good old supply and demand. But I don't think we're ready to speculate about that.

And then on logistics. I mean, obviously, there's the rail project. There's a few smaller pipeline projects around the Tulsa Refinery. I mean, any sort of other logistic opportunities that you're considering as the crude landscape changes?

Well, the greatest of our logistics capacity, combined with our partner, Holly Energy Partners, obviously, is around the Navajo Refinery. And they're doing good work in expanding that gathering system, meaning that we're becoming less dependent on purchased merchant barrels and getting access to more gathered barrels out in the Permian, particularly with the great work that's going on in the Delaware Basement -- Basin. So that's going to be the principal focus. There are also opportunities around the Cheyenne Refinery, which we're not going to document yet. But with the proliferation of preproduction right around us, we are working with Holly Energy Partners to gather more barrels.

And then on the confidence in dividends and specials being sustained, obviously, despite the narrower headline cracks that people are seeing in the third quarter. I mean, is that a function of your views around sustainability of these cracks or a function of your assets are going to be running better in future years and hence, you can support at that level of cash flow?

What I would tell you, Ed, this is Doug, I think, again, the board, as they have, will evaluate that with management's recommendation every quarter. And it's a part function of our current earnings stream, and also a part function of our current balance sheet. And so, until we get to a point where either the earnings or the balance sheet won't sustain that dividend, it's something that we would continue or expect to continue the board to approve. And when we get to a point where, if we have a sustained or prolonged downturn, where we don't have the earnings and we eat into our existing cash position, then we'd have to revisit that with a much harder look. For now, I don't see that as being a concern for us. And as Mike pointed out, yes, there will be volatility, but we would see those differentials returning. So perhaps, it continues on into perpetuity, absent other opportunities for us.

Your final question comes from the line of Paul Cheng of Barclays.

I just have a quick question. Navajo, how much is the oil that you currently run this [ph] from your own gathering system?

How much oil per [indiscernible]. At Navajo.

Paul, it's approximately, in the -- our Artesia gathering system, we do about 45,000 to 50,000 barrels a day. And that's out of 100,000.

Okay. And then, Doug, you gave the July number on the gas and diesel crack. Do you have the second quarter number?

I do, Paul. Rockies gasoline, $32; Rockies diesel, $33; Mid-Con gasoline, $28; Mid-Con diesel, $30. Mid-Con lubricant, $72; Southwest gasoline, $26; Southwest diesel, $28.

Okay, great. And that, Dave, you earlier mentioned that Tulsa, because of the storm, you got locked out for 7 days. Is this that whole plant down or is a certain unit down?

No, just the reformer and the Coker, Paul, only. So we experienced a little bit of crude cut, but we're through that now and back up.

So both the throughput and the earnings impact should be relatively small then?

I would expect it to be relatively small.

The crude impact is in the number you provided right there.

Right, yes.

And Mike, I think you guys have been looking at initiative how you can reduce the product pricing pressure during the wintertime when the demand is weak. Can you elaborate a little bit more on that?

Certainly. For context, the Mid-Con demand seasonally decreases, frankly, more than any -- many parts of the country, the difference between summer, winter is probably up to 20%. And so the issue is what to do with barrels of product when the refineries are running full in the winter. Our strategy has been, and is to expand our marketing footprint. We are gaining access to new markets, and I'm not going to go beyond there. But in the near term, I think we're looking toward being able to place between 10% and 20% of our production in markets that we haven't served previously.

Your final question comes from the line of Chi Chow of Macquarie Capital.

I'm sorry, I forgot to ask about the backwardation in the WTI structure here in the quarter, current quarter. Is that going to impact all of your crude purchases? Or do you get some relief from your Canadian barrels or other barrels? Can you talk about that?

It affects most of what we purchase, Chi. And the Canadian barrels are obviously priced on a little different basis. But our internal strategy is to hedge many of those barrels forward to their delivery time. And hedging into a backward curve, you obviously bear the burden of that downward slope.

At this time, there are no further questions. I will now turn the floor back over to Julia Heidenreich for any additional or closing remarks.

Thank you, everyone, for joining us this morning. If you have a follow-up question, feel free to reach out. I'll be here all day. Otherwise, we look forward to sharing our third quarter call in November. Thank you.

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