HF Sinclair Corporation (DINO) Q1 2013 Earnings Report, Transcript and Summary

Welcome to HollyFrontier Corporation's First 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 this conference is being recorded. It is now my pleasure to turn the floor over to Julia Heidenreich. Julia, you may begin.

Good morning, everybody, and welcome to HollyFrontier Corporation's first quarter earnings call. I'm Julia Heidenreich, Vice President of Investor Relations. In addition to Mike, Dave and Doug, we also have members of our management team to assist with Q&A. This morning, we issued a press release announcing results for the quarter ending March 31, 2013. If you would like a copy of today's 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's 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 outcome. Today's call may include discussion of non-GAAP measures. Please see the press release for reconciliations to GAAP financial measures. Also, please note that information presented on today's call speaks only as of today, May 7, 2013. Any time-sensitive information provided may no longer be accurate at the time of the 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 first quarter earnings call. Today, we reported first quarter net income attributable to HFC shareholders of $334 million or $1.63 per diluted share, which compares favorably to the $242 million or $1.16 posted in the first quarter of 2012. First quarter EBITDA generated was $611 million, 30% above first quarter 2012 EBITDA of $471 million. These strong earnings were driven by high refined product crack spreads throughout our inland system and by an average realized crude differential of $7.18 versus WTI for crude charges across our 5 plants on average. Our first quarter consolidated refinery gross margin was $23.32 per produced barrel, which was 34% above the $17.46 recorded in Q1 of 2012. We saw the high February cracks moderate, as industry production capacity came back online following heavy seasonal downtime. And despite unusually cold and snowy weather in many of our markets through the past couple months, margins remained at the high end of the range typically realized at this time of year. And product inventory levels are seasonally in line with market demand. The average Mid-Con 321 crack in the second quarter to date is $26 compared to a range of $8 to $27 between 2007 and 2012 for the same period. In terms of HollyFrontier's operating performance during the quarter, we experienced high levels of downtime due to both planned and unplanned maintenance activities within our refineries. Some of this being turnaround-related maintenance that extended beyond the completion dates. It's fair to say that we target more consistency in our refinery operations than was achieved in the first quarter. And without making any excuses, we're focused on delivering just this. The large turnarounds at El Dorado and Navajo have since been completed, and Dave will elaborate further on forward-looking refinery throughputs and costs. During the first quarter, we continued to execute our strategy of returning a significant portion of our cash earnings to stockholders. In February, we raised our regular dividend by 50% to $0.30 a quarter and announced another $0.50 special dividend, our 8th since initiating the special dividend program. Dividends paid during the first quarter totaled $0.80 a share or about 50% of the net income we produced. As of today, our trailing 12-month cash dividend yield stands at 6.2% relative to yesterday's closing price of $51.73. We also sold a portion of our L.P. unit holding in Holly Energy Partners during the quarter. This transaction, conducted alongside an HEP equity offering to restore balance sheet leverage to target levels, raised cash for HFC of $73.4 million or about $50 million after income taxes. It further demonstrates the value to HFC shareholders of our remaining 39% ownership in a high multiple, steadily growing MLP, while also freeing up capital for investment in higher returning refining projects or distribution back to our shareholders. The Renewable Fuel Standard has attracted a tremendous amount of attention over the past several months. As the industry has approached the E10 blend wall, RIN prices have jumped higher. These prices in the near term are impacting the financial results of refiners who must purchase RINs to comply. We believe that this effect is moving downstream into retail product pricing and the transition will become more pronounced through time as the industry adjusts to the elevated RIN costs. HollyFrontier, due to our merchant refiner business model, must purchase approximately 50% of our RIN compliance requirement in the marketplace. This need results from bulk sales of refined product into product pipeline systems and from legacy offtake agreements that were entered when we purchased the El Dorado and Tulsa refineries. At current prices, this cost of compliance in terms of RIN purchase price is in the range of $125 million to $150 million for the current year. Within the marketplace, this regulation is creating distortions, but our general view is that without crisis, Washington is slow to act, meaning that our internal efforts to mitigate the exposure have the highest near-term probability of making a difference. These include additional renewable fuels blending, shifts in our refined product slate, and changes in the way we conduct marketing operations. From a macro perspective, investors have had to digest a considerable amount of sector-specific noise during the past few months, including the RINs, Tier 3 gasoline standards and shrinking crude differentials. These factors affect near-term profitability and will influence capital investment decisions as we go forward. With that said, I believe the fundamentals that have driven inland refinery financial performance, namely, that growth in crude oil production in excess of logistics capacity, and ultimately, our proximity to the lowest-price feedstocks available nearly anywhere in the world, are still strongly in place and likely to persist for a very long time. With that said, I'll turn it over to Dave Lamp, our Chief Operating Officer, for a review of refinery operations during the quarter.

Thanks, Mike. Throughput for the first quarter was 381,000 barrels a day of crude and 421,000 barrels of total charge. The crude slate was 18% disadvantaged crudes, which I'll remind you is mainly WCS and black wax, and is 19% sour. Average laid-in crude cost for our system was $7.18 a barrel under WTI. The Brent WTI differential was $18.19 for the quarter. And just some other crude differentials, WCS was $31.92 -- $31.96 under WTI. WTS was $6.27 under. And North Dakota light was $1.37. Light/heavy and sweet/sour spreads versus WTI were wider on average compared to the fourth quarter of '12. However, both Canadian and sour differentials versus WTI have narrowed significantly from their January highs. Total refinery operating costs for the quarter were 202 -- $232 million. Operating costs were high due to maintenance costs associated with repairs required due to a fire at Cheyenne and a higher net gas price. Total lost opportunity in the quarter was $98 million, the majority of which was related to unplanned events at Cheyenne, Navajo and Tulsa. Throughputs for the first quarter for the Rockies region were 69,000 barrels a day of crude and 74,000 total charge. Disadvantaged crudes were approximately 48% of the slate and 1% sour. Average laid-in crude costs for the Rockies region was $12.01 under WTI. Refinery operating costs were approximately $8.11 per barrel. Our Cheyenne plant had a 25-day coker outage as a result of a fire in January, which resulted in lower crude rate versus planned. Throughputs in the first quarter for the Mid-Continent region were 240,000 barrels a day of crude and 267,000 of total charge. Disadvantaged crudes were approximately 13% of the slate and 5% sour. Additionally, we once again ran approximately 8,000 barrels per day of Christina Lake, a high acid number crude, which sells at a discount to WCS. The average discount to WCS for the quarter was approximately $4. Average laid-in crude costs for the Mid-Continent region was $4.22 per barrel under WTI. Refinery operating costs were approximately $5.84 per barrel. The West -- the Tulsa West crude unit had an unscheduled outage as a result of the fire at the end of March, which resulted in a 2-week downtime. Tulsa lube sales in the first quarter were about 7,800 barrels per day with an average crack of $70.50. Throughputs in the first quarter for the Southwest region were 71,000 barrels a day of crude and 80,000 of total charge. Disadvantaged crudes were approximately 10% of the slate and 80% sour. Average crude and laid-in crude cost for the Southwest region was $11.21 per barrel under WTI. Refinery operating costs were approximately $8.06 per barrel. Our first quarter turnaround of the Lovington crude unit, FCC and alky units went longer than planned by 2 weeks. Navajo is back to running full rates at 104,000 barrels per day, exiting the quarter after the turnaround. During the quarter, our revenues were impacted by a build in inventories of roughly 900,000 barrels, which was mostly related to turnaround activity. The impact on earnings was roughly $0.10 per share. For the second quarter of '13, we expect to run approximately 400,000 barrels a day of crude with 24% of the slate being disadvantaged heavy crudes and 21% sour. The El Dorado turnaround, which began in the third week of March, completed on schedule. We have since had an electrical issue with our FCC unit, which caused us to cut crude until it's resolved. That unit is in restart right now. The Tulsa East plant turnaround is to commence in May with planned work on our crude unit, reformer and naphtha hydrotreaters and Panex unit. During the East plant turnaround, that Tulsa West plant will continue to operate at 90,000 barrels a day. No other downtown is planned in the second quarter that will affect crude rates. HollyFrontier has had an unusual high number of large turnarounds across its refining fleet in the past several quarters as a result of independently planned turnarounds scheduled prior to the HollyFrontier merger. After the Cheyenne turnaround plan for the fourth quarter, we will have completed major turnaround works in 4 of our 5 plants. And going forward, we will have the ability to better stagger the necessary turnaround work in future years. With that, I'll turn it over to Doug for some closing remarks.

Thank you, Dave, and thanks to all of you for joining us this morning. For the first quarter of 2013, cash flow provided by operations totaled $248.6 million. First quarter capital expenditures totaled $67 million, excluding HEP's $5 million capital spend. Turnaround spending in the quarter totaled $69.8 million, and we maintain our full year 2013 CapEx guidance of between $400 million and $450 million and turnaround spending of $156 million. As of March 31, our total cash and marketable securities balance was $2.5 billion versus $2.4 billion at year-end 2012. HollyFrontier debt totaled $471 million, excluding nonrecourse HEP debt of $811.9 million. In the first quarter, we distributed $102 million in dividends to shareholders, as well as another $61 million declared in the first quarter that was paid in the early -- early in the second quarter. Year-to-date, we have repurchased 446,000 shares. And since our July 2011 merger, HollyFrontier has returned $1.3 billion in capital to shareholders through regular dividends, special dividends and share repurchases. I'd like to mention a few additional items that impacted the quarter. We incurred a few one-time charges in the quarter, including a $3 million pretax charge due to the Cheyenne coker fire Dave mentioned, and a $5.3 million charge for the El Dorado cap- -- problems that we had, as well as the write-off of some equipment that we would no longer find to be usable. Lastly, I'd like to update you on our quarter-to-date crack spreads. These are all based on West Texas Intermediate, not the advantaged crude oils that we run. For the Rockies region, the gasoline crack spread averaged $30 for April and the diesel crack spread averaged $33 for April. In the Mid-Con, the gasoline crack spread averaged about $28 for April and the diesel crack spread averaged $35. In the Mid-Continent, at our Tulsa refinery, we always -- also make lubricants. The lubricants crack spread was about $77 for the month of April. Lastly, in the Southwest region, the gasoline crack spread averaged $26.50, and the diesel crack spread averaged about $30 for the month of April. Turning finally to the first few days in May. We've seen the gasoline crack in the Mid-Continent at about $22.50, and the diesel crack spread in the $27 range. In the Southwest region, month-to-date for May, about $18.50 on gasoline and about $18.75 on diesel. And in the Rockies, we're seeing about $24.50 on gasoline and about almost $28 on diesel. And with that, I believe we're ready to open the floor to questions.

[Operator Instructions] Our first question comes from the line of Paul Cheng of Barclays.

A quick question. Dave, can you give us an estimate what is your second quarter total crude and also, total refinery throughput estimate?

Well, I mentioned it was about 400,000 barrels per day. That includes the effect of the El Dorado turnaround and the Tulsa East turnaround.

Okay. That's crude, right?

Pardon?

400,000 is just crude. Yes.

Just crude. Total throughput would be -- is usually that same -- about that same percentage of kicker that you -- that we normally see, a difference of about 40,000 barrels a day.

And Dave, given that the turnaround activity in the second quarter will be lower than the first, should we assume that your absolute cash operating costs should be down compared to this -- to the first quarter?

Well, we don't see net -- net gas has drifted down slightly, but that affect will still be there. We should see some onetime effects of operating costs come down. Exactly what that'll be depends on how we account for some of the turnarounds we do. And some of those -- if they're not material, they get expensed 100. If they are, they're crude, they're amortized.

And earlier that, Dave you're talking about, I think either you or Doug, talking about an inventory build-up a $0.10 per share hit in the quarter. Do you have a breakdown how much is the inventory or what the inventory costs are by region?

We don't have that detail, Paul, for this call. We might be able to get that for you after the call. That just related again, due to turnaround activity, we ended up with some excess gas oil that will be sold in this quarter resulted in some lost opportunity. But we'll have it for you by region offline, if that's okay.

That's great. Doug, can you say, maybe give us a rough estimate that you gave about the unplanned downtime opportunity costs, say, $98 million. And how about the planned downtime, what is your estimate, given it's such a heavy downtime?

Well, the $98 million, Paul, is just lost opportunity to unplanned events.

Yes, we have the number, Paul, as well for the -- again, a bit unfair to call turnarounds lost opportunity. But the cost -- the opportunity cost of having taken the turnaround for us, given the high-margin environment, was $140 million in the quarter.

Our next question comes from the line of Arjun Murti of Goldman Sachs.

Just a couple of follow-ups to I think it was Mike's prepared remarks. Mike, you mentioned due to some of the RIN and Tier 3 issues and Brent I think is closer to 9 or 10 versus what we had before, that it could impact future CapEx. But you did reiterate your $400,000 to $450,000. So just wanted to make sure I understood, you're just talking about the future CapEx could be lower, some other amount or any additional color would be great.

Sure, yes. Starting out, the Tier 3 requirement will generate capital spending at HollyFrontier and other refiners. We haven't fully quantified that. But it will be incremental compliance costs incurred between now and at stipulated dates, 2017 and 2020, depending on which plant we're talking about. So that really was that reference. In addition, we're spending more money to create blending opportunities for biofuels at materially all of our terminals and refinery locations. That being in order to blend ourselves and pocket the RIN, as opposed to have to buy in the marketplace. So that really was what I was talking about in terms of future capital spending.

On the latter point, do you have an estimate of what percentage -- I think you mentioned you were 50% exposed. What you can take that down to based on what you just said?

I think 10% in the near term is a good target. The residual relates to the product offtake agreements I discussed, as well as bulk sales, which are a part of our business.

That's great. And then just a last one for me. Just looking for some more details on the rail projects you announced with Holly Energy Partners during the quarter. Are these just rail offloading facilities at or near your refinery? Or I guess, how far back upstream do you see yourselves going? It does seem like in Canada, with some of the pipeline delays current and future, they're going to need to rail a lot more of that oil sands out of that country. And just curious to what degree you can participate further backup stream, on the rail side I'm talking that.

This is Dave Lamp. What we're proposing right now and just exploring, mostly, is whether we put a rail loading -- unloading system at Artesia or Lovington. We haven't really made that decision yet. But the concept is, is that we would -- since we're in the middle of the Delaware Basin, which is exploding in growth of crude production, like you say, more outlets is needed to go either east/west or even south. Most likely, east/west, however. But we think we have pretty good flexibility because we have access to WTI, we have WTS and we have WCS, should somebody be able to get it to Cushing. So those are kind of the concepts we're playing with. We could make multiple grades of crude, tailor it to a customers' need. But the real part of the deal is we're not looking at additional railcars, so a customer would have to come in with his railcar, pick up a load and take it to wherever. We're designing or have in the mind, the concept of unit train so you get the maximum discount. Just to give you an idea, some of the freight rates are somewhere around $7 to the West Coast. We really haven't determined what it is on the East Coast yet. But it could be competitive with Bakken barrels. As another phase, we're looking at potentially bringing in uncut bitumen and diluent bitumen. That is a little tougher play in that we have access to Cushing today, but we're exploring what those economics are and what that might entail. And that's kind of a Phase II.

Beyond that, the plants are obviously linked into Holly Energy Partners' gathering system, and so that asset feeds well into the plan. And hopefully, we get the incremental gathering volume as well. But the overall goal is to gather barrels and move them westward toward our plant through existing infrastructure and adding the rail as an alternative, principally, for West Coast customers, possibly for East Coast customers, but giving broader access to that Permian growth.

Our next question comes from the line of Evan Calio of Morgan Stanley.

Just maybe if I can just follow up on the rail projects. Do I understand it correctly that Phase I is largely based in export, where Phase II is potentially more of an import? Or is it initially viewed as somewhat bidirectional depending on different differentials?

Well, I think it gives us the opportunity to do Phase II with Phase I. We need some additional tankage, some other things, that's why we tend to call it a Phase II. You need railcars to really do that, too, Evan, which is a significant investment, not only in commitment, but also in time.

So I think it's fair to say Phase II is just dependent on the outcome of the large pipeline projects going from Hardisty to Cushing. And if those come, we have plenty of capacity to move WCS westward through the Centurion and Roadrunner lines. If they don't, then we look hard at the direct import of dry bitumen.

Great, great. And just a question on Wood Cross expansion. Maybe give me a permitting progress update. And I know you had mentioned -- you had last mentioned that the public comment period had expired. I mean, what's the regulatory timeline and path forward there?

Well, we have gone through a process of redefining the project to some degree, including adding some more reductions and emissions, back to basically the same point we were before. Right now, the agency is in -- Utah agency is in the final review step of that modification. We will go out for public comment again because of some of the changes made to the permit. And that's -- hopefully, will start in the next couple of weeks.

So looking forward from that, we expect a 45-day public comment period. That takes us sort of into mid July, end of July before an expected permit would be issued. At this point, that is still comfortable, though tight with our initially articulated project timeline, and really looking forward to first quarter of 2015 as a realistic completion date. But we're optimistic. We think we changed some things that made both the state and the EPA very happy in this new application. But it's enough change that it really requires additional public comment period.

And I'd add to that, engineering continues and long-lead equipment is on order.

Okay. Maybe lastly, if I could, is there any additional color on the buyback? I mean, were you -- was that back-end loaded in the quarter when the sector was weaker? And have you been blacked out of the market into earnings here?

Evan, we're able to get around the blackout. I wouldn't say get around, because obviously, the SEC allows through 10b-5 for us to do share repurchases even in a blackout period, but through a program. I'd tell you, when you see the Q filed, that some of that was in March, more -- even more of it was in April. And our stance really hasn't changed. We are a bit selective in terms of price and have, what I would call, the levels that you saw there, more of a toe in the water approach to get some shares back in and to offset dilution, and still have roughly a $500 million authorization left from our Board of Directors to support the stock, if we feel like it's good value as supposed to our dividend program or rather, I should say, in addition to our dividend program, which we certainly expect to continue.

Our next question comes from Robert Kessler of Tudor, Pickering and Holt.

I wanted to see if you could comment about refined product export routes. And by that, I mean both the latest performance on UNEV. And then also, any thoughts about a possible Gulf Coast refined product export route, whether it's Port of Catoosa or otherwise?

Sure. Practically speaking, I think that we will, in the near term, move marginally, marginally south of Tulsa, marginally east of Tulsa. And I'm talking about 200 miles at a clip. And we've achieved that. The Wynnewood South extension performed by Magellan reversing that flow has helped us, certainly through the first quarter. I would say that we have nothing earth-breaking in terms of Tulsa to the Gulf product pipeline expectations in the next 12 months, but rather, we'll probably move in small bites, 10,000, 15,000 barrels a day extending into these markets. As to UNEV, Dave, the volumes there?

Well, in coming off the season of the winter season, which Salt Lake is typically long, we pretty much maxed out the pipeline, at least the rack in Las Vegas. Margins have since softened or were more equalized since then. But we expect the summertime we'll have a small flow going that way, just to balance the Salt Lake market.

And then can I ask on Woods Cross, what do the incremental capture requirements do to the overall CapEx for that project?

In terms of the permit or...

The additional emissions reductions?

Yes. Yes, you referenced having received the comments, you modified the scope, yes.

Yes, it's about $5 million in terms of additional equipment, control equipment we have to install. Not particularly material to the project.

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

I guess, maybe a quick follow-up on the RINs. Have you actually had to adjust or do you think you may have to adjust the product slate that you're running at this point based on the RINs? Or is it a, call it a manageable issue in '13 and then we all hit the wall in '14?

Well, we're hoping not to hit the wall. But near term, in terms of product slate, obviously, jet fuel doesn't carry a RIN requirement. And so pushing distillate into jet until the RIN value tells us not to is an actionable near-term item. Offering for sale E85 is something else that we can do and obviously, have great RIN economics in doing that. The demand for that product is very light. So as much as we'll be posting that at our racks, the expectations are modest. But those really are the 2 product offering opportunities.

Okay. And then, just wondering, as the differentials between WTI and Brent compress a little bit here, one of the things I've heard from your competitors, that you've been able to use that as a -- for some of the lower-end products, as an advantage, obviously, in terms of moving your products further -- to markets further away than what you normally would do. Is there a level we should be paying attention to? Like, say, if the differential were to compress to $5 or $3 or something like that, where we would have to consider that maybe it would be more difficult for you to move out some of the lower-value products over time?

Well, I think our view would be is ultimately the differential goes to the pipeline cost to transport barrels to the clearing point of the market. As far as the low-value products, I mean, where it impacts us -- would impact us the most is at intermediate or attempts to sell intermediates, like gas oil or BTBs or bottoms, of that sort. So I mean, it affects us in terms of those type of products. But the other factors, the LPGs, which are long in the Mid-Con and in most of our markets that export out, so those get impacted also. But in terms of the yield slate, it's still a relatively small piece of the total equation.

Yes, the fuel oil that we're needing to move to the Gulf Coast or other markets might be between 5,000 and 8,000 barrels a day. So I don't think it materially affects crude running. But yes, at a $3 differential, assuming current rail costs and current inland versus coastal pricing dynamics, that would bite into those economics. Whether there's enough gas crack to offset it and continue to run that barrel, diesel crack, that really is the L.P. question.

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

It's Jeff Dietert with Simmons. I was hoping you could talk about some of the implications of the Permian pipelines, what you've seen or perhaps what you expect, given that they're still relatively new with Longhorn having filled line pack last month and starting deliveries in the Gulf Coast and Permian Express and West Texas Gulf expansion coming as well. How is that changing your feedstock procurement?

Well, I guess, in short, it's making it more expensive, isn't it? But practically speaking, these are, in our minds, induced by line fill and by changes in flows. To see Midland significantly ahead of Cushing in price, you still have probably 300,000, 400,000 barrels a day moving east toward Cushing through that differential. So whether that persists over time will be interesting to see. Also, to see WTS over WTI, similarly interesting. So there are distortions in the market largely, in our minds, due to near-term issues. But longer term, it's hard to see Midland trading at a significant discount to Cushing.

The other thing you're seeing, Jeff, is I don't know if you're following naphtha pricing in the Gulf Coast, but it's $0.42 to $0.50 under gasoline, which is a significant move. And that's just recent. And that's indicating to me that there's a lot of light crude down there and they're outrunning the reformers and until HOHO [ph] gets reversed, that's another effect of the market. Yes.

So effectively transfer crude differential to the Gulf Coast until it starts to reject it, right?

Exactly.

That's helpful. Are you saying or do you sense competition for West Texas sour? Do you anticipate that given the complexity of refiners in the Gulf Coast, they're more likely to try to pull West Texas sour out of the Permian rather than WTI?

Certainly, as you run out of reformer capacity, the tendency will be to desire a heavier barrel. I mean, that's my explanation why WTS is over WTI. But will it hold? I don't know.

Yes, and I guess with Tulsa and El Dorado, you've got lots of flexibility. You start moving towards more northern-produced crudes relative to Permian crudes.

That's right. We're stepping up gradually in our spearhead shipments, gaining 1,000 barrels per day per month or so. And in theory, at some point, we go through our WCS requirements and start shipping Bakken through the Clearbrook system and can get it done at the Mid-Con for $4 or so, which may be an attractive barrel.

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

Just back on the rail project. Can you just clarify, is this project more focused on HEP economics? Or is there some identifiable uplift to the refining system as well?

It sort of remains to be seen, and it's dependent on bitumen imports. Otherwise, the refining system has a wealth of crude available to it, sitting effectively on top of the Delaware Basin. So this is -- whether it's an HEP opportunity or just a logistics play, obviously, we're working with HEP. The Lovington refinery sits next to a long rail side and has great infrastructure tie-ins to the gathering system and to other crude pipelines. So we think it's a very logical addition to both our logistics capacity and potentially, our refining system. That being dependent on pipelines coming from the North.

Okay, so you really -- Mike, what you're talking about is really getting into potentially crude marketing going forward here? Is that right?

We're already in it. We're purchasers of crude, as HollyFrontier, of what, 70,000, 80,000 barrels a day beyond our appetite?

Yes, 160,000 total.

Yes. So we're extending that capability.

For the rail project, what percentage of the crude would be sourced from your gathering system versus just open market purchases? Any sense on that?

Well, there'd be a mix of contract and first purchase in that, Chi, so it would be -- it's hard to give you an exact percentage because it just depends on where we source it. I would point out to you that the Delaware Basin, as Mike said, is growing like a weed in terms of production. So I imagine a lot of those barrels will be first purchase.

Okay, okay. And then can you give us a status on the permitting on the project? I think in the release, you mentioned an early 2014 startup.

Yes, when we get going, when we make a decision on the location, and that's still pending, I might add. But that's about a 9-month bill is what we're estimating. So first step is get some engineering done and get enough definition to get the permits in. And permits are -- it's relatively a small modification, so it's not a real big, complicated permit.

Okay, great. And then, finally, can you just give us status, Dave, of Tulsa and Cheyenne post the fire incidents? How are the plants running right now?

Both of them are back up. Actually, Tulsa was -- today's running about 140, but had been running about 150. And Cheyenne is back up to about 46, 47 and is doing well. So both of them are in good shape. Now we're getting ready to go into turnaround on Tulsa East. So you'll see that happen in this quarter.

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

I wonder if I could just take a big picture question here for a second. Obviously, TI Brent has been a lot of the discussion on the call this morning but it came in a little quicker than any infrastructure build-outs really appeared in the U.S. So what is your prognosis for how that -- I mean, do you expect things to widen out again and if so, some of the moving parts around your, I guess, in northern acreage would be, in particular -- of particular interest. What I'm getting at is that there's a lot of chatter about wellhead pricing exceeding the benchmarks in the regions, particularly in the Bakken, and whether or not that's actually finding its way to your facilities. And I'll leave it at that on the crude, then I've got a follow-up, please.

Sure. So from the Brent TI standpoint, recognize that the TI hasn't changed near as much as Brent. And I think that global considerations and demand on Brent softened pretty quickly. I see that as somewhat temporary, with potential for that to widen back out during the course of this current calendar year. Because I agree with you, the logistics addition, effectively, was the Longhorn pipeline. And then whatever ramps Seaway has been able to achieve. So I don't believe it was on the domestic side that caused that spread to compress to $9. Beyond that, you asked about benchmarks in the northern crudes versus...

Yes, Clearbrook is trading, it looks on our screen, about $5 or $6 below TI again. So it's kind of widened out. And I'm just kind of curious, is that what you're seeing or is wellhead pricing higher than that or worse than that, I guess, would be a better way to put it.

Right. So our purchasing of Bakken crude is from the Guernsey hub, and it reflects that softening. Recognize that with Brent TI coming in and with the volume crude moving to the coast, Bakken really becomes Brent linked and Brent minus, call it $12 to $15 of transportation cost. So I think that current pricing is fairly logical. To the extent that we can buy that crude for our Cheyenne plant at under TI, it's obviously attractive. And at some point, as I referenced earlier, it becomes relevant through the Clearbrook system to compete against the WTI Cushing.

Okay, okay. Just 2 quick follow-ups. I guess, one for Doug on the numbers for a second. DD&A was up a bit, Doug, sequentially. Can you just shed some color on that?

I can. Normal run rate's in the sort of $65 million per quarter area. We were up to just over $70 million, and, Doug, that related to some nonrecurring tanks that were taken out of service. Sort of accounting between HEP and HFC, and you shouldn't expect to see that continue.

Okay. Final one, I think, is probably for Mike. Mike, in the past, you've mentioned some desire to look towards the coasts in terms of potential expansion in the future. Just any updated thoughts as to how you might see yourself getting involved there? And I'll leave it at that.

Yes, sure. Doug, what we've said is there's obviously an abundance of refining capacity on the coasts. Ours is a mature industry. It's subject to further consolidation, in our opinion. Our particular strategy in refining is feedstock-based, as access to cheaper feeds flow right through to gross margin per barrel and ultimately, EBITDA. So the Mid-Con, Rockies have obviously experienced the greatest feedstock benefit to date. And we see this as moving to the Gulf Coast, in particular, being the likely recipient of crude barrels that are significantly in the money versus competing refineries. And so when we talk about the potential to look toward coastal refining capacity, it's really Gulf Coast that we talk about, and it's premised on a crude advantage that we believe will accrue to Gulf Coast refineries. In terms of specific strategy, we obviously don't talk about particular opportunities other than to say, feedstock advantaged refining is what we believe we do well and do for a living. So that's kind of a short summary. Clearly, an industry in which demand is flat to down in terms of our finished products. So any deal that we would execute is going to be returns justified as opposed to growth justified.

Would you characterize anything else as in process, Mike, or is it still just kind of pipe dream at this point?

Pipe dream, literally. Not going to go that far, Doug. Thanks.

Our next question comes from Rakesh Advani of Credit Suisse.

It's Ed Westlake here. Just on this -- still coming back to this rail project. I get which direction I think it's flowing, but in terms of CapEx and potential payback periods, any comments?

Well, we're estimating it to be between $30 million and $40 million to put in a 70,000 barrel a day unit train system. Whether we go that far or not is still under debate, but that's probably the outside of it.

Right, okay. And then I see HEP is doing some small pipelines around, I guess, getting crude into -- for the Tulsa to Cushing and then maybe a part of pipeline around Cheyenne. But I mean, I guess, maybe a broader question is, as you see the logistics landscape around the refineries, maybe either what's uppermost on your mind in terms of incremental projects perhaps beyond this rail project?

Yes, I think you have to follow the crude, right? And the Permian is growing quickly and growing in our neighborhood. So it's a question best directed to HEP, but we obviously have a significant interest in it. So crude projects in the Southwest, I think, are a great opportunity for both companies. Beyond that, the projects that support the refineries, make them more competitive in terms of the feedstocks we can bring in and the product markets we can access. And those are very generic project areas, not specific, I appreciate. But that's where we are pointing in terms of the assistance that we need from HEP for logistics expansions.

But I mean, you could do something similar to what you did with UNEV which is front the upfront CapEx and then potentially drop it down later. Is that the sort of structure or just through HEP's own organic availability of funds?

Either way. If our aspirations and the project opportunities exceed their ability to fund it in the near term, then we can joint venture it, if it makes sense. I don't think we have projects on the table right now that require that, but we'll take it on an opportunity-specific basis. The objective over time is to make money and increase value.

Great. And 2 small questions. I think you'd spoke about a pension charge. I think that was going to be, Q2, $37 million pretax, if I remember rightly. Is that still right?

I'm sorry, you said hedging charge?

A pension, pension, pension charge.

Yes, pension charge. Yes, that's still appropriate, but maybe $38 million or so. But still expect to have that. We've got to get an approval from a government authority to sort of terminate that plan, but we still expect that by the end of this quarter.

Okay. And then the tax rate was 35%. Any change for the full year guidance?

No, not that I'm aware of.

And we have reached the allotted time for questions today. I will now turn the floor back over to Julia.

Maria, if we still questions in the queue, we're okay to take them.

Okay. and we do have a follow-up question from Jeff Dietert of Simmons.

I'm sorry, my follow-up has been asked and answered.

We have a question from the Faisel Khan of Citigroup.

This is actually Mohit Bhardwaj for Faisel Khan. I had a question regarding Christina Lake crude. And what's the number that you guys are potentially looking to run through your system as far as Christina Lake crude is concerned?

Well, directionally, we are metalling up, have projects to metal up, and El Dorado is basically already metalled up to handle these high-acid-number crudes. So as it becomes available, we'll run more and more of it.

And current is about 8 a day.

Yes, 10 a day.

10 a day.

8, 10.

And opportunity, depending on metal up, of 20, 30.

Yes.

And that's included in the 80,000 barrels per day of total pipeline capacity you guys have for getting WCS down all the way to your refineries at the Mid-Con?

That is our pipeline capacity availability today, yes. And so to the extent that we bring incremental barrels, we either need more pipeline capacity or we're going to be substituting Christina Lake for WCS.

I'm showing no further questions in the queue, sir.

Excellent. Well, thank you for joining us today. And we hope you all have a good day.

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