Welcome to the HollyFrontier Corporation’s Second Quarter 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.

Good morning, everyone, and welcome to HollyFrontier Corporation’s second quarter earnings call. This morning we issued a press release announcing results for the quarter ending June 30, 2014. If you would like a copy of today’s release you can find one on our website at 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 financial measures. Please see the press release for reconciliations to GAAP financials. Also please note that information presented on today’s call speaks only as of today, August 6, 2014. 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 $176 million or $0.89 per diluted share. Our second quarter EBITDA was $388 million, which represented a 15% improvement over the first quarter EBITDA of $339 million. Improved refinery operations, attractive Midland crude differentials, and good heavy crude economics during the quarter helped to drive this result which was influenced in the downside by weaker coal product cracks and back gradation [ph] in the crude market structure. Our second quarter financial performance was also affected by some one-time items relating to non-cash write-down’s that Doug will address in detail. These charges combine to reduce the quarterly EPS by about a dime. Second quarter crude throughput was 439,000 barrels per day versus guidance of 425,000 barrels per day. We ran 23% sour, and 18% WCS and black wax crude. Our average laid-in crude cost across the refining system was $3.90 – pardon me, $3.97 per barrel under WTI. Regionally we experienced average laid-in differentials under TI as follows; $10.84 in the Rockies, $1.92 in the Mid-Con, and $4.59 in the Southwest. Our consolidated refinery gross margin for the second quarter was $14.54 per produced barrel, slightly below the $14.75 of gross margin recorded in Q1 of 2014. On a regional basis, our second quarter gross margins per barrel ranged from a high of $17.49 in the Rockies to a low of $13.01 in the Mid-Con. During the quarter, crude differentials generally moved against us with the exception of the Midland crudes. Inland coastal and Canadian heavy dips compressed 30% and 13% respectively, pressuring our capture rates in the Rockies and Mid-Con regions. Our Navajo refinery ran very well through the second quarter, operating…

Thanks, Mike. For the second quarter of 2014 cash flow provided by operations totaled $327 million. Second quarter capital expenditures totaled $102 million, excluding HEP’s $18 million capital spend. Turnaround spending in the quarter totaled $5.4 million. We maintain our full year 2014 CapEx guidance of approximately $400 million and turnaround spending of $77 million. Total refinery segment operating costs for the quarter totaled $237 million. As of June 30, 2014, our total cash and marketable securities balance stood at $1.8 billion, in line with our March 31 levels. HollyFrontier debt totaled $189 million excluding non-recourse HEP debt of $839 million. On July 1, we terminated $1 billion senior secured credit agreement and replaced it with a new $1 billion senior unsecured revolving credit facility which matures July 1, 2019, to bring us in line with the standard for investment grade rated companies. The unsecured facility should save us approximately $1.7 million a year and give us additional flexibility. HollyFrontier currently owns 39% of Holly Energy Partners, including 22.4 million common units in the 2% GP interest. The current market value of our LP units is approximately $749 million as of last night’s closing price. Second quarter general partner incentive distributions were $8.1 million. Through the first six months of the year we have received $39 million in cash distributions from HEP. In the second quarter we announced and paid a $0.32 regular and $0.50 special dividend, distributing $163.4 million to shareholders. Today we also announced a $0.32 regular and $0.50 special dividend to be paid in the third quarter. Since our July 2011 merger, HollyFrontier has now returned approximately $2.4 billion in capital to shareholders through regular dividends, special dividends, and share repurchases, including today’s announcement. As of June 30, we have $312 million remaining under our share repurchase authorization. And as of today our trailing twelve-month cash dividend yield stands at 7% relative to yesterday’s closing price of $45.81. During the quarter, we incurred $31 million of pretax charges relating to the write-down of several assets at our Navajo, Cheyenne, and Tulsa refineries. $7 million of that ran through the OpEx line, and the rest through depreciation and amortization. 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 investor page. 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 now Stephanie, I believe we’re ready to take questions.

(Operator Instructions) Thank you. Our first question comes from Doug Leggate with Bank of America. Your line is open.

Thanks, good morning everybody. Mike and Doug, I wonder if I could ask the dividend question in slightly different way, guess, that’s the record for a guess [ph] but – what are the other potential calls on cash as you look forward in terms of organic opportunities, I guess, an elevated oil price environment, you’ve got different letters of credit requirements I guess, but when you look at more that are kind of planning base for your use of cash, what are the other calls on cash that could otherwise change your way on how you treat the special versus the ordinary dividend? Then I’m going to follow-up this.

Sure. Doug, they are effectively two. The first is, a promising project in Salt Lake City in Woods Cross that relates to conversion of waxy crude into Group III or higher lubricants, and we are continuing to develop this project, internally we haven’t got into a final investment decision point but we believe that it’s a very high return project but also high cost in terms of capital. And so we’re continuing to run that to ground in terms of initial engineering and commercial development with expected final investment decision sometime next year, middle of the year. Second is new focus on share repurchase, and that is something that as you probably know, or as we said repeatedly, we debate and discuss every quarter and it’s getting more internal and first hand [ph] discussion at this point. We’ve had a long string of paying out a very high cash yield on our stock, and we’re continuing to do that this quarter, obviously, we think it’s benefited our shareholders to a great degree and we’ve seen a lot of other companies follow us in this. But share repurchase remains a large opportunity for us, as well, particularly at these types of valuations.

Mike, just to be clear as a point of clarification, after three years that would be quite a big switch, are you suggesting that you forgo the special for buybacks given where the stock is or both are on the table?

No, you asked I think what the additional cash calls on the stock might be?

Right.

And so I highlighted those two, I’m not suggesting forgo but those are incrementally where we could invest cash for shareholder value.

Got it, thank you. My follow-up is, so a different question there. Earlier this year you made some changes obviously, on the management of HEP, I’m just wondering how any – how that may have changed or may have changed the focus on additional initiatives that could resume growth and not part of the business? And I’ll leave you there, thanks.

Look, we have a great management team in place at HEP and we have lot of confidence in them. I’d say a solid half of their effort is targeted towards external growth right now, externally generated revenues, and they highlight that in their quarterly discussions with their unit holders but crude gathering in the Permian – and generally logistics support in the Permian and some in the Rockies are their principal areas of focus in addition to those investments which facilitate HFC’s growth from a logistics perspective.

Alright. Mike, I’ll let someone else jump on. Thanks very much.

Thank you, Doug.

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

Hey guys, good morning.

Hi, Paul.

Before I ask my question I just want to make a request. It’s great that you guys gave unit number and the GP cash probably in the call but if possible, with that in the future if you can actually put it down in the press release, I think that will be really helpful for many of your investors.

Thank you, Paul.

I guess that with the – that the market rumor talking about CITGO, the refinery could be up for sale. Mike, can you maybe refresh our mind in terms of how you guys be on the M&A market or their opportunity they have now, important or significant that part of your strategy over the next, say, one or two years.

We have a refining system that we have great confidence in, we’re working hard to develop it to improve it to reliability, and improve the discounted crude fees to our plant. So that is the heart of the fairway in terms of our strategy. Incrementally, acquisitions, CITGO could fit very well, it’s obviously a large buy if it’s actually for sale. But we look hard at all these types of opportunities, particularly those with an Inland crude supply tributary, and so CITGO would obviously fit that. But with that said, we’re really focused on returns at this company and to the extent that we feel like we can increase our share value by presenting such an acquisitions we’ll do so, and if the price point or the opportunity doesn’t fit us, we’re very happy with the assets that we have.

Mike, is there any particular financial metrics in any M&A transaction that you will be focusing on that that need to be accretive to the UPS or that you need to have a particular multiple. I mean, what kind of metrics that you maybe internally consider?

Well, frankly, with our current balance sheet and abundance of cash, anything that we buy is accretive to EPS to some degree I would assume. So it has to be a higher hurdle than that. Presumably we’re going to pay market value in any acquisition that we undertake, so we need to be able to add to that incrementally, additional earnings through combination synergies managing the assets better or different view on the future. So that’s really what we’re looking for, this is how do we add incrementally to the value of the business that we would otherwise pay market value for.

Paul, I would just add to that that given no debt on our balance sheet and the extraordinarily low cost of debt today, as Mike said, you can make accretion look very appealing but if you look at our 20-year plus return on capital employed number of write out are just above 20%. That’s a hurdle that we’re proud of and one that as a management team we’re compensated on one that will continue to look at as needing to be able to return a healthy risk return for our shareholders. So it’s not just accretion, it’s certainly return on capital as well.

Great. Alright, final question for me, if I look at your Southwest system, your crude [ph] in the second quarter is quite dramatically different you’re your historical past. You run only 1% on there, have you start with normally you’ve won more 8% to 10%, is that just a function because the mid 90s – so why this quarter or that this is really going to be the news maker because you’ve changed the way how you’ve won it going forward.

The crude dynamic there is as follows; WCS was crude trading at WTI minus $6 to $8 at Cushing, and when we used that market price and compare it to our opportunity at Navajo refinery we find that we have much better crude economics by buying that local Midland barrel which is discounted to the same degree or wider despite being a weak crude barrel. So unless and until that inverts, I would expect the Navajo system to be running local crudes, Permian crudes, to the exclusion of WCS.

Thank you.

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

Good morning. I guess just one other question along the lines of the rumors out there about CITGO, as you talk about the 20% ROCE long-term, what really is kind of the hurdle rate, I mean, understand 20% is something you’re proud of and would want to maintain but if you return 15% we generally be happy. So can you kind of help us understand maybe what your own sort of minimum expectations would be in an acquisition or investment there?

We’re certainly looking for happy shareholders Roger, so I guess 15% maybe the number but in fact, we don’t have a hard hurdle rate around an acquisition opportunity. We obviously look at return on capital employed hard, we look at what we believe our cost of equity and weighted average cost capital are. And for our internal investments, we expect to double those returns in the capital that we put to work within our plans, and that’s among other things to cushion for lack of visibility to forward margins. As it relates to an acquisition, I can’t give you the secret sauce because I don’t have it but I do know that in a competitive process you’re going to pay about market value for these assets and if you can’t add to them through different management or combination with your own existing assets, there has been effectively zero uplift in which you’ve purchased. So that’s so much guidance I can give you.

Okay, that’s helpful. And then, any possibility you can go into more detail about the opportunities in West Texas, I mean you mentioned some of them in the preview part – your 40,000 barrels a day in the near term, more behind that. At one point there was talk of a real option out in that area, I’m just wondering if you could give us maybe a little bit more granularity on what is possible out there, I mean is real back on the table, yes/no/maybe, is the rest of it conventional pipelines? We continue to see the area of drilling expand out there, maybe kind of, give us an idea of where you’re stronger areas might be for a future growth?

Sure. The Delaware Basin is our home court in terms of further developing our gathering and transmission infrastructure, and traditionally that gathering system serves the Navajo refinery. We’ve obviously come to the conclusions that we need to be able to gather crude and get it to market in addition to consume it ourselves in order to provide a value-added service to the producers. And so next phase is more extensions to the existing gathering system but also linking that system into transmission points where the crude can get to the Gulf Coast in Cushing. And that affords us the growth beyond our refining appetite, to be able to gather effectively more than we can just deal. That I would say is our greatest opportunity because of our established infrastructure and competitive position out there. Real [ph] is not presently on the table though our Lovington facility has very good real access and the economics of developing that would be as good as anywhere. In our view, putting a real system in place requires a continued view of Permian differentials inside Cushing of probably $8 to $10, and that’s – the question is, whether the shipper is going to make that commitment to the facility or whether we do on speculation, thus far we have not speculated.

Appreciate that, just one last follow-up there on Navajo. Is it receiving all its crude by pipeline or are you getting crude in by truck or by rail at this point from the Permian area?

No, it’s principally by pipeline through our gathering system. We run crude trucks out in the Permian, largely to feed the gathering system.

Okay, that’s helpful. Great, thank you.

Okay.

Our next question comes from the line of Sam Margolin with Cowen & Company. Your line is open.

Good morning. I wanted to circle back to those – to that right down, it sounds like from the language of the press release it was more focused on sort of ancillary infrastructure, maybe not quarter refining units but if we could just get a little more color on that that would be great.

Yes, sure, Sam. What I would tell you is, there were – it was a list of few different things and in Cheyenne, we had a disposal well that we drilled in order to try and send wastewater down it. As it turns out, after we got to the water table, thought we were an area because there was another company that had drilled very near there that we could put water down hole turns out we couldn’t because it was drinking water. So that was $6.5 million or closer to $7 million of OpEx for Cheyenne in the quarter. In Tulsa, we had some units around treating of gasoline that we found better technology, and replaced it with what I would call newer and better operating units that would lead the less OpEx in the future perhaps, and so, took idle assets out of play. There were several like that in Tulsa, and then a couple in Navajo which totaled that sort of $25 million of DDNA.

Okay, great, thank you so much. And then just one more on the Delaware Basin initiatives, I wonder – first of all, if you could just remind us on the exit rate gathering volumes, if it actually exceeds Navajo when you’re looking at third-party sales as well, and also in light of the condensate permits, it sounds like you guys have a really close value on everything from the upstream angle in the area, with your discussion about the recent type curve moves but – if you’ve seen any broader API progressions up, and if you might also consider maybe some splitters or other assets that could position you and HEP down the road to maybe take advantage of not necessarily changing legislation but more, I guess solid guidance from the BIS about what the specs are?

That’s a mouthful, okay, I’ll try. First, on your question I think you were asking about gathering volumes, growth, and that, and whether we need to have exit capacity in order to gather where we are today. The answer is, today our gathering volumes are inside of our crude appetite, but as the – what HEP refers to as the Malaga system, our Southeastern Mexico new gathering extension, that additional, upto 40,000 barrels a day will definitely push us over where we can consume that after the refinery, particularly when one considers refinery turnarounds and then things such as that. So that’s the need to get connected into transmission infrastructure, you get those barrels to Gulf Coast or to Cushing, and be a reliable gatherer for our producers. Today gathered volumes are in 50% to 60% range versus crude distillation of approximately 100%. Moving beyond that, your question I think was relative to the light crude and condensates in particular, this investment in condensate splitting makes sense for us. And the answer to that question really depends upon logistics infrastructure to move condensate from the very light ends, from West Texas to or New Mexico, in fact to the Gulf Coast. Obviously, there is not much of a market locally in Southeast New Mexico for the light condensate and so we’ve concluded that railing that material is a fairly expensive long-term proposition, probably $10 a barrel to move that to the Gulf Coast. So condensate splitting in West Texas in our view will depend upon our transmission infrastructure to a market that de-values the light product. That hasn’t happened yet but there is discussion of such a line. So, that’s the one that we’re sort of watching and the question is really where is it most economic to split that condensate. On the crude exports front, as a consumer and manufacturer of crude oil we are not supporters of crude exportability. We think that it’s one piece in a puzzle of U.S. Energy Policy, and then that one piece by itself shouldn’t be addressed that the RFS and other items should be addressed along with. And with that said, we’re great supporters of free markets, we think that it creates wealth for all of us, it’s just that we don’t believe addressing crude exports and isolation makes sense. So, what happens at BIS and how they move, I think they made a strong move relative to the pioneer and enterprise decision and have since retrenched and gotten a lot of negative feedback from the elected officials. So we’re just going to have to see how that goes, I don’t think I have a great policy insight other than to watch it and read it as much as you are.

Okay, thanks so much. I appreciate it.

Okay.

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

Hi, good morning, everyone.

Hi, Paul.

Can you talk about demand, I think there was some issues with fiscal, obviously in the quarter and pricing that – could you just give us your latest thoughts? Thanks.

Yes, the distillate, it is the key product in terms of the U.S. crude complex. I don’t think – pardon me, refining complex, I don’t think anybody sees great gasoline demand growth in the near term. And that was a swing during the quarter and in cracks, and probably demand, I think it’s mostly related to export loadings, off the Gulf Coast and how much Russian and Persian Gulf distillate is moving to Europe, it’s obviously a global market now. I don’t know that there has been any real compression in demand for – you know that the new over the road engines on the truck fleet are substantially improved in terms of their efficiency. So, when we see diesel cracks come into the level of gasoline cracks or inside that, we have some concern, that has since changed and refiners I think are probably taking action in terms of product slates and crude throughput even in response to – that the margin activity that occurred during the month of July. So, what I’d tell you is that we’re watching it, we don’t think that the story is different but obviously, for a period of three or four weeks at least it caught our attention.

But that seems better now?

Yes.

That’s a simple answer, thank you. And if you could just continue the thought into where you see us in the cycle – I don’t know, it’s an honest impossible question but I guess, what I’m driving at is two things; firstly, your hedging strategy in the past. You’ve been quite openly prepared to look in when you think things are over stressed, in other direction. And then secondly, your acquisition strategy, you stood out as the finest of both, refining when we were at the bottom of the cycle. I would imagine that the current point, you would be less interested in doing deals just because my best guess is that we’re somewhere around mid cycle right now. Thanks Mike.

Sure. So as to where we are in the cycle, I’ll steal from Doug who I think is pretty clever but he says, we’re in the eight [ph] it’s a double header. And I think that’s pretty accurate, that match is up well with your thought around mid point in the cycle. I believe that current margins, current demand reflect that. We have not seen much of an increase yet in light products demand in the United States though the economy is definitely improving. And the residential real estate homebuilding market is improving, that’s a big driver of gasoline demand to job site type activity. And employment is improving, not unemployment rate but actually job numbers are going up, so we’re pretty bullish about that. Offsetting, you’ve obviously got a lot of volatility induced by geopolitical events and that I think scares everybody, it certainly scared the market over the past few days. But does that sidetrack where we are in terms of cycle of petroleum products demand in the United States and globally, it’s not clear to me that it does. The producers are doing very well in terms of growing production, increasing efficiency. This is significantly a U.S. versus the world crude oil story, our sector at this business is monetizing that into a saleable refined product that can travel. And I think that’s the role we play, we need to look to international demand or to make the conclusions about where we are in the cycle. As to our own company’s acquisition strategy, I’d say that things are neither cheap nor expensive right now, they seem sort of in the middle. I wouldn’t feel as though we were stealing something if we bought it in this current environment, but it also doesn’t feel important [ph] to me.

Great. Was there anything to add on hedging strategy? Thanks.

Doug?

Paul, what I would say is, ordinarily, I think – and then most cases, folks buy HFC shares because they want exposure to cash [ph] and our typically hedging strategy historically, when we see what we see or when we see what we see as/or extraordinary or very top-end of a 5-year or 7-year or 10-year range, and we get a chance to lock some of that in, it’s probably prudent to do so, otherwise if – using your term, it feels more like mid cycle. I’m not sure as a management team we’d be creating much value by locking that in, we certainly don’t have an interest expense burden that we need to worry about or other reasons why folks typically hedge. So, only when we see prices as being extraordinary, do we typically hedge.

Yes, I mean, we measure that as a two standard deviation from historical average and we can always debate what history is, but if that gives you a feel for where we like to hedge, and we’re not there right now.

Thank you, guys.

Yes.

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

Hi, guys, good morning, a couple of quick ones. Your guidance I think for the third quarter throughputs was – I think you said 405 which looks bit less than the second quarter. So I’m just – if I go back right, will any color on where that drop off is being driven from?

Yes, three things really. The first of its which is that we have some planned maintenance going on in the third quarter at the El Dorado, large turnaround of the FCC will commence towards the end of this quarter. We also have had some unplanned maintenance, particularly El Dorado and Cheyenne, which affected crude throughout during the quarter already. And finally, as we looked at Mid-Continent gasoline margins, in month of July, and saw a $5 crack spreads, our conclusion about how much crude to run in that sector was affected. So we’re turning that down a bit. So the combination of those three items really represents the difference between second quarter and third quarter.

And then on the logistics side, I mean, outside of HEP – maybe you could give us a little bit of color of how much Holly is actually spending in terms of CapEx on logistics in 2014? And maybe how that might change based on the opportunities that appreciates some of these things, new wins and stuff that probably still work in progress, but how that might change in 2015?

Right, so – our CapEx spent on logistics is nearly a 100% executed through HEP. And we then engage through T&D commitments to HEP. HFC [ph], it is not building a warehousing logistics assets at present, whether we take – make commitments to third parties for additional logistics capacity, really depends on the individual opportunity and I’m not prepared to discuss those but really it’s not a focus for HFC CapEx.

Okay, thank you for clear. Just on then, macro question, I mean obviously, in the Southwest everyone is benefiting from this brand spread, I mean you guys are probably going to be as close to it as anyone. There are worries that bridge techs one of the pipes would narrow that and spread when it starts up later in this quarter but then, as a counterpoint to that some folks suggest that the connections into Colorado City are perhaps not yet ready and therefore it’s going to trucked volumes. I’m just wondering if you had any perspective on how that ramp up might affect the wide spreads that we’re seeing at the moment in the Midland?

I think you’ve pretty well characterized it, the bride techs throughput potential is 300,000 barrels a day, I think in the press we’ve read that the ability to get that amount of crude to the Colorado City injection point is limited or nil right now, and so they are really dependent upon trucking. That’s going to change overtime of course, our pipe is being put in the ground but as a near term threat to run 300,000 barrels a day beginning September, I would discount that heavily. And on the flipside of that is obviously the growth in the Permian, which feels like a pace of 200,000 a day year-over-year. So as each of these pieces of logistics infrastructure come on, and as I referenced in my opening comments, there is a reshuffling, and sometimes it’s painful and it causes you to question your underlying assumptions but crude growth is the driver and we’re fairly confident based upon the comments from our customers in discussion with them that the growth in the Permian has very long legs. So I think bridge tech is an important piece of infrastructure but it’s not determined at a long-term about Midland versus Cushing or Gulf Coast differentials.

And one final small one, any crude discounts emerging say versus Cushing WTI in the Tulsa region, just as domestic production kicks off in that sort of Mid-Con area?

No, those are significant, there is a little bit of money to be made or discount to be gathered through gathering by truck into the Tulsa facility. But Tulsa is very close to Cushing and there is lot of pipe in the ground in Oklahoma, so I wouldn’t tell you that we expect wide Tulsa/Cushing differentials going forward.

Thanks.

Our next question comes from the line of Mohit Bhardwaj with Citigroup. Your line is open.

Yes, thanks for taking my question. Doug, I just wanted to follow-up on the earlier question regarding hedging. So, I think a lot of your comments were on the product side but you still have the hedges in place on the WCS side, I would assume as you have in the past, if you could just clarify that for us?

Sure. I think Paul’s question was more towards product hedges at least, that’s the way I understood it. You are correct, when we see an opportunity, really more to lock in a supply agreement perhaps with a Canadian producer, for that matter a bank that’s willing to sell it forward. There is a certain amount of Canadian heavy crude that fits very well into our Mid-Continent, be in particular, El Dorado, and then Cheyenne refineries. And so when we see something in the low 20s – on some volume we think it makes some sense to lock that supply up and guard against – perhaps new pipelines or other opportunities. I would say that that spread seems to be widening in the near term but that’s something we’ll continue to pursue I think in the low 20s. It’s the other that is probably worth mentioning has been natural gas, we do have some hedges on the books for three or four more years with natural gas in the high 3’s or low 4’s, again, particularly it’s tough for us, in one way we see that as price protection.

And Doug, if you could just clarify the inter [ph] purchases as well, I think in the past year you have mentioned that TI – 80% of that somewhere around that and you have some term contract as well, is that how it works or are there hedges in place for that as well?

Yes, we have a confidentiality agreement in place with new field around the 10-year supply agreement with them. What we can say is that it approximates the historical average and your number is very close to being right, it’s about 80% of WTI and then we have about $5 of transportation from the Basin down to the Salt Lake City refinery. So lands into the refinery at a $100 crude, about $15 off.

Okay. And Mike, if I could just ask one final one, a lot of your peers have followed this whole diversification strategy in terms of where their cash flow streams are coming from, and you obviously have the logistics side of the assets, and in the beginning of the call you also mentioned the project at Woods Cross, is there any opportunity for you guys to get involved on the condensate side, you mentioned that, and also on the chemical side as some of your peers are doing, if you could just clarify that for us?

Yes. Our focus really is around lubricants, we have a very solid group one business in the Tulsa marketplace, and what I believe we’re pretty strong capabilities in the lubricants marketing. So our view is that pushing that through converting waxy crudes to lubes is synergistic with our existing capability, and the economics of that physical process appear to be pretty attractive. So that’s sort of where we’re pointing the gun right now. There are obvious opportunities in the logistics space, anytime you have crude production growth and we participate in that through HEP. As I said previously, HFC is not intending to make significant logistics investments; we do that through our MLP subsidiary for cost of capital reasons. Getting to chemicals, but that really is beyond the scope of where we play, so I’d really pointed towards lubricants and crude gathering as those things apart from fuels production that we’re most likely to participate in.

Thanks for your comments.

Our last question comes from the line of Evan Calio with Morgan Stanley. Your line is open.

Hi guys, this is Manoj Gupta today. Couple of quick questions, first, following up on Ed’s question, what is the plan turnaround activity looking for the fourth quarter? What are the plan turnarounds right now that you have already announced for the fourth quarter?

Give us one second on that one. Maybe go ahead and ask your second question and we’ll come back to you with that.

Sure. What was the RIN compliance cost in the second quarter and given current RIN prices, what kind of compliance cost are you looking into the third quarter?

Okay, I guess you get the award for the most technical questions today. Give us a second to pull that data together as well.

I’ve got it in front of us, go ahead [ph]. So we called out in the initial comments, significant turnaround activity at El Dorado and that includes the cat cracker and the gas oil hydrotreater, as well as some other ancillary units, the alkylation unit comes down along with. So that’s probably a 30 to 35 day outage in aggregate, and during that period, crude production is brought to about 70,000 barrels per day. So that will be a large turnaround. In addition to that we’ve got crude unit and two hydrotreating units at the Artesia refinery and Navajo system. So the Artesia crude unit distills approximately 35,000 barrels per day of a 100 that the Navajo system runs, rather to give you an idea of scope of that, and again, approximately 30 day downtime. Beyond that we’ve got in Woods Cross, some work within our reformer and downstream – upstream, not the higher treating downstream hydrogen consuming units and that’s planned for the month of October. So that’s significant work but not as large as what is going at Navajo and El Dorado.

And on the RIN side, about $35 million spent for the quarter, showing an average price of pretty close to market, around $0.50 per RIN assuming no material change there our estimates going forward are very similar for third and fourth quarter.

Thank you so much guys. Thank you for your comments.

Sure. Stephanie, you’re still with us?

Yes, I am with you. I have another question that has queued up, from Jeff Dietert with Simmons. Your line is open.

Yes, it’s Jeff Dietert with Simmons.

Hi, Jeff.

I lost the call – for a part of the call, so I apologize if this has already been discussed, but I was curious if you could discuss the quality of the crude coming in on the Southeast New Mexico system, if you know what that quality looks like. And more broadly, your continuing run kind of 80% West Texas Sour at Navajo, and what’s curious about your thoughts on West Texas Sour versus WTI Midland crudes, obviously, both of them are very heavily discounted at this point, but WTS has kind of moved above Midland. Do you think that’s sustainable, what are your thoughts there and how flexible your capabilities stood just to that?

Jeff, we’ve got quite a lot of flexibility because of the infrastructure that we’re connected to, the Ruslands HEPs barrels are more sour, more heavy than the light sours that we gather within HEP gathering system near the refinery, so both sit within the WTS classification. Beyond that – as we progress south into Southeastern New Mexico and towards White City, our experience today is that we’re not seeing the very light suite barrels, and so we don’t have a concern that some have expressed that those are going to be that condensate rich and not effectively fill out the middle of the barrel, that’s important, and obviously the diesel economics. So we cover a lot of geography in terms of the crude that we have access to, we don’t have concerns about the high gravity material in either of our pipeline system or in our refinery. And with respect to your question about WTS versus TI and great differentials, both as traded in Midland, I think the common lower is simply that when you increase the gravity of the production that TS barrel is becoming more valuable as blend stock in order to meet pipeline specifications around vapor pressure of nothing else. So that is where the incremental value that have your sour barrel, WTS appears to be – but we don’t have the system constraints that are causing us to value it in the same way as the market appears to be, and we also aren’t seeing the real high gravity material.

Thank you.

Good, thanks, Jeff.

There are no further questions. I turn the call back over to Julia for closing remarks.

Great. Thank you all. Investor Relations will be available this afternoon for any of you who have follow-up questions and we’ll look forward to our next earnings call in November.

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