Welcome to the HollyFrontier Corporation’s Q1 2014 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. (Operator instructions.) Please note that this conference is being recorded. It is now my pleasure to turn the floor over to Julia Heidenreich, Vice President Investor Relations. Julia, you may begin.

Thank you, Shannon. Good morning, everyone, and welcome to HollyFrontier Corporation’s Q1 Earnings Call. I’m Julia Heidenreich, Vice President of Investor Relations. This morning we issued a press release announcing results for the quarter ending March 31, 2014. If you would like a copy of today’s press release you can find one on our website, www.hollyfrontier.com. Before Mike 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 outcomes. Today’s call may also include discussion of non-GAAP measures. Please see the press release for reconciliations. Also please note that information presented on today’s call speaks only as of today, May 6, 2014. Any time-sensitive information provided may no longer be accurate at the time of any webcast replay or rereading of the transcript. With that I’ll turn the call over to Mike Jennings.

Thanks, Julia. Good morning. Thank you for joining us on HollyFrontier’s Q1 Earnings Call. Today we reported Q1 net income attributable to HFC shareholders of $152 million or $0.76 per diluted share. Our Q1 EBITDA was $339 million, more than double our reported Q4 EBITDA of $158 million. Current quarter earnings were driven by strong wintertime refined product track spreads throughout our inland system, somewhat offset by narrowing crude differentials, a decline in fuel oil and asphalt cracks, and elevated [Brents] cost during the quarter. Q1 crude throughput was 416,000 barrels per day versus our guidance of 410,000 barrels per day. We ran 21% sour, 20% WCS and black wax crude. Our average laid-in crude cost was $4.12 per barrel under WTI and regionally we experienced average laid-in crude differentials under TI as follows: $11.27 under in the Rockies, $3.11 under in the mid-con, and $1.96 under in the Southwest, that’s on a per barrel basis. As expected, inland coastal crude differentials compressed approximately 20% during the quarter due to new pipeline capacity from Cushing to the Gulf Coast. I continue to view this demand pull from Cushing as a temporary phenomenon and expect the Brent TI spread to widen through 2014 as production grows in the second half of the year and northern tier pipelines come online. We also benefit from light/heavy, and sweet/sour discounts though the Canadian crude differentials compressed approximately $10 during this quarter driven in part by extreme winter weather in the producing region. The sweet/sour spread was favorable during Q1 with WTS at Midland trading below WTI Cushing by an average of $3.60 for the quarter. This differential has recently grown to about $8.00 per barrel during March and April which will contribute to an improved Q2 capture for our Southwest operations where we run…

Thank you, Mike. For Q1 2014 cash flow provided by operations totaled $395 million. Q1 capital expenditures totaled $103 million, excluding HEP’s $21 million capital spend. Turnaround spending in the quarter totaled $4.3 million. We maintain our full-year 2014 CAPEX guidance of $400 million and turnaround spending of $77 million. Total refinery operating costs for the quarter were $239 million. We spent nearly $20 million more than the previous guidance on natural gas in the quarter driven by a combination of both higher price and volumes attributed to the extreme weather. As of March 31, 2014, our total cash and marketable securities balance stood at $1.8 billion versus $1.7 billion on December 31 of last year. HollyFrontier debt totaled $189 million which excludes nonrecourse HEP debt of $834 million. In March, HEP redeemed its $150 million 8.25% senior notes and incurred a $7.7 million charge associated with that redemption. Going forward, consolidated interest expense should be approximately $10 million per quarter. In Q1 we announced and paid a $0.30 regular and $0.50 special dividend, distributing $159 million to shareholders. Since our July, 2011, merger HollyFrontier has returned approximately $2.1 billion in cash to shareholders through regular dividends, special dividends, and share repurchases. As of March 31, we have $312 million remaining under our share repurchase authorization. As of today our trailing twelve-month cash yield stands at 6.2% relative to yesterday’s closing price of $51.60. As for an update on our hedging program, we’ve sold forward a total of about 35,500 barrels of diesel for calendar 2014 at an average price of $28.62 per barrel. We’ve sold 36,000 barrels of gasoline at an average price of a little more than $12.00 a barrel. And for 2015 we’ve sold 12,000 barrels a day of diesel at an average crack spread of $30.00 a barrel and about 4,000 barrels of gasoline for the current quarter – that being May and June timeframe – at about $18 a barrel. Lastly, a reminder that you can find monthly WTI-based 3-2-1 indicators for our mid-con, Rockies and Southwest regions posted on HollyFrontier’s Investors webpage. These regional indicators do not reflect actual sales data and are meant to show monthly trends. Realized gross margins per barrel may differ from indicators for a variety of reasons. You can find the data on our investor page at www.HollyFrontier.com. And with that, Shannon, I believe we’re ready to take questions.

At this time the floor is now open for questions. (Operator instructions.) Thank you. Our first question is coming from the line of Doug Leggate of Bank of America. Your line is now open.

Good morning, fellows. I wonder if I can ask you to talk a little bit about the operating performance, because obviously compared to last year it’s significantly better. And I just wonder if you could provide some confidence I guess or some guidance as to what’s changed and why you’re confident you can basically maintain this performance through the peak season. And I’ve got a follow-up please.

Yeah, Doug, reliability is something that’s getting a ton of focus inside this company. I won’t say that we’ve achieved what we want to yet but we’re improving pretty progressively. Take Navajo as an example. We solved that wastewater problem in the month of December and got through it by about the 20th of January, and have been running full ever since. Cheyenne was actually having a quite good quarter and got tagged with a severe freeze-up in which they lost their steam system. But I guess to answer your question succinctly a ton of focus and some amount of investment, and we do have confidence that we can move the needle through the remainder of the year as we look forward.

Great, I appreciate that. My follow-up is in the past, Mike, you’ve talked about efforts to try and move product out of your region. I guess that’s going to be less of an issue during the summer months but can you just give us an update as to how that process or what your thought process is as to how you might achieve that? And perhaps just underline again whether you still see the kind of volatility in your region as a result of, for want of a better expression, Gulf Coast gasoline making its way into your markets. And I’ll leave it there, thanks.

Yeah, sure. The issue really is one of how much demand is there to absorb a full running mid-continent refining system. And I think from a system perspective the obvious markets are to the south and to the east – our company is pursuing that strategy. I wouldn’t tell you that we expect a physical link to the Gulf Coast anytime soon but we also don’t believe that we need that. As we look to markets traditionally served by Gulf Coast refiners, we feel that we can compete in those, particularly north Texas, states to the east of our markets currently that we don’t serve. So that’s really our focus area.

Is it fair to say, Mike, are you seeing any kind of regional tightening in your markets as a result of these efforts? I mean you’re only one refiner, obviously, but are others pursuing the same kinds of issues? Or what’s your overall prognosis for the market I guess as you go forward?

Well, if you contrast the current winter to that of 2011 when the Magellan system was really full and apportioned, I think we are seeing progress. And as you know, petroleum barrels move incrementally. So I don’t know that I can tell you the number of barrels into which new markets by which particular producer but I can compare year-over-year performance within the Magellan system in particular and product is moving out to other markets.

That’s really helpful, thanks guys.

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

Good morning, guys. Mike, can you remind me for (inaudible) the oil that you receive from Permian, do you receive it just from the [commentary] or do you have your own gathering system?

No, we have a significant gathering system owned by our MLP Holly Energy Partners which delivers roughly 50,000 barrels a day to the Navajo refining system.

Right. And with the I think increasing campaigns from some of your peers that the oil quality [people are increasing] more and more condensates and all that. So it seems to be a significant advantage that having your own crude gathering system joined to, supplying to 100% of your refinery – is that something that you guys are going to step up and be more aggressive in investing on the HEP side so that you can get the full, the entire 90,000 or 100,000 barrel a day of [controlled crude slate] coming from your own gathering system?

Right, Paul. We are doing exactly that. HEP has announced an expansion of that gathering system which they dub the Malaga Project. Initial opportunity there is an incremental 40,000 barrels of day or so and expandable to 60,000. So at that point we would be gathering in excess of our own demand. But you highlight an important advantage, and that is to be able to control the barrel coming into your refinery, and having these more captive gathering systems does permit that.

And can you share with us that comparing to your own gathering oil to those that currently you receive from the third party, what are the incremental benefits that we may be talking about? And also what kind of timeframe do you think you would get to a point where you would actually be 100% [supply your own]?

The ability to supply our own is going to hinge a bit on production growth but we do see that in the Delaware Basin. As to crude quality versus crude price, I’m going to take a pass on that, Paul, for competitive reasons but I would tell you that it’s meaningfully better.

Should we assume over the next 18 months you will get to 100%?

I believe so, yes.

Perfect, thank you.

Your next question comes from the line of Paul Sankey with Wolfe Research. Your line is now open.

Good morning all. Hi guys. I’m sure there’s a conference call joke in here somewhere, Doug, but I’ll just move on to my question.

How’d you get this number? [laughter]

Can you, just to get back to the Operator, I think the major concern we have is the operational performance question. Mike, can you just do a look back – was it a high level of turnaround last year? What were the issues last year? And you’ve kind of stated that it’s going to be better this year but can you just talk more about your confidence and why, thanks.

Yeah, there are really two things. One is less planned maintenance and fewer units at end of cycle which we had a lot of last year across our system. So between sort of sliding into turnaround and then needing to come out of turnaround, that certainly affected performance. And then I’ve got to say that it was old-fashioned blocking and tackling, Paul, and as I expressed previously we haven’t solved all the problems that we want to but we are getting better in terms of reliability, and finding main culprits and knocking those off one at a time. So I am confident that we will improve certainly year-over-year and move closer to our targets.

And to the extent you’re prepared to can you talk a bit about how much more turnaround and maintenance you’re going to have this year coming?

Sure. I specified earlier on but our turnaround activities are all compressed into Q4 – the Navajo refinery in Artesia, New Mexico, has a small crude unit that’s being turned around as well as a distillate hydrotreater and mild hydrocracker, so hydrotreating units. The El Dorado facility at a similar time in the October time period will be turning around its cat cracker, gas oil hydrotreater and alkylation unit. So big units but fairly modest across relative to our entire system.

Great. And then finally from me, Mike, you’ve often expressed views on the crude market and the way things are moving in the US. What’s surprising you about the current market and what’s your outlook for the next year or so? Thanks a lot.

Sure. I think there isn’t a lot of surprise. A lot of pipeline capacity was built and subscribed forward to connect Cushing to the Gulf Coast and crude hasn’t yet filled it. And so those prices between Houston and Cushing are trading very similarly right now, separated by maybe $0.50 if you adjust for crude quality. Through time I believe those differentials will re-widen as we get more northern tier pipelines from North Dakota as an example, potentially from Canada connected up to Cushing. Beyond that I think the obvious is kind of a comment around crude production growth and the likelihood that the Gulf Coast crude separates from Brent further as time goes forward due to additional production domestically.

Thank you, thanks a lot.

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

Good morning. I was hoping you could talk a little bit about the ATP New Mexico gathering system – what types of quality of crude are you expecting? Is it lighter API gravity crude and are there unique design or processing capabilities that are associated with this system?

So our targeted area is in the Delaware Basin extending south from our refinery and then east from there. And we have seen lighter crudes coming. We believe that we’ve designed for that. As it extends further south yet the crude starts to heavy up. So I don’t believe we’re going to have problems in terms of crude gravity that are going to affect our own gathering capabilities or refining capabilities. With that said there probably is a blending opportunity for the incremental barrel that we might sell into the market because it is a very light and sweet crude.

Given the substantial growth that’s expected out of the Permian and kind of uncertainty as to quality until we see more production, are there potential projects at Navajo for expansion of light crude capabilities there?

We expect to be running more light crude out at Navajo, and then obviously that puts pressure on the light ends processing and naphtha treating portion of the refinery. And we’ll advance that progressively as we need to. For the time being we feel like the [kit] is in pretty good shape as compared to the crude slate, so I don’t think that we need a lot in terms of projects. There’s obviously the potential to do some condensate splitting out in the Permian, and the challenge is simply one of what to do with the condensate and can you transport it cost-effectively to the Gulf Coast which would be the market point for that. And that’s something that we’re considering but haven’t cracked the code yet.

Gotcha. It seems like there’s a substantial race between production growth and pipeline capacity additions with [Bridge Techs] coming in next quarter and then Cactus and Permian Express. Can you talk a little bit about what your expectations are for WTI Midland differentials relative to Cushing over the next twelve months or so? And I’ll leave it there, thank you.

Sure. I think that the production growth in the Permian, the big basins are obviously the Bakken, the Permian, the Eagleford; and the level of activity in the Permian in our view will fill incremental pipelines that are planned. So we don’t expect to see the current wide differentials persist through twelve calendar months, but I think that will be the pattern – that production will grow a little bit more quickly than infrastructure will facilitate.

Jeff, the only thing I’d add to that is that with Bridge Techs and others coming online, at some point I think maybe not conventional wisdom but there’s certainly some of us out there that question at what point does the Gulf Coast become saturated? And if we continue to see the Gulf Coast trade at effectively parity to Cushing are folks willing to spend $3, $4, $5 a barrel shipping to the Gulf Coast to get the same or in some cases a lower net back? And in Mike’s opening comments he talked about us viewing the likelihood of that widening back out as you see more crude come from the north, and I think that that’s certainly a strong possibility that we could see by mid-Q3 anyway.

Very good, thanks guys.

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

Yes, thank you and thanks for the color on Navajo in terms of gathering some of the local barrels. Just remind us as you look at the Cushing system, say Tulsa, are you able to get Permian barrels in the Midland and source them there, and then just pay the freight to get it over to your refineries? Any volumes there that sort of should be advantaged in Q2 that we should be aware of?

We don’t have advantaged transportation or subscribed transportation from Midland to Cushing, so in the mid-con we’re effectively paying Cushing price.

Okay, that’s helpful. And then the cash flow, Doug, was very strong in the quarter. Was there anything in the working capital that contributed to that strong cash flow? I mean obviously it’s great to see the EBITDA improve sequentially as well.

There was. I mean what we had was about a $150 million benefit from change in working capital in the period - $35 million or so of that was payables increasing ahead of inventories. And then the other big item was an income tax receivable of about $97 million providing working capital in the period.

Okay, thanks very much. And then just obviously, I guess a lot of people focus on [dips] and everything but maybe any update on the self-help in terms of where we are with the Tulsa refinery, if there’s anything more still to come?

Yeah, we are knocking things off sort of small project by small project and we are improving the liquid yields within that system. I don’t think that there’s anything headline-making with respect to Tulsa. Our significant growth projects remain the Wood Cross xpansion project as well as the El Dorado naphtha splitter. But I do think that you’ll see more in Tulsa in terms of reliability and margin capture as we go forward just with our small capital program.

And now that you’ve mentioned it, are those Wood Crosses still on track?

Yes.

Great, thanks very much.

Thank you.

Your next question comes from the line of Evan Calio of Morgan Stanley. Your line is now open.

Hey, good morning guys. Like all places, the focus is on the Permian and your color around Navajo is helpful. Let me switch gears on Wood Cross Phase II. I know Group 3 lubes market is a little bit less transparent at least to us. Do to the recent capacity expansions at Baytown and Chevron’s [Pascagulu] for lubes alter your medium-term outlook? I presume not but I’d listen to your thoughts. And then also now that you have your permits is the CSA still the gating item in the update there?

So with respect to the market for the Group 3 Lubricants product, obviously a lot of capacity has come on recently – that’s Group 2 capacity – and has affected the market price of the crack spread for base oils. Certainly that affects our short-term view but we’re looking a little farther out than that and we have to, because the demand for Group 3 oils as both a correcting or an improvement fluid for Group 2, and a base oil unto itself in terms of unique specs. So I don’t think we’re go or no go on account of new Group 2 capacity being brought on stream at Baytown and Pascagula. More broadly is the gating item the economic analysis and the cost analysis? Yeah, absolutely, and we’re probably six to twelve months from really having a clear understanding of what the project would cost and what the economic returns might be. So in addition to that as you speak to it, the crude supply remains out there and we don’t have the barrels to charge that plant yet, so there’s work to be done. But we’re still optimistic that it makes a lot of sense and it would fit very well with our Woods Cross processing scheme.

Great, thanks. And my second question, Cushing has been drawing for the past seven weeks. Where do you guys have a view on where the minimum level of inventory is at Cushing? And I know while you expect Brent TI to widen in ’14 moving up from the Gulf, do you see any differential risk in the near term as we move towards, away from tank tops and looking for tank bottoms here?

[laughter] Well, I don’t own a tank farm in Cushing nor does HollyFrontier. We read in the press that working inventories might be 20 million barrels and we’re at 26 million or so right now. Is there a chance that Cushing trades at a premium to the Gulf Coast? I really don’t think so. More aptly will we test the 20 million of bottoms? It’s really hard to say. I think you need to look at the accumulation of sweet crude in tanks on the Gulf Coast and ask who’s going to run that barrel and who’s going to continue to buy the sweet barrel and ship it down? As you know, the market structure is currently backward which means that anybody storing crude in tanks is paying $0.75 to $1.00 per month in addition to storage costs via the market structure. So I don’t think that we’ve necessarily reached a bottom in terms of Cushing inventories, but there’s certainly an economic cost; and the benefit of pushing more sweet crude to the Gulf is not clear to me.

Mm-hmm. You talked about it a little bit in your prior comments but any other discussion on the organic growth opportunity at the ATP level given it’s in your backyard at Navajo on the collection and gathering side? I’ll leave it at that, thanks.

Evan, I think Mike sort of enumerated the Malaga project which is going on. We’ve got a truck dock expansion in Las Vegas which is some additional incremental EBITDA for APT that we would expect here in the next 90 days. We’re also looking potentially in what I’ll call generically the Rockies – so [Naibrera and Uenta Basin] for some opportunities to grow our infrastructure. And then we’re also looking at third-party acquisitions, and haven’t had anything to report there. I think that market was very frothy last year and continues to be hot and competitive but we’re still looking – and particularly for things that are in our backyard and around the basins that our refineries serve because that’s the most logical area for us to do it.

Good. Maybe the key new member to your team can help there, I appreciate it.

Thanks, Evan.

Your next question comes from the line of Roger Read with Wells Fargo. Your line is now open.

Hi, good morning. I guess I’d like to come back to a couple of maybe more operational issues. You mentioned the impact of higher natural gas kind of taking numbers from a year ago and looking at the change in Q2. Would we be looking at natural gas impacts of about $45 million to $50 million higher Q2 this year versus a year ago using kind of call it a $1.20 difference in the average price?

I think that’s right. I’m not sure I completely followed your math but I’m showing on an annual basis these days every dollar change is about $41 million pretax for us, so quarterly about $10.25 million or so.

A year ago you said $0.70 in difference in price was about $28 million so I’m just kind of extrapolating off of that, and then what you had had in the commentary.

Yeah. So I’d say quarterly every dollar change is about $10.25 million and I don’t know exactly what nat gas price was in Q2 of last year. But I think if you just use an annual sensitivity of $41 million for every dollar change you probably can get there.

Okay. Completely unrelated, any update on the Tier 3 impacts in terms of estimated cost, you know, the kind of compliance programs you’re going to have to put in?

We’re still evaluating the projects that we will need at our various locations, and we will be spending some amount of capital but we really don’t have a number ready to share. And we’re looking for solutions that don’t deploy significant capital.

Just I want to add to that final answer that all of that, our natural gas sensitivity is on an un-hedged basis. So we have hedged about 25% of our usage. So after taking that hedge into consideration the sensitivity for every $1.00 change is about $32 million on an annual basis.

Okay thanks, that’s helpful. And then back to the Tier 3, as sort of a follow up there, which facilities, if you can help us remember which facilities are the ones that are probably going to have the biggest challenges catching up with the new gasoline regs?

Right. So Cheyenne probably has the largest individual challenge but its compliance date is 2020. Woods Cross running very sweet crude has the least challenge but again it is 2020. So that leaves Navajo, El Dorado, and Tulsa at 2017 and they are pretty similar with El Dorado probably having the greatest need for investment because it runs the heaviest crude, the sourest crude.

Okay. And then my last question, and I was looking through my notes so I apologize if I didn’t find the exact right spot, but a year or so ago one of the discussions was being able to add some pipeline tie-ins to bring more WCS into your plants – but that was obviously going to be offset by you don’t want to produce more asphalt. Just wondering if you can update us, maybe your thoughts on doing something along that line, what the permitting process may be or maybe you’re already into that; and whether or not that’s even something you’re still considering or still pursuing?

Right now it’s not something we’re pursuing. The limitation is the northern tier transmission capacity, call it the mainline system of [Enbridge] or capacity available within Keystone. So there are some things that we can do when new pipeline capacity is built, and we may choose to tie into Pony Express which is not a heavy crude pipeline but one that transmits Bakken down to the mid-con. But in terms of heavy barrels, we don’t see that opportunity right now.

Okay, thank you.

Yep.

Your next question comes from the line of Chi Chow with Macquarie. Your line is now open.

Hey, thank you. Doug, I wanted to ask you about the dividend policy. You’ve kept a special dividend now at $0.50 for almost three years running, I guess that’s excluding the one quarter in ’12 where you doled out two of them. But can we expect that to stay constant going forward or do you have any thoughts on varying the special and/or thoughts about the split between the regular and the special?

Chi, I think that you’ve basically got it right, and I think what we said on our last conference call and certainly haven’t had any change since then is that the regular dividend is one that we would expect to grow steadily over time. And I think it’s been almost now twelve calendar months since our increase there. We’ll see our Board next week and have that discussion certainly as we do every quarter. And on the special I think the different twist we gave perhaps on the last call is that we may see a bit more variability on that over time, perhaps paying out a bit more when we earn more and less when we earn less – with the caveat that with $1.8 billion of cash and almost no debt that you wouldn’t expect us to pay less than that until our cash was more than the $1.0 billion or less range.

Okay, great. And then I guess on [RIN] purchases in the quarter, do you have something you can share with us on that cost in Q1 and what’s sort of your expectations on [RINs] going forward here the rest of the year?

We’ll get you the costs in a minute here. Our expectation, Chi, is that we’re about 50% in need of purchasing [RINs] meaning we don’t blend about 50% of our overall volumes. What the price for those RINs will be as we go forward is pretty opaque to me honestly. We spend a lot of time and effort working in Washington and lobbying and discussing and educating and to no real avail yet. So I think the ball is in the court of the EPA in terms of the annual RVO and how they choose to moderate that in order to line up with what is really feasible in the system, but I don’t think our company has unique insights on when and how they’re going to do that.

Cost for the quarter, Chi, for compliance with RFS for us was about $45 million in total, again that’s pretax. That number’s higher than you might have expected given the average RIN cost for the quarter because we account for our RINs on a first-in, first-out basis and so we had Q4 RINs from last year more in that sort of $0.80 range that were being run off for the quarter. Although we typically don’t give guidance I’ll tell you we’ll be more in the $30 million to $35 million range for Q2 and stepping down from there if we continue to see a decline in that RIN price.

Okay, great, thanks Doug. And then maybe just one more operationally. I know the op costs have been pretty high at Cheyenne due to the weather issues the last couple of quarters and downtime. Any sort of guidance on Rockies’ kind of quarterly OPEX per barrel going forward here?

Chi, I would say that it ought to be back in more of what we saw in Q4 as guidance going forward with the big caveat of natural gas being again, every $1.00 change sort of $10 million to $11 million per quarter sensitivity.

Okay, great. Thanks Doug, I appreciate it.

Your next question comes from the line of Blake Fernandez with Howard Weil. Your line is now open.

Folks, good morning, thanks for taking the question. I had to hop on late so I apologize if this was covered, but I’m trying to get a sense of DD&A. Overall on a consolidated basis I think we were kind of in the norm of about $78 million to $80 million for Q1, I’m just trying to get a sense if that’s a good run rate moving forward for the balance of the year.

Yep, it is.

Okay. Secondly, I think in the past, Chi already kind of addressed the dividend policy but in the past I think you had kind of given an indication of different levels where the buyback would be maybe more aggressive. It looks like you repurchased a little bit during the quarter; just any thoughts around what level you may be willing to step that up?

You know, Blake, I don’t think we’re going to tip our hand quite that far. We’ve said we’d make share repurchases opportunistically and then other than that obviously offset any dilution from shares granted to management or our directors. And opportunistically is I guess a secret sauce or a secret formula – like the guys at Coca-Cola we’re not going to be able to share that.

Okay, fair enough Doug. The last one for you, I think you mentioned the kind of tight difference between crude in the Gulf Coast and WTI. We haven’t had a lot of discussion on take or pay lately but it kind of begs the question is that being witnessed in the market? I just didn’t know if you had any thoughts on whether take or pay is maybe going to lead to these spreads between Gulf Coast and Cushing crude to maybe remaining compressed for a while?

Well, Blake, there are a number of things at work, right, one of which is just simply does that barrel have a home on the Gulf Coast? But to the extent that those pipelines are subscribed on a take or pay basis the transportation cost can be perceived as sunk. So then you’ve got to figure out is there a spot for that crude and does the crude quality that is coming in warrant bringing it to the Gulf Coast at all? And I guess we don’t have a lot of specific insight into what other market participants are doing, but I think if you just look at the indicator prices of a TI Cushing versus Houston Light or what they’re posting now for Port Arthur, you can conclude that the full transportation cost is not reflected in the differential. And those things happen in this business. They tend not to persist through time but they do happen.

And I’d add that my understanding is that all of them have some, albeit small but there is a variable component to shipping a barrel even when you have a take or pay arrangement. So you have to consciously decide that you’re willing to spend an incremental $0.60, $0.70, $0.80 to ship a barrel that might be out of the money in the example that you’re giving us, Blake.

Right, right. Thanks for your comments, I appreciate it.

Sure. And Chi, as a follow-up we gave on our last quarter $260 million quarterly as a run rate for our OPEX so I’d use that number going forward, again unless there’s a material change in nat gas price.

Your next question comes from the line Faisel Khan from Citigroup. Your line is now open.

Thank you, good morning – it’s Faisel from Citigroup. I just had a few questions. If you can go back to some of your comments on the potential for acquisitions or [granite] growth in the midstream sector and kind of how you would use ATP, so are you saying that the acquisition market is still pretty frothy or has the market sort of cleared? Are there more opportunities now today at the right price than there were sort of last year?

Faisel, I think that it is a very competitive marketplace out there. You have not only the traditional MLPs but a lot of privately funded entities that are set up as midstream businesses with an expectation of going public and a strategy of growing by acquisition. So it is still strongly competitive. The multiples that we’re observing for sort of low-growth transportation assets might be 12x, 13x, 14x cash flow – and those prices to us are pretty high unless there’s a strategic driver. So we’re really focusing in our backyard with respect to our MLP and particularly increasing our capabilities and gathering system within the Permian basin.

Okay, great. And then I think you guys mentioned some of the opportunities up in the [Yuenta] and the Rockies. I think Newfield discussed on one of their calls that they’re looking for sort of a pipeline solution into Salt Lake. Is that something that would be something that you would participate in? Is this related to some of the heavier crude or is this related to just light, sweet crude?

Yeah, that project is being discussed by some industry participants and I’m thinking we are most likely under confidentiality around it and so I’m not going to go further. But it’s an interesting concept because the [Yuenta] is going to be producing probably upwards of 60,000, 70,000 barrels a day as we look forward and that’s a lot of trucks on the road. So a pipeline solution might make a lot of sense up there.

Okay, understood. And then just on the, you guys in one of your press releases I think discussed sort of your expansion of your asphalt business into the southwest; and I think you discussed that also in the realm of leasing an asphalt terminal. Is that a business that’s going to have a major contribution to the bottom line or is that just sort of expanding your reach in terms of where your product can get?

It’s really more the latter. It’s a retail distribution capability within our asphalt business, and we’ve taken leases for two incremental terminals which has traditionally allowed us to uplift our margins pretty substantially. And we’re beginning to develop a pretty nice franchise in that southwestern asphalt business.

Okay, but nothing material that we should see drop down to the bottom line?

Nope.

Okay, thanks, I appreciate the time.

Yep.

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

Hi, Mike, in (inaudible) the 77% sour crude, I assume that that’s WTS. What’s the opportunity for you to reduce it and replace with the light sweet?

Well, the 77% sour is WTS and that lands at the refinery, other than in the month of February this year it seems, but it tends to land slightly cheaper than the WTI Midland alternative. So it’s six and one-half dozen of the other. The important point right now is that we are buying crude on a Midland basis now for that Navajo refinery and are able to realize the benefits of being in the Permian. And whether it’s the real light barrel or a WTS grade our refinery has capacity to handle either of those, so we really shop for price.

Sure, I understand but I’m saying that from a configuration standpoint, I think there’s an argument in the industry or some view that with the increasing condensate production in the [thermal] basin that you have more and more people looking for maybe a heavier barrel that (inaudible), and as a result WTS may continue to trade on a premium going forward versus the Midland. And if that’s the case what I’m trying to understand is that just based on your configuration what is the minimum that you can run in terms of WTS?

The sours that we’re running at the Navajo refinery are a very light sour. So based upon our configuration we probably can run mostly sweet crude out there because the gravity is really not the issue. The sour that we’re buying tips over based upon sulfur content – it’s higher than the TI spec. And it also is within, is being produced in the area of that Artesia gathering system through which we feel like we have a competitive advantage around procuring, transporting and running those barrels unaltered. So I’m not avoiding your question but what I’m suggesting is that I think within reason we’re able to buy that WTS barrel and have it be economically advantaged against what we might otherwise buy as a generic TI Midland.

Okay. The last one then: do you have any rough outlook for 2015 CAPEX and turnaround expense?

Yeah, Paul, I think as we’ll complete the Woods Cross project next year and clearly we haven’t talked to the Board about any new projects, but right now my view going forward would be similarly in that low $400 million’s - $400 million to $420 million of CAPEX next year with turnarounds being in the $75 million to $100 million range.

Thank you.

There are no further questions on the phone line at this time. I will turn the call back over to Ms. Julia Heidenreich.

Thank you all for joining us this morning. If you have any follow-up questions you can reach Investor Relations for the rest of the day, and otherwise we look forward to sharing our Q2 results in early August. Have a great day.

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