Welcome to the HollyFrontier Corporation's Second Quarter 2015 Conference Call and Webcast. Hosting the call today from HollyFrontier is Mike Jennings, President and Chief Executive Officer. He is joined by Doug Aron, Executive Vice President and Chief Financial Officer; and George Damiris, Executive Vice President and Chief Operating Officer. At this time, all participants have been placed in listen-only mode and the floor will be open for questions following the presentation. 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, Andrea. Good morning, everyone, and welcome to HollyFrontier Corporation's second quarter 2015 earnings call. I'm Julia Heidenreich, Vice President of Investor Relations. This morning, we issued a press release announcing results for the quarter ending June 30, 2015. If you would like a copy of the press release, you may find one on our website at hollyfrontier.com. Before Mike, George and Doug proceed with their prepared remarks, please note the Safe Harbor disclosure statement in today's press release. In summary, it says statements made regarding management expectations, judgments or predictions are forward-looking statements. These statements are intended to be covered under the Safe Harbor provisions of federal security 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. The call also may include discussion of non-GAAP measures and please see the press release for reconciliations to GAAP financial measures. Also, please note that information presented on today's call speaks only as of today, August 5, 2015. Any time-sensitive information provided may no longer be accurate at the time of any webcast replay or re-reading of the transcript. And with that, I'll turn the call over to Mike Jennings.

Great. Thanks, Julia. Good morning. Thank you for joining us on HollyFrontier's second quarter earnings call. Today we reported second quarter net income attributable to HFC shareholders of $361 million or $1.88 per diluted share. Excluding the $135 million non-cash lower cost to market inventory gain, net income attributable to HFC shareholders was $278 million or $1.45 per diluted share. Strong refining operations, improved realized margins, and lower costs drove more than a 60% increase in earnings per share year-over-year. Second quarter EBITDA excluding the inventory adjustment was $531 million, 37% above the comparable quarter last year. Adjusted second quarter refining segment income from operations was $441 million, more than 50% above the $292 million reported in the same quarter last year. Despite tight crude differentials in the current quarter, HollyFrontier's EBITDA in refining operating income approach levels not seen since early 2013 when the Brent CI spread was nearly $20 a barrel. Our refineries are operating safely and reliably across all regions. Second quarter 2015 refinery utilization rate was 101% of nameplate capacity and 106% of expected crude throughput, the highest quarterly rate realized since our merger. In the Mid-Con, the Tulsa and El Dorado refineries operated there over 100% utilization rate, achieving new record crude rates in the second quarter. Our feedstock optimization strategy in the region continues to drive performance improvement, eliminating previous crude rate constraints caused by gas, oil and acid containment. Strong operational performance in the quarter allowed us to capitalize on the constructive margin environment. On a per barrel basis, consolidated refining gross margin was $17.42 or 20% above the $14.55 of gross margin recorded in Q2 of 2014, driven by a combination of higher benchmark margins and improved margin captured. We're continuing to see strong gasoline demand, encouraged by lower prices at the pump and by an improving labor market. Summer gasoline pricing is the lowest we've seen in years, with the national average at $2.64 per gallon in the second quarter. Monthly vehicle sales remained strong and skewed toward SUV and light truck sales, and data through May shows vehicle miles traveled now surpassing 2007 levels by 3.4% on a year-to-date basis. U.S. average gasoline cracks remained attractive during the month of July and strengthened into the third quarter, rising from $20 per barrel in the second quarter to approximately $25 for the third quarter to date. Excellent operational performance and opportunity capture across our refining system has continued into the third quarter. We're clearly beginning to see the results of increased investment in and focus on operational reliability. And I congratulate my colleagues across the company for the way they have translated this initiative into action. With no further planned maintenance in 2015, we expect that high throughput rates at our refineries will combine with the constructive margin environment to generate very solid financial results for the remainder of the year. So, with that, let me turn it over to George Damiris, our Chief Operating Officer.

Thanks, Mike. Second quarter crude throughput was approximately 446,000 barrels per day versus our guidance of 420,000 barrels per day. Average laid-in crude cost across our refining system was $2.55 per barrel under WTI. Total refinery operating costs for the quarter were $220 million, an 11% reduction compared to the same period last year. Cheaper natural gas prices and lower maintenance expenses were the major contributors to our operating expense improvement. Rockies' crude throughput was 52,000 barrels per day. Average laid-in crude cost was $5.01 per barrel under WTI. Refinery operating costs were $9.67 per throughput barrel. I expect Rockies' OpEx to revert to $6 to $7 per barrel range after bringing the Woods Cross expansion online and as we make further progress achieving our cost targets. Woods Cross successfully completed their June turnaround. Mid-Con crude throughput was 280,000 barrels per day. Average laid-in crude cost was $2.17 per barrel under WTI. Refinery operating costs were $4.01 per throughput barrel. Past upgrades made to the El Dorado SGC and continued optimization of intermediate streams between Tulsa and El Dorado has allowed us to more consistently run the Tulsa crude unit at or above nameplate capacity. Both the Tulsa and El Dorado refineries operated at over 100% utilization rate in the second quarter reaching new crude – record crude rates. Our Tulsa refinery had the best summer crude rate ever recorded. These record crude rates were accomplished safely with zero reportable injuries or Tier 1 or Tier 2 GSM events. On a per dollar – per barrel basis, second quarter Mid-Con realized gross margin was $15.35 per barrel. Second quarter capture rate versus our posted 3-2-1 indicator was above historic quarterly average levels but below first quarter levels. The sequential decline in capture was attributable to diesel price conversion, lower sales…

Thanks, George. For the second quarter 2015, cash flow provided by operations totaled $323 million. Second quarter capital expenditures totaled $133 million excluding HEP's $11 million capital spend. Turnaround spending in the quarter totaled $9 million. In 2015, we expect to spend between $600 million and $650 million in capital. In addition, we expect to spend approximately $70 million on tanks and turnarounds. In May, our Board of Directors approved a $1 billion share repurchase program, replacing all existing other share repurchase programs. During the second quarter, we returned $388 million in cash to shareholders through buybacks and dividends. Including an executed $300 million accelerated share repurchase agreement for which we received 5.5 million shares or 80% of the total shares expected to be repurchased under that accelerated repurchase program. The remaining shares to be repurchased under this ASR will be delivered sometime in the third quarter. This morning in conjunction with our results we announced a $0.33 regular dividend to be paid in the third quarter putting our yield at 2.8% as of last night's close. We remain committed to maintaining a competitive total cash yield relative to the refining peer group. In June, we redeemed our $150 million outstanding 6 7/8% senior notes that were due 2018 for a total payment of $155 million. As of June 30, 2015 HollyFrontier debt totaled $32 million excluding non-recourse HEP debt of $901 million. Our total cash and marketable securities balance stood at $626 million, a $383 million reduction from the March 31 levels. Cash outflows in the quarter included the $388 million in share repurchase and dividend payments made in the quarter, $156 million debt redemption and $178 million of federal income taxes paid in the quarter. We expect to reduce our cash balance further throughout the year as we continue executing on both our share repurchase program and internal investment opportunities. As a reminder, HollyFrontier owns 39% of Holly Energy Partners, including 22.4 million common units, plus a 2% general partner interest. The current market value of our LP units is approximately $664 million as of last night's closing price. Second quarter general partner incentive distributions were $10.7 million, or a 20% increase over the same quarter last year. Lastly, a reminder that you can find monthly WTI-based 3-2-1 indications 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 margin per barrel may differ from the indicators for a variety of reasons. You can find the data on the Investor page at www.hollyfrontier.com. And with that, Andrea, I believe we're ready to open the line for questions.

The floor is now open for questions. Our first question is coming from Faisel Khan with Citigroup.

Hi. Good morning. It's Faisel from Citigroup. Wondering if you can address sort of the Reuters article that was out not too long ago, about a proposed offer from Tesoro for you guys earlier this year. Is it true, and what's being – what is done about it and what's the situation, right now?

Faisel, it's not going to come as any surprise to you I am sure but our company doesn't comment on speculation or market rumors. I think what is important is that we are absolutely laser focused on executing our plan. We've developed a good plan, I think it's made evident in our operating results some of the things that we're doing. And we feel like that we are able to build and guide this company through that plan. So more to come in terms of our Analyst Day, in terms of granularity, but we're very excited about what we have going on and we think that it will be to the benefit of our shareholders to see this plan implemented.

Okay. Just a follow-up question then on the operations. During the quarter, we saw a number of companies that operate refineries in your area benefit from the crude contango. Can you talk a little bit about how that benefited you? I mean, some companies talked about that being as much as $1 to $2 per barrel benefit in the quarter versus the first quarter of this year.

Okay. I think – this is George Damiris. I think we benefited similarly to what you've heard from the other companies. Contango for the quarter was $1.91 a barrel and that pretty much came through our crude cost, the majority of our crude is purchased off of Cushing.

Okay, Thanks.

And your next question comes from the line of Paul Cheng with Barclays.

Hey, guys. Good morning.

Hi, Paul.

George in the Mid-Continent your throughput was excellent but the sales seems much lower than usual, typically it's about 10,000 barrels a day lower than your throughput that you achieved that is about more than 20,000 barrels per day, and also that the realized margin seems to be a little bit low. Is there any reason why the sales is low and the realized margin may be low and that may reverse in the third quarter? And also, that in the – in your Rocky Mountain, historically that you only be able to do no better than 80% on a going forward basis and what kind of sustainable rate as the improvement continue that we could expect?

Okay. First for the Mid-Con, for the capture, I think we had slightly lower sales of produced product in the second quarter versus the first quarter, about 96% versus 99%. So we should expect to see that reversed in the third quarter. And in addition to that we had some purchased product sales in the second quarter.

George, the reason why that you have lower sales for it, is it because the market is not there for you to push through or that you set an intentional effort by the company?

It's intentional, it's a timing thing. It's not – the market is there. As you said, with a number of our peers having operational issues and downtime, the market is there. We have no problem selling our product in Mid-Con.

Okay.

Paul as a matter of commercial practice occasionally we will take advantage of forward market contango in our product's market and put barrels into storage to capture contango profits. So, it's really a commercial strategy.

Okay. And how about the Rocky Mountain, what is a sustainable throughput rate or utilization rate we could assume as you continue to improve the operation there?

Yeah. We expect to run all of our plants at capacity. Cheyenne has a capacity of 50,000 barrels per day or so and we expect to operate at that level. It hasn't run necessarily at that level historically, but we're pushing to get that plant up to 50,000 barrels per day. Woods Cross capacity is roughly 30,000 barrels a day. It will be expanded to 45,000 barrels per day with the Phase 1 expansion. Again, we expect that plant to run at capacity as well.

My – and my final question. HEP, what is the growth strategy, and some of your peers like TLLP and MPLX have make some pretty large third party acquisition. Is that a path that you're going to go down, or you have your own – other strategies?

Paul, we look at a lot of deals within HEP, but really our principal focus is two-fold. One is, the relationship with HFC and aiding HFC's growth, sort of, a mutual strategy which I'll call inside the fence. And we've called that out as an example with our naphtha fractionation project in El Dorado, which is likely to be dropped down here in the third quarter. The second piece is extending and improving the crude gathering system and the core assets already owned by HEP. An example of that would be the Malaga and Permian gathering expansions. I think the much higher probability growth is within our system and expanding organically. Obviously, were going to look like others do at external opportunities, but those come as they will.

Thank you, Mike.

Paul, I just want to follow-up, to one – I'm sorry, Andrea one second. One question I don't believe we answered the gas, about the Mid-Continent was, sort of, the capture rate being a little lower than maybe expected. And that was mainly attributed to the big swing in distillate prices, sort of going below gasoline for the first time certainly in as long as I can remember. The Mid-Continent for us is going to be the largest distillate producer and relative to our other markets that might look more like a 3-2-1 crack, diesel in the Mid-Con is closer to sort of a 2-1-1 not quite – but what I will tell you there, that was the biggest driver to the – if you could call in a quarter this good anything disappointing, that was one area that in fact hit us negatively in the Mid-Con for the quarter.

Thank you.

Your next question comes from the line of Blake Fernandez with Howard Weil. Blake Fernandez - Scotia Capital (USA), Inc. Folks, good morning. And Mike, congratulations on the operational turnaround. Things are looking pretty strong here. The question's on the buyback. Obviously a massive ramp-up here in the quarter and I'm just trying to get a feel for the way you are thinking about this. Was this an opportunistic situation? And I guess tying in with that, it looks like the balance sheet is really in good shape to a point where you could really kind of continue to be aggressive here for the balance of the year.

Yeah Blake, I'll address that just right off. We feel like we have a very visible plan that stands to increase value of the company by 50% or so, and with that in mind, our shares are undervalued, in our view. It's not opportunistic in terms of buying, yet it's opportunistic in terms of putting our capital to work more efficiently, particularly in view of what we think the company will be worth as we execute this plan. So we, through the quarter executed very ratably in this instance, in an accelerate share repurchase structure supplemented by some open market purchases of our own, and we're going to continue in the same manner, whether with a structured program or not, but we will intend to be out there daily and weekly purchasing in volume. Blake Fernandez - Scotia Capital (USA), Inc. Okay, good deal. Secondly, on the cost side. Costs were well below our estimates. I know you cited a couple of issues like natural gas and decreased maintenance. I know too when you run at high utilization rates, that tends to lead to a little bit more efficiency and lower per unit cost, but I am just trying to get a sense of how sticky this is. I mean, given your commentary on the lack of maintenance for the back end of the year, is it fair to think that these per unit costs kind of hang in there for a while?

Yes. I think as long as our rates stay up this high, as you said, that's a major contributor. Even on an absolute dollar perspective, it should stay in the same region.

Operations are a gift that keeps on giving, Blake, and you referenced our turnaround progress and really our team across the company has a hand in that and they are doing a great job. But you're going to see that in throughput rates, in operating costs and maintenance costs and capture rates. That's why it's so critically important. Blake Fernandez - Scotia Capital (USA), Inc. Okay. The last one, if you don't mind, real quick, just on the Southwest region. The gross margin was really strong. I am just trying to get a sense, is some of that tying in with some of the strength we're seeing over in Pad 5 in the California market? Does that kind of play into some of the margin strength we're seeing at Navajo?

That's exactly right. You see it in the Arizona market. Especially Phoenix. Blake Fernandez - Scotia Capital (USA), Inc. Okay. I'll leave it there. Thank you.

Next question comes from the line of Roger Read with Wells Fargo.

Yeah. Good morning.

Hi, Roger.

And congrats on the quarter.

Thank you.

I guess, you – in response to the last question, you mentioned a 50% value uplift, and I recognize you've got the Analyst Day coming soon. But can you kind of give us maybe some broad outlines of all that flowing into the upside potential?

What I'm going to say is it's a combination of using our balance sheet more efficiently and improving our earnings through reliability, commercial opportunity and cost savings. And you're going to get the details of that program at the Analyst Day. But it's sort of an all-in combination of those different things, plus a little more extensive use of the MLP.

Okay. And then, in terms of the – putting the balance sheet to use, the debt was repaid ahead of schedule, and I'm thinking about what the right long-term sort of, I don't know, debt to cap, debt to EBITDA, do you lever the balance sheet to accelerate a share repurchase, something along those lines?

Roger, I would say that – I think we've sort of long said we expect our debt to EBITDA target to be in the one-times range on a net basis, and obviously it's a little tricky in refining to determine what that one-times is. But we feel strongly about maintaining our investment grade rating and don't know that we would push it beyond that. The trajectory for this year's EBITDA is obviously very strong. As we think about it going forward, though, I would expect at some point over the next six months to nine months, we would likely be issuers of some debt securities and be able to use that capital towards share buyback. And again, would hope to have a bit more detail on that, when we see you on September 3. The retirement of the existing debt was just getting rid of the negative carry for the time being and it really does not reflect our intended balance sheet.

Okay. That's helpful. And then just the last question. As you think about the operational challenges you had in the comp. Let's say the prior year and half, two years and not every quarter was a problem but now you've got two quarters in a row, pretty good throughputs, pretty good realization. Could you give us a quick summary of some of the things that have been solved? I know some of it is small accidents; nobody can predict that, but has there been a, sort of, a from the corporate level down change in how you are managing these processes, or a change in how the individuals running the various units are rewarded here in terms of uptime?

The short answer is yes. The conversation at our company begins with safety and reliability now. We've made fairly extensive changes in people. We've brought in additional resource – or people into the company. We've made investments in our plants, particularly in supporting utilities and infrastructure that tend to nag us. And finally, the focus on reliability, on getting our preventive maintenance done and maintaining the plants in a way that they can run full all the time. And I am not going to say that's dramatically different than any other refining company, but we are intending to do it well.

Okay. Thank you.

Next question comes from the line of Evan Calio with Morgan Stanley.

Hey, good morning guys, and good results. Let me try then my first question is a follow-up to the very first question. And I know you don't comment per se on rumors, but do you believe that Holly is vulnerable to be acquired, and was that perceived vulnerability a driver or influence in your strategic shift in the last conference call, maybe kind of started in the first quarter, but more prominently announced on the last quarter conference call that materially addressed many of the investor concerns? Any comments there, Mike?

I think that the market probably reads it a little bit wrong. We were very involved and hopeful toward a large and transformative acquisition and had pretty high expectations along that front. They obviously didn't work out and we needed to make a strategic shift. That shift involved a hard internal focus of what we can do inside the fence to drive value at this company, and that's what the plan comes from. So Reuters and whatever else really isn't relevant to that assessment. It is simply what you do following missing a large transformative opportunity to take control of your own destiny, and that's what we're doing now.

Okay, that's fair. And my second question maybe you just give us an update, run through your three growth projects and talk about progress towards starting startup and CapEx pace and how are those proceedings since we last heard?

Really, they're very much on time, on budget. We have taken the step of expanding the scope a little bit in Woods Cross to accommodate more variety in the crude slate which will be necessary with the winter waxy crude on the wane right now, but other than that – and that's going to be a moneymaking opportunity in terms of that incremental $20 million or $30 million that we're going to spend towards optionality. But other than that the projects are proceeding apace, and then we have great confidence in both their execution and ultimately making money on them.

Great. Let me squeeze one last if I could. I know, and maybe you won't go out this far, but turnarounds are expected, and at least in our early indication appear to be pretty heavy into early 2016, which has important implications for margins and differentials. Any – maybe any thought of what you think could be driving relatively outsized turn and/or how does Holly look relative to peers into – or relative to history into 2016? I'll leave it at that.

Well, if the rest of the market has what we had in 2013 and 2016 I think we're going to be in pretty good shape at this company. But thinking forward. George, do you have the forward-looking 2016?

We have turnarounds at Tulsa, El Dorado and Cheyenne in the spring of next year. So we have our fair share of turnaround activity during that time period.

Great. Thanks, guys.

Thank you.

Your next question comes from the line of Edward Westlake with Credit Suisse. Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker) And it's nice to see the investments made delivering the reliability this year; well done. A MLP conversation. You mentioned some additional CapEx and obviously you mentioned that you had very high gross margins and so you could easily be more assertive by dropping into HEP without affecting the volatility of the core business, and I think you mentioned 20% of future EBITDA seems like a good number. You know, why not more, would be the first question, and then secondly have you done any analysis on what you think is HEP's ability to absorb drops in terms of the pace?

Well, I'll take your questions in inverse order. The ability to absorb drops really relates to the ability to raise capital principally. HEP is an effective operating organization, and I don't think they have any problem pulling these in. The ability to raise capital, the MLPs have gotten hit pretty hard in the last month or two but I think we need – we will distinguish HEP as the high-quality asset that it is. It's cash flows are very, very predictable, currently it yields 7%, which I think is an undervalued HEP, but through time it's lack of commodity exposure and very consistent yield I think will show through, and it will be able to raise capital pretty efficiently, particularly with the addition of some growth pace drops from HFC. Your other question relates to how about picking up the pace effectively, is 20% the right number? And I don't know that I have a particularly right answer to that other than I think there is upside to the 20%. It's not 100% but it's south of 50% and maybe north of 20%. Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker) Yes, I mean, if you look at the peer group some are closest to 40% EBITDA, and appreciate some of it is third party, some are as low as 17%, and it just feels that – but most are around 30%. It just feels there could be some upside in terms of the fixed charge that you put on your refining business if the funding was right.

I agree with that statement. Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker) Okay. So then just a macro question. Gasoline obviously has been strong this year. I mean B&Tas you mentioned, demand has been strong, it feels there are some constraints in the refining system to be able to meet demand that is globally above where it was a few years ago. Do you agree with that statement? And if so, maybe what are the constraints in your own systems to boost gasoline, and do they make good investments for you if the sort of prices you think will occur to make?

Well, we certainly want to agree with that statement obviously. The ability to increase gasoline production, what I will tell you is that through key downstream units in terms of naphtha high extruding, reforming, cat cracking, we're making small debottlenecking moves with the Tulsa cat revamp as an example likely to get us 4,000 barrels a day or 5,000 barrels a day of cat cracking capacity in Tulsa. And probably has a little bit of knock on down at the alkylation unit in terms of alky feed availability. And so we are doing the things that good refiners have done through time in terms of low cost debottleneck investments. They also tend to be more efficient in terms of liquid yield as we get inside these units and improve them. Day to day, in terms of can we make more gasoline at this company than we did during the second quarter. I think that's a stretch without further investments. We're running very, very full right now in a market that has plenty of incentive for us to do so. You've noticed the premium, premium if you will, otherwise the octane premium, in the Mid-Con right now that's about $0.80 per gallon. So we've got a very strong driver to make premium. The same has been true in Southwest and relates as much to refinery downtime probably as to crude slate. But these are high-class opportunities, and a lot of them will involve small investments, but that's right in the heart of our opportunity capital program. So we'll intend to be pushing those things hard, but at relatively small dollar cost and 18 months to two years execution time period as opposed to the typical four years or five years. Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker) Thanks very much.

Yeah.

Next question comes from the line of Phil Gresh with JPMorgan.

Hi. A couple questions. One, you mentioned the one times net debt to EBITDA target potentially taking on some debt. Is there a specific timeframe when you want to achieve this leverage ratio? Is it 12 months, 24 months, how are you thinking about that?

Yeah. I said even probably a little shorter than that. That you'd probably expect something in 6 months to 9 months. Timing's always a bit of a factor, but I think certainly reasonable to assume that in the next year we will have added some fixed debt component to our balance sheet and gotten closer to that target by then. Much more than that I'm not sure that I can give you a specific date and time but that's our intent.

Got it.

We need to be real aggressive with the share repurchase program given the cash that the company is generating, and we haven't gone so far and likely will not as to tender for our shares, but in order to achieve our target balance sheet structure, we need to repurchase a lot of stock.

Okay. Fair enough. I guess, the other question I was going to ask on that front was, you mentioned a larger deal that did not work out, but is there any a desire to become larger on the refining side, kind of along the way with more of a bullpen approach, or is that really not what you are thinking about nowadays?

We're thinking about larger in share price, and to the extent that we can buy a refinery or a company that helps us to achieve that we'd certainly like to, but it's not what we think is critical to our strategy or its execution. We have a very good platform in advantaged geography of assets that are performing well, and have the ability to extend it through new capital investments. So I guess the point being we like what we have, and if we can add to it in a way that makes sense we will do that, but it's not necessary.

Okay. Last question just on the Rocky Mountain region, you mentioned again the costs target there, once the Woods Cross project comes online. What else do you think you need to do outside of just bringing that project online to get those operating costs down to where you want to get them, and what timeframe are you thinking about?

I think the other major item we need is just more sustainable high rates at Cheyenne. And we've said Cheyenne has the capacity of 50,000 barrels a day. We've demonstrated that most recently but not for a sustained period of time. If we get that rate up it obviously increases the denominator and helps us get that per barrel charge down. And as we said, anything you can do to increase reliability just gets a lot of your costs out of your system as well, maintenance costs, turnaround cost, things of that nature.

Right, okay. So the volume and reliability. All right; thanks.

The next question comes from the line of Doug Leggate with Bank of America-Merrill Lynch.

Good morning, everyone. Mike, I think whichever way you looked at it, the idea of consolidation in the sector is uppermost in everybody's mind right. So if I may – if you can humor me while I try the question a little differently. You guys were first to do the MLP, you've probably got some of the most enviable position in the sector as it relates to the crude advantage, there are a lot of companies of similar size to you, and you obviously see the benefits of scale given what you try to do with the Citgo assets. So all things considered, why wouldn't you see yourself as a consolidator in the sector?

Doug the simple answer to that is that being a consolidator most often requires paying a premium and the way to justify that most likely in our minds is through fence line consolidation; effectively industrial synergies as opposed to financial structuring. And those deals are few and far between, so when I say that we'll be consolidators if we can add value to the process, it really is focused on particular assets that we think will improve our overall refining system by industrial synergy, and that's hard to do. Is there going to be an opportunity through time to do so? I certainly hope so, but growth by acquisition is tough to achieve, and growth in value by acquisition is really what we insist on.

Okay. I appreciate that. I've got hopefully two quick follow ups if you don't mind me asking a couple. The first one is really on the buyback. Again, it's really more of just your perception on how you guys are thinking about this, but if you look at where gasoline fracs are and obviously the impact that's had on sector valuations, and one could probably take a view as to where gas price go next as we come out of peak seasonal demand and so on. Why wouldn't you be a little bit more patient with your buyback as opposed to accelerating it, given that, let's assume that the sector follows a weaker gas price lower for example, as it normally does in the fall?

We've had a history of patience with our buyback looking for dips, and I will tell you explicitly that we haven't been rewarded for that. We need to get to a more efficient capital structure. We believe that the company is worth substantially more than the current trading price, particularly the execution of our plan. And there's no reason to be patient. That's just warehousing shareholder capital and liquidity that we don't need to run the business.

And Doug, I would add to, in addition to having quite a bit of capital, as we talk about adding debt available to us for additional buybacks that, yes, while I would agree with you we're moving out of what is the traditional driving season and you'd tend to see weaker demand, certainly, through the fall and the winter, I'm still somewhat optimistic that we're going to be very surprised by consumers' behavior in this current gasoline price environment. With the oil price lower, I think that we – again, maybe not the same strong summer gasoline demand, but we wouldn't be surprised to see much stronger than expected gasoline cracks through the fall months and into the winter.

I appreciate that Doug, and I guess my final question is really a little bit more just macro, kind of technical. There's been a lot of chatter about octane tightness in the industry and as we come into higher RVP season butane blending, isobutane becomes available, I guess for those who can produce it. What do you guys see, or maybe you could just characterize for us, does butane help the octane problem or exacerbate it? And I will leave it there. Thanks.

Well butane is a fairly decent octane component, and so directionally it helps a little bit.

Okay. I'll maybe take the more detailed stuff offline. Thanks a lot, guys.

Okay, Doug.

Thanks, Doug.

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

Hey, it's Jeff Dietert with Simmons.

Good morning, Jeff.

You guys have talked about the strength in gasoline demand for a number of months now, and I have noticed increased traffic between Dallas and Houston and the other way around. So I think that's something you've been right about so far. Could you talk about distillate demand? I know it's been a little bit softer in the monthlies and you're close to North Dakota and the Bakken markets. Are you seeing any impact from reduced drilling activity up there on diesel demand?

Yes, I think that's a correct statement not just obviously in the Bakken but across all of the producing areas, the Permian as well. And then I think we're hearing also from our customers on the trucking and on the railroad side, demand is down in their businesses as well. I think coal, what's happening in the coal industry and the demand for coal is having an impact on the railroad.

And I think the industry is kind of focused on, you know, historically distillate demand has grown more rapidly than gasoline demand, and there has been a focus towards shifting towards maximizing diesel yield, and we're kind of reversing that now, going back to trying to maximize gasoline yield. Has there been any loss of ability to produce gasoline over the last few years as the distillates have been stronger?

Jeff, we are cat cracking refiners. We know how to make gasoline. Our real challenge was to get the distillate yields up, which particularly in the Mid-Con, we have done a pretty good job of, but in terms of the knobs and levers to get the gasoline yield back, we didn't forget how to do that.

Okay, good. If I could get a quick update, you'd reversed the Centurion pipeline to move Midland barrels into Cushing a while back, and I assume that that's changed. But could you update us on what the status is of that pipeline?

We continue to work to make that reversal permanent, and that should be done in the very near future, but beyond that, I don't have many details I'd like to share with you right now.

Thank you for your comments.

Thanks, Jeff.

Your next question comes from the line of Neil Mehta with Goldman Sachs.

Hey, good morning.

Hi.

Mike, you have always been one willing to pontificate on the spreads here, so I thought we could talk a little bit about your views on three in particular. One is, thoughts on Brent WTI as we get into the turnaround season, and given what's going on internationally with OPEC production, how we should be thinking about that? Brent WCS, which has widened out and WTI Midland, which has inverted; any color on those three spreads would be valuable.

Well, I don't know that I'm in a shape to pontificate this morning. It is obviously a changing landscape. Starting with Midland, there's a lot of takeaway capacity from Midland directly to the Gulf Coast. And for the time being, between filling those pipes and filling the T&D commitments to use those pipes and Midland's pricing in excess of Cushing. Absent additional growth in the Permian, we'll probably see that for a while. And I think that is okay. You've got basically $1 or so between Midland and Cushing inverted right now, but the Basin line still runs fairly full. So, they'll probably remain close through time. The likelihood of large blowouts in Midland, I think, is now really limited to significant refiner downtime on the Panhandler in the Southwest or dramatic increases in production, which with current rig count are going to be hard to achieve. The Brent CI spread, the market probably sees $5 or so, and I do not know that we internally have a real different view from that. That recovers a certain amount of the transportation costs to the logical trading point, which really isn't Houston anymore but is more St. James. And so, the WCS is probably the interesting one to us in that Canadian production isn't quite as fickle in terms of their ability to turn it on and turn it off. And I think that the large mines and certainly the Frag D (48:20) projects will continue to produce, and the new phases of growth that are destined to come online soon will continue to come. So on a percentage basis, we're very bullish about the WCS spread, certainly going into the fall and winter; I think that is going to be an attractive barrel. It doesn't yet have another form of egress meaning to the Canadian East Coast or the Canadian West Coast, so the midcontinent and Gulf Coast refiners really represent the market for that barrel and at the time being that's an attractive barrel to us.

Very good. And then this might be a question for like September Mike, but could you talk a little bit about the opportunity to do other low capital high-value projects the way you have done at El Dorado, Cheyenne and Tulsa? Are there other smaller projects, which can be done at low EBITDA multiples over the next couple of years?

George is right in the middle of that. I'm going to ask him to...

Yeah. I think the short answer is, yes. We have a number of those types of projects specific to cat crackers, especially we have projects at Tulsa and Cheyenne they're very similar to what we have done at El Dorado to modernize the technology being used in the cat crackers across to our system. So those are three specific projects, with one already in the bag and two coming shortly, and that's a major component of our business improvement plan that we will be discussing at the Analyst Day.

Yeah. But Neil, Julia threatened us that if we gave you all the information today, none of you guys would show up. So consider if you come to Dallas in September, it's certainly not for the weather.

We'll be there. Thanks a lot, Mike.

Thanks, Neil.

Next question comes from the line of Ryan Todd with Deutsche Bank.

Thanks. Good morning, Mike and everybody. Maybe if I could do a couple of follow-ups on earlier questions. On the gasoline yield, you had mentioned some of your views on gasoline and diesel, and to run higher gasoline yields you would have to make some incremental investments. Is the strength in gasoline that you're seeing – do you see it is as transient enough that it wouldn't be worth any incremental investment? Has there been any change in what we have seen versus what has been kind of a long-running view on the – of the industry to try to maximize distillate yields. So I guess any change in the view on these two, or do you just feel it is a transient issue that's primarily driven by lower oil prices?

Well, the beauty of it is even if it is a transient issue, the gasoline yield for us, and gasoline volumes in particular are probably the easiest, the cheapest to expand. And so in terms of our small capital – our opportunity capital program, there is going to be some money spent toward improving throughput and gasoline mix. And I think that that is sort of near term payback kind of dollars that whether or not it's transient we make money on those and retain the optionality going forward. So it makes sense to do these small debottlenecks and yield improvement investments. And how for forward we look, we are nearly always surprised by the market, which is why we really try to hit optionality and reliability to be able to participate in the opportunity that exists today.

Great. Thanks. And then maybe one follow-up on some of your other comments on strong West Coast cracks. Can you talk about how much volume you're bringing into Las Vegas via the UNEV pipeline in 2Q, and maybe what you're doing in 3Q, and then the outlook there?

Yeah. Obviously, when the West Coast gets tight, we see this both in the differentials both at Phoenix and Vegas and we try to take as much as we can to those markets when those arbs are open from say Salt Lake City down to Vegas and – versus El Paso to Vegas.

Yeah. I would add to that a couple of anecdotes. One, we saw, no doubt, yesterday and are starting to witness the same that actually Rocky Mountain crack spreads are just above Los Angeles as of yesterday. So what it's really doing is pulling up not just the California region, but also the Rockies. But to George's point, our UNEV terminal has been running at record rates at least over the last week or two, certainly good for HEP and our ability to move product into Las Vegas.

Great. Thanks a lot. I'll leave it there.

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

Hey, guys. George, is there a preliminary 2016 CapEx that you guys can share?

We don't – we haven't had that develop yet Paul, so when we do we'll share at the right time.

And then with the completion of the Woods Cross expansion and upgrade, should we assume that it's going to be dropped pretty meaningfully or that you're going to have sufficient slate of the small growth projects that essentially period?

Yeah. I think -

I mean, just looking at direction of these, whether it's going to be above trend, going up, going down?

Directionally, would be down. We don't have many small cap projects to equate to the size of the Woods Cross phase one project.

Right. That's project is spending, sort of, $200 million, $225 million in this current year. The El Dorado naphtha frac project would have spent $75 million or so in the current year, and we're not going to be backfilling those two with small capital, so directionally down.

Okay. And maybe that this is also for George. George, you're talking about the three refineries going to have turnaround in the spring. Can you give us a little bit more granularity in terms of number of days will be down, which unit will be down?

Sure. Hold on one second. Let me get that page up. So without trying to give away too much information here, we have basically cat cracker turnarounds at Tulsa, at Cheyenne, and we have a major diesel hydro treater turnaround at El Dorado, and roughly about 30 days in duration for all three of those.

Each one is about 30 days?

That's correct.

Okay. And then Doug, do you have a rend cost that you pay in the second quarter you can share, and what's your expectation in the third quarter?

Paul, I have – Julia has got it for me here in terms of rend in the second quarter. $49 million is the number that I am showing, as a continued tax on the refiners to remain in business in the United States. In terms of our expectations for the third quarter, Paul, I think rend prices are down some but they probably guide to, I would say, $30 million-$50 million would be a decent range.

Thank you.

Your next question comes from the line of Brad Heffern with RBC Capital Markets.

Good morning, everyone.

Hi, Brad.

Just circling back on some of the earlier questions on the Rockies, I am curious exactly what is holding back Cheyenne and Woods Cross? Obviously there is a big delta between 80% utilization and 100%. Is it just pure reliability; are there investments that need to be made, what exactly are the bottlenecks there?

It's primarily reliability. We have made some minor investments to make an infrastructure. But it's really doing what we have done at the other refineries that have set record crude rates recently, doing that same type of work and focused work at Cheyenne as well.

Yes, the Woods Cross utilization in the second quarter was turnaround affected. They did not have reliability issues of any consequence, and in Cheyenne we're working through a list of what we consider to be bad actors in terms of equipment and infrastructure. And frankly, while throughput is still constrained because of reliability in Cheyenne It has improved by 50% since 2013 and 2014. So we have got that plant on the right trajectory, we'll be replacing additional equipment in the upcoming turnaround that being in April or so of 2016, but we have every reason to think that the money that we're spending, the training that we're doing, the reconfiguration in terms of people and process is going to take root in Cheyenne just as it has everywhere else.

Okay. Thanks for that. And then, just circling back to operating expense as well. For the Southwest region, this quarter it was very low, $10 million down sequentially, if my math is right. Was there anything going on that caused that number to be very low or is that a sustainable number going forward?

Yeah. We had the benefit of a one-time tax benefit at Navajo that will not be obviously sustainable. So it's roughly on the order of $6 million.

Okay. Thank you.

Okay.

Your next question comes from the line of Faisel Khan with Citigroup.

Yeah. It's Faisel again. So I just had a couple follow ups. Just on the California market, your ability to capture that. So UNEV I think was about 60,000 barrels a day, was that pipeline running at full capacity during the quarter?

I'm not sure we saw it running at full capacity in terms of shipments there. I saw a number that was closer to 30,000 barrels a day across their rack recently. I think that's probably a closer number, and that would include both of the major shippers on that line.

Okay. So it sounds...

– Vegas, and another 5,000 barrels a day in Cedar City or so, so let's call it 35,000 barrels a day.

Okay. Got you. And that's enough to sort of keep Rockies sort of crack connected to the West Coast, I guess is the way I am looking at it. If it's 30,000 barrels a day flowing and then the pricing mechanism in the Rockies has to keep that gasoline in the area to sort of keep that – keep both markets in balance, I guess. Is that the way to look at it?

I am sorry...

Okay.

We look at these things and again, I mentioned seeing the Rockies trading over at least LA recently. And I think that's the result of actually when you see an imbalance in the Rockies, which we were hearing news of one or two folks that supply that market having some unplanned maintenance, which is causing that crack spread indicator to be significantly higher currently.

Okay. Got you. And how much gasoline can you get into the Tucson and Phoenix markets from Navajo? I think previously, you guys have talked about something like 10,000 barrels a day to 15,000 barrels a day, but I think I can't remember going back that far.

No. I think an order – a number in the 30,000 barrel a day to 40,000 barrel a day range of gasoline would be more correct.

Okay. Got you. Understood. Thanks a lot. Appreciate the time.

I will actually now turn the floor back over to Julia for closing remarks.

Thank you, everybody. We appreciate you taking the time to join us on today's call. If you have any follow-up questions as always reach out to me, and we look forward to sharing the rest of our plan at our September 3 Analyst Day here in Dallas, Texas. Have a great day.

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