Craig Biery - Investor Relations, HollyFrontier Corporation Michael C. Jennings - Chairman, Chief Executive Officer and President George J. Damiris - Chief Operating Officer & Executive Vice President Douglas S. Aron - Chief Financial Officer & Executive Vice President.

Ryan Todd - Deutsche Bank Securities, Inc. Paul Y. Cheng - Barclays Capital, Inc. Paul Sankey - Wolfe Research LLC Bradley B. Heffern - RBC Capital Markets LLC Blake Fernandez - Scotia Howard Weil Kalei S. Akamine - Bank of America Merrill Lynch Roger D. Read - Wells Fargo Securities LLC Evan Calio - Morgan Stanley & Co.

LLC Neil Singhvi Mehta - Goldman Sachs & Co. Faisel H. Khan - Citigroup Global Markets, Inc. (Broker) Johannes M. L. Van Der Tuin - Credit Suisse Securities (USA) LLC (Broker) Phil M. Gresh - JPMorgan Securities LLC Matt Lair - Macquarie Capital (USA), Inc..

Welcome to the HollyFrontier Corporation's Third 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 a listen-only mode and the floor will be open for your questions following the presentation. Please note that this conference is being recorded. It is now my pleasure to turn the floor over to Craig Biery, Investor Relations. Craig, you may begin..

Thank you, Brandon. Good morning everyone, and welcome to HollyFrontier Corporation's third quarter 2015 earnings call. I'm Craig Biery, Investor Relations for HollyFrontier. This morning, we issued a press release announcing results for the quarter ending September 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 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, November 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..

Thanks, Craig. Good morning. Thanks for joining us on HollyFrontier's third quarter earnings call. Today, we reported third quarter net income attributable to HFC shareholders of $342 million or $1.82 per diluted share, excluding the $225 million non-cash lower cost or market pre-tax inventory valuation charge.

Including the non-cash inventory valuation charge, net income attributable to HFC shareholders was $196 million or $1.02 (sic) [$1.04] per diluted share. Healthy gasoline margins, combined with high throughput rates and lower cost, drove more than 100% increase in earnings year-on-year.

Third quarter EBITDA, excluding inventory charge, was $630 million, a 70% increase from the comparable quarter last year. On a per barrel basis, third quarter consolidated refinery gross margin was $19.85 versus the $15.59 per barrel recorded in Q3 of 2014.

We had another strong quarter in operational reliability and safety performance across our refining system. Third quarter 2015 refinery utilization rate was 104% of nameplate capacity, the highest quarterly rate achieved since our merger in 2011.

In the Rockies, our Woods Cross and Cheyenne plants set a record combined average crude charge rate of 78,000 barrels per day. Our Navajo plant also surpassed previous crude charge levels by recording an average of 105,000 barrels per day, while El Dorado and Tulsa ran above 100% utilization.

Our continued focus on improving refining reliability and safety is evidenced by our operational performance throughout 2015 and we're confident in our ability to sustain these rates going forward. We are well on track in executing our business improvement plan outlined at our Analyst Day in September.

Through continuous improvement in our refining operations, commercial optimization and opportunity capital investments, we are further increasing our competitive advantage as an inlet refiner.

Year-to-date, our employee recordable – occupational incident recordable rate has dropped by 43% and our process safety incident rate has dropped by 38%, which means we are running our refineries more safely and therefore more reliably. We are continuing to make progress towards our first quartile operational availability target.

In the third quarter, we achieved this target on a consolidated basis and have done so year-to-date at our three largest plants. Looking forward, we continue to focus our efforts on building upon this progress across our refining system.

Our commercial organization continues to advance market capture opportunities, driving higher realized margins relative to the benchmark margins. In addition to increased light product market access, we are increasing production of high-value products.

The Tulsa Refinery produced an average 6,700 barrels per day of Bright Stock heavy viscosity lubricants in the third quarter, a 15% increase from 2014 levels. We also continue to capture higher value in the bottom of the barrel by targeting specialty applications for heavy products, such as roofing flux and pitch, which sell at premium to WTI.

We've made meaningful headway on recent opportunity capital investments with emphasis on liquid yield and de-bottleneck investments such as the Tulsa cat cracker modernization and the Cheyenne hydrogen plant. Both projects are currently on schedule for startup in the first half of 2016.

These enhancements further diminish feedstock constraints, while increasing light product yields. We have over 15 high profitability investments that are in various stages of planning and execution. These quick fit opportunities require small capital investment with quick payback periods, typically two years or less.

The Woods Cross Refinery expansion is in its final stages of completion with an anticipated startup date in January. Including the new crude design flexibility, we expect to generate $100 million of incremental average annual EBITDA from this project.

Our success in leveraging the relationship with Holly Energy Partners has been demonstrated recently by the completion of the El Dorado naphtha fractionation and hydrogen unit drop-down on November 1. Increased emphasis on drop-down opportunities between HFC and HEP will continue to be a big value driver for our company.

We continue to identify potential drop-down candidates such as the logistic assets related to the Woods Cross expansion. HEP's future growth outlook has been further supported by its recent quarterly distribution increase, marking the 44th consecutive increase since its IPO in 2004.

This increase in distribution demonstrates Holly Energy Partners' commitment to achieving an 8% targeted distribution growth rate over the next few years.

Looking forward, our focus remains on the implementation and execution of our business improvement plan, and we believe the strong gasoline demand growth experienced in 2015 will continue into the coming year, supporting attractive refining margins. With that, let me turn it over to George Damiris, our Chief Operating Officer..

Thanks, Mike. Third quarter crude throughput was approximately 460,000 barrels per day versus our guidance range of 440,000 barrels to 445,000 barrels per day. Average laid-in crude cost across our refining system was $0.81 per barrel under WTI.

Total refinery operating costs for the quarter were $240 million, a 6% reduction compared to the same period last year. Cheaper natural gas prices and lower maintenance expenses contributed to our operating expense improvement in the quarter. In the Rockies, crude throughput was 78,000 barrels per day.

Realized gross margin per barrel was almost $24 per barrel, the highest we have seen since the second quarter of 2013. Average laid-in crude cost was $3.94 per barrel under WTI. Refinery operating costs were $7.62 per throughput barrel, a 25% reduction from the same period last year.

We expect to achieve $7 per barrel or less after bringing the Woods Cross expansion online and as we make further improvements to the Cheyenne Refinery.

Our focused efforts on improving operations at Cheyenne and Woods Cross are clearly reflected in the quarter with the plant setting a combined record utilization rate of 94%, the highest level since our merger. For the Mid-Con region, crude throughput was 277,000 barrels per day. Average laid-in crude cost was $0.47 per barrel under WTI.

Refinery operating costs were $4.34 per throughput barrel. On a per barrel basis, third quarter Mid-Con realized gross margin was $18.67 per barrel.

Third quarter capture rate versus our posted 3-2-1 indicator improved 5% quarter-over-quarter, despite narrowing crude differentials and smaller contango benefit, reflecting our ability to access higher value markets and increased production of higher value asphalt and lubricant products.

Southwest crude throughput was 105,000 barrels per day, a record quarter at 105% of nameplate capacity. We ran 100% Permian crude of which 39% was higher gravity crude available through HEP's Southeastern New Mexico gathering system.

Average laid-in crude cost was $0.63 per barrel over WTI, which was the primary driver of the lower capture rate in the region sequentially and indicative of the Midland/Cushing spread for the quarter. Refinery operating costs were $5.04 per throughput barrel.

Our refining system continues to run exceptionally well as reflected in our third quarter operational results. Going forward, we expect to continue to see the benefits of our ongoing efforts to improve reliability across our system in the form of improved safety, enhanced optimization of our units and reductions in operating costs.

We have no further major turnaround activity scheduled for the remainder of the year. However, we have some minor maintenance planned for the typically weaker-margin fourth quarter on the Tulsa West crude and lubes units, Cheyenne's diesel hydrotreater and reformer and on El Dorado's largest diesel hydrotreater.

For the fourth quarter, we expect to run 410,000 barrels to 415,000 barrels per day of crude with 30% of its weight being sour and 20% WCS and black wax crude. With that, I will turn it over to Doug for some closing remarks..

Thanks, George. For the third quarter of 2015, cash flow provided by operations totaled $333 million. Third quarter capital expenditures totaled $150 million, excluding HEP's $8 million capital spend.

In 2015, we continue to expect to spend between $600 million and $650 million in capital and additionally, we expect to spend about $70 million on tanks and turnarounds.

During the third quarter, we executed $102 million in open market share repurchases and completed our previously announced $300 million accelerated share repurchase program that was initiated in May. Additionally, in October, we have repurchased an additional 2.1 million shares and spent approximately $100 million.

Year-to-date, we have repurchased nearly 12.8 million shares, reducing our shares outstanding by more than 6% and as of October 31 of this year, we had approximately $455 million left on our current $1 billion authorization.

As of last night's close, our current dividend yield stands at 2.6% and we remain committed to maintaining a competitive total cash yield relative to our peer group. As of September 30, HollyFrontier's debt totaled $32 million, excluding non-recourse HEP debt of $951 million.

Our total cash and marketable securities balance stood at $627 million, essentially flat quarter-over-quarter. As a reminder, HollyFrontier owns 39% of Holly Energy Partners, including 22.4 million common units plus the 2% general partner interest. The current market value of our LP units is approximately $780 million as of last night's closing price.

Third quarter general partner distribution was $11.1 million, a 19% increase over the same period last year. 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 margin per barrel may differ from indications for a variety of reasons. You can find the data on our Investor page at www.hollyfrontier.com. And now, Brandon, I think we're ready to take questions..

We ask that you limit to one question and one follow-up. If you have additional questions, we welcome you to rejoin the queue. Thank you. Our first question is coming from the line of Ryan Todd from Deutsche Bank..

Okay. Thanks. Good morning, gentlemen. Maybe if I could start with one on the differentials. The differentials are clearly better. We've seen narrow light diffs and attractive WCS diffs from – within your system.

Can you talk a little bit about maybe your outlook for the rest of fourth quarter and then the 2016 in terms of – I guess, in terms of differentials and how it will impact the crude slate that you guys run?.

Yeah. This is George. I think the key diffs for us are the Midland/Cushing diff, as it relates to Navajo, and I think the dollar premium for Midland versus Cushing that you saw in the third quarter is an anomaly. I would look to that to flip to $0.50 to $1 a barrel under Cushing set by some sort of reflection of transportation costs.

And then WCS, as you said, diffs are reasonably attractive considering the flat price. And I don't foresee much changing from the nominal $15 discount at Hardisty for WCS, despite some new pipelines coming into play out of Canada..

And so, in terms of the outlook for 2016 on the slate, do you see things as, I guess, relatively consistent and....

Yeah. Ryan, I don't think much could change from our crude slate perspective. We will always try to – it is very rare that we will – we won't match WCS at both Cheyenne and El Dorado and then we're going to run Permian crudes at Navajo..

Great. Thanks. And then maybe one follow-up on OpEx as well, you've had positive trends throughout the year on OpEx, a little bit higher than we would have expected in 3Q.

Can you talk maybe a little bit about anything that were driving some of the OpEx trends in this quarter and how we should think about it going forward?.

Sure. Our operations guys are continuing to do a good job, squeezing costs out of our system. Most of the cost reductions you're seeing right now are maintenance related and that ultimately ties back to our reliability efforts.

When we keep our plants online, we don't need special projects or special maintenance to get them back in line in a hurry, so a lot of savings. I think we've reaped those benefits pretty much already. I don't think you're going to see much more improvement along that perspective.

I think on a per unit basis, we should continue to trend downward, especially in the Rockies as we get our denominator higher in the form of more throughput, but as far as an absolute dollar perspective, the maintenance cost reductions are, I'd probably say, we are 80% there..

And, Ryan, I guess your question was why maybe a little bit higher 2Q to 3Q. There was a few things. Notably, we had a job wage credit in the second quarter that we didn't get in the third quarter. Again, from our perspective, everything is trending in the right direction and guys working very hard.

One timers like that that you can't count on maybe should have been called out further in our second quarter call. Thought it was but that could be one thing that – I think that was a $6 million or $7 million credit..

Okay. Thanks. That's helpful. I'll leave it there..

Operator, do we have another question?.

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

Hey, guys. Good morning..

Good morning, Paul..

Couple of questions. Mike and George, one of your peers, in this case, Western, they have done very well on the crude gathering. And that helped their refinery profit really and the gross margin quite substantially over the last couple of years.

The question is that, is that an area that you guys will be focusing? And what is the percent of your oil currently gathered by yourself to run in your different system? And what may the target be look like over the next 12 months and over the longer term target?.

Okay. Yeah. I think, Paul, we gather all the crude that we run at Navajo on our HEP affiliated systems. So we've done that for a long time, and I guess, to some extent, Western must be catching up and growing their business to get away from their typical Midland supply and again getting on their own gathering systems.

What we have been doing and we've been talking about that this quite a bit, I think, is that we've been growing with our Malaga system, that's the newest system we built in the Permian region to bring lighter condensates from the South, the very south end of New Mexico.

And I think we highlighted that in the call that 39% of our slate at Navajo are barrels that are coming to us from that Malaga system.

So in addition to Navajo, we are also gathering and transporting barrels to Cushing primarily for El Dorado, but also for Tulsa and that's on the order of 40,000 barrels to 50,000 barrels per day that are coming from the Permian to be run at those two refineries. The majority of that is coming from HEP's systems as well..

George, is there a target to increase in the Mid-Con system that by your own crude gathering? And also how about in the Rocky Mountain?.

Yeah. I think, like I just said, Paul, about half of what we are currently bringing to Cushing is coming from barrels that are gathered on our system and we would like to increase that to 100%. That's going to be difficult with the limited growth in the Permian now. We will continue to push that.

And then as far as the Rockies, the local crudes around our Cheyenne Refinery are not typically attractive to us. Relative alternatives like WCS, so that has not been a primary focus for us.

Having said that, we typically bring in about 5,000 barrels to 10,000 barrels per day in the Cheyenne that are locally gathered and then as far as Woods Cross, there is really no production locally that can be put on the gathering systems..

Second question. I know, historically, you guys are not really interested in retail. But over the next several years, one may argue, in the niche market where you guys operate, the gasoline supply may end up there to be increasingly exceed market demand at some point.

So a lot of your peers that would argue that having the retail element secure is a good thing.

Is there any change in your view that how you guys view on the retail? Or do you still think this is just not the business for you?.

Paul, I will tell you that I and we are in strong agreement with our peers who say that integrated retail distribution is important to clear barrels. Our strategy is just a little different. We don't believe we need to own or brand that retail to do so.

We have very strong customer relationships with big box retailers, with convenience stores, with truck stops who are competing against our peers and like the direct relationship that we have with them. So to construe it, as we are out there as a bulk seller, as a commodity seller, every day trying to clear a wholesale market really is inaccurate.

Our distribution channels go through established relationships, long-term commitments to retailers that are unaffiliated with oil companies typically..

Mike, can you tell us that what's the percent of your sales is going through or that I mean your gasoline and diesel that you produce are going through those long-term relationship?.

Paul, I think, it's in the 80%, 85% range depending on the quarter. 80%, 85%..

Thank you..

Yeah..

And your next question comes from Paul Sankey from Wolfe Research..

Have there been any issues of black wax delivery in this low price environment?.

Not to date, Brad (sic) [Paul]. We're still getting our typical volumes..

Great. Thanks. And can you talk a little bit about pipeline and train differentials? How the market is shifting for particularly for those running trains and whether that affects you in any way? Thanks..

Yeah. I mean, we're not active in the train market. So our intel there is just from what we hear in the marketplace, but I think it's fairly clear that the economics for rail and crude have diminished, especially with the WTI Brent spread and WTI-LLS spreads collapsing.

So I think all of that directionally should work to our favor as the crude searches for pipeline routes rather than train routes out of the markets..

Yeah. Paul, beyond that, particularly with respect to the Bakken, as you probably know, there were a lot of contracts out there that were Brent minus, so, Brent minus $10, Brent minus $15, which afforded rail transportation to the coastal plants.

But those weren't five year deals, those were six month deals and I think we're going to see a lot of those rolling off and that crude is going to be hopping on pipelines preferentially over the rails, just because of cost and lack of economics to ship to the coast. So we believe, in Cushing, we're going to be a beneficiary of that.

Through pipelines such as Pony Express, you can get from Williston Basin down to Cushing for about $5, whereas the rail transportation, including terminal and charges, would be nearly twice of that..

Yeah.

I guess it was a bit of obscure question given that you're not exposed as such to rail, but I was also thinking of the extreme discounts we saw in Canadian crudes earlier in the year that seems to be corrected by rail, as well as obviously the comments that we've heard in the past 24 hours from Plains All American and how the rail side of the crude market in the U.S.

seems to be under a bit of pressure. And, finally, we've had consolidation. I know your strategy is essentially now buyback. But can you comment on the environment as you see it for consolidation? And the latest update on how you see consolidation in the Mid-Con? And obviously, I'm thinking of Western NCI recently as just your latest thoughts.

Thanks a lot, Mike..

Sure. Look, I think there will be through time a continuing argument to make for consolidation to gain efficiencies. But the refining industry is very healthy right now. People are generating strong margins. And I would expect that the bid/ask is probably pretty wide for quality assets..

Yeah, sure. Can I just do a follow-up? Q4 to date, how the things look given the – on the screen, a lot of stuff has gone down a lot? Thanks. I'll leave it there. Thanks..

Yeah. Okay. Well, I'm going to have to answer two questions because I'm not sure which one you asked. But the margins have obviously come down seasonally, but still attractive. And we certainly have reason to run, incentive to run, flow at all of our plants. The stock prices really haven't come down in fact, they are at year-to-date highs.

So, I assume it's the – the margins on light products that you are speaking of and that doesn't surprise us a bit. We expect seasonal decline and we tend to pick back up when people start seeing gasoline season in front of them in late January, early February..

Well, actually, yeah, kind of, you got there. Thanks a lot for helping me out. What I was really referring to was the capture that basically seems to be Q4 to date better than the screen margins for refining would indicate..

Yeah. So we hadn't reported capture, yet. Maybe others do that, Paul. But what I would say is, for November, we feel like gasoline margins, and diesel margins, for that matter, are pretty constructive.

And I think what you are seeing is gasoline, may be a little bit higher than this time of year typically, diesel a little bit lower, which is somewhat of a continuing trend. But typically this time of year, folks in refining start hunkering down and that hunkering hasn't started yet. Product inventories are well behaved on the Magellan system.

Demand is good. There's been a lot of turnaround activity and some unplanned outages in our geographies during the fall and that's obviously supportive of margins. So we've been in a pretty good spot quarter to-date..

Yeah. I mean, to see double-digit cracks for both gas and diesel for this time of year, as Doug said, is not typical. So....

Great. Thanks, guys..

Thank you, Paul. Have a good day..

Thank you for helping me out. Thanks..

Yeah..

And your next question comes from Brad Heffern from RBC Capital Group..

I think that one of the things that stood out on the quarter specifically and you called it out in the prepared comments is utilization in the Rockies.

I was curious if you could delve into it a little bit more, what's driven the pretty dramatic uplift, how sustainable is it, and how much upside to it is there going forward?.

Yeah. I mean, the uplift is the Cheyenne Refinery that's operating pretty well. And even then, they are not operating at full capacity nor are they operating at our targeted loss profit opportunity of 4% or less. So I think that there remains upside.

We continue to invest in people and process and equipment up there with the intent of Cheyenne running as well as our other facilities. So the Rockies had a very strong margin driver throughout most of the summer months, even into the fall. We captured that nicely.

But there is still opportunity on the table in terms of both the Woods Cross startup and operating the Cheyenne plant to the extent we can get probably another 4,000 barrels or 5,000 barrels a day out of that plant consistently through better operations..

Okay. Great. And then thinking about repurchases, obviously, there was a decent slug in the third quarter but it was down some from the second quarter. And then it seems like you guys are back heavy in the market in October.

I was curious in the third quarter, was there anything, from a blackout standpoint, maybe that caused you to repurchase less or why was it down so meaningfully on a sequential basis?.

Yeah, so, Brad, that is really a function of the way these ASR programs work. You enter into them and the benefit is you get to report a big slug of stock that gets retired immediately.

If there is a downside to it, is you have to selectively and carefully only at sort of the permission of the executing bank, then be in the open market, because the way it works is it gets executed over a period of time and in our case, I think that was a three-month or four-month time window.

Once they completed their program, which was – let's call it the last week or so of September, we were free to get back in the market. As you know, we went then into blackout September 30, but could execute more aggressively through a 10b5 program.

So understand – if one was looking quarter-over-quarter, they could say, jeez, perhaps they've lost their conviction. Just the opposite, we remain very much committed to what we outlined at our Analyst Day and I think you saw that in October, and we'll continue to see that in the November and December months and then roll forward into 2016..

Thanks. I'll leave it there..

Thanks, Brad..

And your next question comes from Blake Fernandez from Howard Weil..

Good morning. Doug, just to elaborate a little bit on that buyback piece. I think you're pretty clear, but when I look at the cash flow from ops in the quarter, when you strip out kind of CapEx and then what you've returned to shareholder, it's basically balanced.

Is it fair to think that that's the strategy going forward? Or is it just happened to be that the buybacks landed right around where it was about neutral?.

Yeah. No, Blake, that's a coincidence. I mean we are – as we've also mentioned in our prepared remarks, I mean, debt level at HFC, excluding HEP, is zero.

And I think we outlined, again at Analyst Day that one should expect certainly by the first quarter of next year for us to add some leverage to the balance sheet and continuing to get to a more normalized structure.

And so, yeah, sure at some point, in our future, you would expect something more balanced, but not until we reach a targeted capital structure. And that doesn't also speak to expected drop-downs to HEP, including the one we finished on the 1st, which was a little over $60 million. And then notably, up next is likely the Woods Cross drop-down.

So I think coincidental that we were balanced this quarter. At some point, that'd probably be a long-term strategy to look to, but we've got a little ways to go before we get there..

Right. Got it..

Had we been reasonably able to be alongside the executing bank, buy back more shares, we would have run the quarter at a deficit, which is really what our intention is obviously in order to get to a more levered balance sheet..

Understood. If I could just quickly circle back to the, I guess, the guidance on throughput into 4Q and then the previous questions on OpEx.

Is it fair to think with maybe a lower utilization rate into 4Q that the per unit cost could actually trend up a bit just into 4Q here for a short-term?.

Yeah. That's reasonable..

Okay. Then the last question. I know you've already kind of tackled the differential question, but I was just curious, if you could opine a bit on some of the Cushing draws that we've been seeing despite the fact that overall inventories are building up.

I know for a while there Canada had some production offline, but it seems like that's restarted and it's just been interesting to see kind of depleting inventories each week, while overall inventories are actually moving up?.

Yeah, Blake, we are seeing inventories depleting Cushing on one hand. The other hand is that there were a lot of commercial inventories in Cushing basically contango storage plays. With a $0.60 contango, there isn't near as strong an interest by commercial buyers in doing that type trade.

So I think that probably you see that move towards more operational levels unless the contango widens out..

Okay. Thanks a lot, guys. I appreciate it..

And your next question comes from Douglas Leggate from BoA Merrill Lynch..

Hi, guys. This is actually Kalei Akamine on for Doug. I've got a couple of questions. First of all, I just want to ask about the Mid-Continent utilization. When looking at the data recently, it seems like the Mid-Con has been trending around 80% and actually touched lows of 74%.

And we are expecting that maintenance should come back online in November and December, but we haven't seen that yet.

I just want to get your outlook on how that plays out through the rest of the quarter?.

Well, I think in the third quarter, we should have had more of the maintenance conducted than we will in the fourth quarter. So I think utilization rates in that should pick up, but as you said, there will be some maintenance coming on here in November and December with us being a piece of it..

Beyond that you typically see whether induced impacts to Mid-Con utilization, be it in the fourth quarter or in the first quarter. So I'm not sure that I'd expect the high runs that we saw this summer to persist through the winter, even after maintenance is completed..

Okay. Thanks. And as my follow-up, I just want to touch on the buyback. It seems like, in Q2, you guys ran it at pretty accelerated pace and that slowed in Q3.

Understanding that the program from there was $300 million and you seem to have executed that, but on a quarter-over-quarter basis, it is a step-down, so I'm just wondering how you guys are pacing the buyback going forward?.

Let me try to answer this question. The accelerated share repurchase that we entered into in the month of May was one where we immediately sent to the bank, Doug, $300 million, más o menos (36:35).

Okay?.

(36:36).

And immediately, from an accounting perspective, got to take credit for that share repurchase.

Then, the bank is in the market day to day to day, actually repurchasing those shares and as we expressed earlier, very difficult for us to be in the market alongside them, because they're not desirous of competition in the program, okay? So once they complete that program and fill the bucket of actual shares to deliver us come September, we're able to be back in the market.

But if you start sort of in May 15 or May 20, whatever, we started that program and look through the calendar, you see consistent repurchases in the market by either the bank or ourselves through today's date. And so, it's really an accounting difference versus actual execution. The daily repurchased volume in the market has been very consistent..

And I just would add maybe for extreme clarity, our expectation when we announced the $1 billion repurchase plan was to be done within 12 months. So if you wanted to think of it as $250 million per quarter for four quarters, that's probably a pretty reasonable expectation.

It was a little lumpy around that share repurchase program, but going forward, you ought to expect us to be caught up and to have executed within 12 months..

Yeah. And risk of piling on, our purpose in entering that accelerated program was two-fold. One, it was an attractive financial value. We paid a discount to VWAP which we thought was attractive to do.

Second, it represented a different strategy for us to emphasize repurchase to the exclusion of the special dividend and we want to make a statement to the market that we are taking a different turn. So that's really the hows and the whys behind the accelerated share repurchase in May.

Looking forward, I think we will be conventional open market repurchases conducted really by ourselves..

That's clear, guys. I appreciate it..

And your next question comes from Roger Read from Wells Fargo..

Thank you. Good morning..

Good morning..

Hi, Roger..

Hi. I guess, I mean a lot of the good stuff has already been hit, but one thing I want to make sure I understood and we saw this from a number of your peers during the summer, part of the margin capture in Q2, and especially Q3 seem to be that you were capturing even on kind of the lower value-add products.

I wanted to see if that was the case for you over the summer? And how we should think about that over the next couple of quarters in terms of capture versus indexes and obviously indexes are going to get tougher as the differentials stay narrow which is certainly our assumption?.

Yeah. It's funny, the lower value products aren't so lower value as they used to be, especially on the asphalt front. Asphalt has been an attractive business. We make our fair share of it at – especially at Tulsa and Cheyenne.

So we expect to see some of that asphalt positive crack to WTI erode as it's easily does as the winter approaches, but we think it will still be harder than it has been historically..

And on that, I don't know what your visibility on the demand.

The ultimate buyer of it is, but have we seen a change there? I mean, we've been – there was the highway bill issue, there is just general spending on maintenance which probably was lower, I would suspect, given coming off the financial crisis issues and then just the sheer price of asphalt.

But is there anything you've seen you could point to on the demand side and say, yes, that's the reason for what we've seen and the reason for why we would expect that to repeat next summer assuming prices are in the same general neighborhood?.

Roger, if you have driven the streets of the city we live in, you would probably want to get along asphalt, because there are some repairs that need to happen..

Well, Houston has that too..

Look, we're obviously hoping for a highway bill and some spending to happen on infrastructure. It needs to happen but budgets have been tight since 2009 at the state level, though the deficits that they were running in our markets have tended to get more toward neutral.

But importantly, on the supply side, you're seeing a lot less wholesale asphalt being manufactured. And I think you've seen heavy investment in coking equipment, cokers in particular. The big ones are well-known. And there are just fewer and fewer people in the wholesale asphalt supply.

So I think that's as important to part of the market as is the demand, which we think is fundamentally needed whether it will be funded will be one to watch..

And then, I think on the demand side, it's just flat price driven. I mean these government entities have fixed dollar budgets and, at a lower price, they can buy more..

Okay. Great. I'll leave it there. Thank you..

Thanks, Roger..

And your next question comes from Evan Calio from Morgan Stanley..

Hi, guys. Lot's been covered here, but at your Analyst Day, you highlighted $200 million in EBITDA from smaller projects with less than two-year payback and less than $50 million of capital costs, I believe. How should we think about those projects coming online over the next several years and is there anything into 2016? Just....

Yeah, I think, overall, generally, you should view that as being fairly readable. And then the specifics we have coming on next year, as we mentioned at the Analyst Day, a lot of those projects will be related to our turnaround schedule, because they'll be implemented during turnaround.

And the two big turnarounds we have next year are the cat crackers at Tulsa and Cheyenne. So similar to the project that we had at El Dorado cat cracker turnaround late last year, you will see a similar project implemented at those two refineries basically in the spring of next year..

Great.

So it is a run rate in the back half of the year and you're saying kind of ratably so $50 million-plus a year is a reasonable number to think about?.

That's right..

On a run rate basis, yes. Yeah..

Yeah, yeah, on an annualized rate. My second question is on Woods Cross, the expansion. I think you mentioned it's slated now in January to just kind of update there on that process.

And on the product placement side, with the Woods Cross, which markets you're placing the additional product in? There is a big increase in gasoline and diesel production and kind of any potential issues as you see it there for that – placing those barrels? Thanks..

We don't anticipate any and most of those barrels directionally will go south on UNEV to Vegas. The Northern markets that we typically serve aren't growing at any appreciable rates. We anticipate putting some of those increased volumes from expansion up there, but the bulk of it will go south to Vegas..

And the startup, is it kind of a month delay? Is that what that is from late 4Q to January?.

Yeah. It's just a marginal delay. I mean, the Christmas holidays is a poor time to be starting up a plant. And so we've elected the first part of January in order to have mobilized appropriate manpower and contractors to get that done..

Great. So it won't be on your Christmas tree then, I guess..

Unfortunately not. But we have to be realistic about staffing and the kind of people that we need to show up to get this done..

I appreciate it. Thanks, guys..

Yeah..

Thanks, Evan..

And your next question comes from Neil Mehta..

Hey. Good morning, guys..

Hi, Neil..

Good morning. Congrats. Third quarter in a row here of strong operations. It's good to see. In terms of your views on the product markets, you started to explore this and I want you to flesh it out a little bit more, the view that gasoline could potentially be strong here as we go into 2016, but just a little bit weaker.

What do you think is underpinning that? Is that just a function of demand/supply? And then what are the biggest risks of that view?.

Yeah. So it's obviously a global commodity and the big drivers to my mind are flat price driving U.S. gasoline demand. And the U.S. is the biggest gasoline consumer in the world, so it matters. India and China gasoline demand will also matter in terms of percentage growth.

I think that European distillates and distillate margins generally will be negatively affected, which will affect European throughputs and their ability to export more gasoline to the United States. Thus, higher gasoline margins probably in the United States.

And then that European refinery generally in the Mid, first, and then Northern Europe as a balancing to global light oil supply is an important dynamic. Finally, the Caribbean refineries, Venezuela in particular running very poorly. They have traditionally been big manufacturers and big exporters of gasoline, and so we have to add that to the mix.

But the combination of those factors really lead to a constructive outlook in terms of U.S. gasoline margins..

That's great. And then on HEP, obviously, you guys did El Dorado drop-down here. Two questions there. The stock has actually held in really well, HEP. But in your view, is the capital markets open to finance additional drop-downs? And then just timing on Woods Cross, if you could remind us. I think that's the next one to go down..

Neil, as it relates to the capital markets, HEP has held in well. There was a short period of time where it didn't and that was frustrating to a company like HEP where there is many fixed contracts and minimum volume commitments as we have there. I think the market has started to differentiate some.

Right now, we don't have an immediate need for capital at HEP. As we said on our call there yesterday, we do have a long-term target of sort of 50% debt-to-equity. And so, at some point, we'd like for those markets to be more constructive.

I think it wouldn't come as a surprise to anybody on this call that that market – I wouldn't say it's totally closed, but it's not as open as it's been. We really enjoy wonderful flexibility at HEP, because of HFC's sponsorship and flexibility to take units, if necessary.

Obviously, the preference is to take cash at some point particularly on these newly constructed units because of the tax basis, but even if you have to take units in a period of time when those markets are closed, they don't stay closed forever. We know they won't. And so, we will be opportunistic when those markets are open..

And I don't know that we'll be the first out the door, but in terms of the value proposition, as Doug highlighted, it's very steady and visible and growing cash flows, not commodity influenced. And I think it's a really attractive value proposition.

It doesn't have the mid-20%s to high-30%s annual growth rate, but it does carry a 7% yield and a very strong nearly double digits growth rate. So we believe that value proposition will become very clear and that we will be able to raise MLP capital, not necessarily tomorrow, but certainly on a timeline that affords us to continue the strategy..

Yeah. Sometimes, simple is better. Thanks, guys..

Thanks, Neil..

And your next question comes from Faisel Khan from Citigroup..

Good morning. It's Faisel from Citi. If – I guess a couple of questions.

First have you guys changed at all how much pipeline capacity you have moving crude into your refineries over the last year or so, given all the new capacity coming online?.

No.

The capacity really is – the capacity that's come on has largely gone to the Gulf Coast, right ?.

Sure..

With the exception, I suppose, of some of the Rockies pipes coming into Cushing, but those don't serve directly our refineries. So, no, we haven't had a need..

Okay. And then a second question to follow up on that is that, given the sort of wacky environment we're in right now where there is excess pipeline capacity out of some of these producing basins, and we're seeing sort of basis sometimes be negative between some locations.

I mean, how are you guys managing your guys' pipeline capacity or crude purchases because of those sort of wacky differentials?.

Yeah, I think, in all honestly, it doesn't affect us too much, because it's all based on refining value for those crudes from our refineries.

And even though like we said earlier, Midland being over Cushing doesn't help, especially in the fourth quarter, but it was still attractive enough for us to take those barrels out of the Permian to Cushing to run at our El Dorado Refinery, especially..

Yes. It's obvious we have to be competitive on price. And then if people are going to price that barrel in the outlying regions to ignore the sunk cost of their pipeline tariff, the differentials shrink for a while and that's the zone that we've been in for the last three months to six months.

We think through time that there will be a transportation basis differential between locations. But it's going to be narrow until U.S. production starts to grow again..

Sure. And I think that makes sense. And then just – go ahead please..

Yeah, the third quarter was an anomaly I think for the Midland/Cushing spread. You had two big pipelines that were line filling and that also increased demand for the crude and I think you've seen it revert back to more normal levels so far in the fourth quarter..

Okay. That makes sense.

And just going back to your comments on asphalt, what were the asphalt margins in the quarter? I know it's a relatively small part of your product yield, but what kind of margins do you see in the third quarter for asphalt?.

We might have to come back to you on that one, Faisel..

Okay..

I'm sure we can get there, but let's not hold up the call. We'll get to you once we (52:09)..

Sure. No. I appreciate that. Thanks a lot..

Thanks, Faisel..

And your next question comes from Edward Westlake from Credit Suisse..

Hi. It's Johannes here jumping in. So apologies for the subterfuge. A quick question going to turnarounds. There was quite a bit of outage due to planned maintenance and a little bit of unplanned in Pad 2 over this last four months or so.

I was wondering, kind of, what affect do you think that had on regional product prices and sort of basis differentials? And what are you seeing not just for your own turnarounds going into next year, but in your neighborhood as well?.

Yeah. Johannes, the unplanned turnaround seemed to be concentrated in Chicago principally. So, the Northern Midwest, which is obviously connected to our market but not directly.

When that happens, typically, we and others will try to jump in and fill that void, particularly explore pipeline deliveries and thus you see some pretty extreme volatility in that Northern Midwest market, when you get the unplanned events. We participate to some degree in that, but it's small as a fraction of our overall business.

We, obviously, serve principally the Group Three market, which is concentrated around Tulsa, Oklahoma and extends to neighboring states..

Sure..

The utilization in the Midwest probably comes back up. There was a big turnaround at a plant in Minnesota during the third quarter. And there has been continuing bobbles, I guess, in the Chicago land area and connected refineries. So I'm not sure that we can plan other people's unplanned outages.

What we can say is, our objective is to be operating full whenever we have the economics incentive to do that and realizing lost opportunity of less than 4%, which puts us in the top quartile. And our Mid-Con plants are hitting that. So it's nice to be up when others are down. We made good money, had good captures during the quarter.

What happens going forward? Really, we have to focus on our own kitchen and make sure that we are operating and, to the extent that others aren't, obviously the margin will be a little better..

Okay. And then other than what you've already announced in terms of secondary units that are going to go have maintenance next year, there is nothing else to kind of announce or be scheduled.

Correct?.

Just to be clear, what we talked about on this call was fourth quarter activity..

Yes. Correct. I'm aware of it..

Yeah. We did call out that we'll be turning out around the Tulsa cat cracker in the second quarter next year and that will be an opportunity to put some upgrades into that cat, which will improve the yields out of it pretty dramatically. But obviously, there will be downtime anytime you have a cat cracker outage; similar instance in Cheyenne..

Okay. And it seems with your larger projects, whether that be the naphtha fractionator or Woods Cross which will come in early January, a lot of the self-help that you are planning has been coming in over the last few months and will be into the fourth quarter and maybe the very first part of next year.

Incrementally beyond that, how much more should we expect?.

I think we put that in two buckets at the Analyst Day, referring to your self-help reference. We called out a larger capital and you nailed it. It was the Woods Cross expansion that's going to come on in January and the El Dorado naphtha frac that came on just recently.

And then the second bucket is what we are calling our opportunity capital and we basically called out $200 million of EBITDA there and I think, as we've discussed earlier in the call, thinking about that ratably at about $50 million of EBITDA at each year from 2015 to 2018..

Okay. That's all. Thank you very much..

Thank you, Johannes..

And before we take our next question, I'll – going back to the asphalt question. I'm showing we have it by region. So in Navajo, about $3 million of EBITDA in that Southwest region, which was up about $1.5 million prior – or over the second quarter.

In the Rockies, pretty small there about $0.5 million of EBITDA, down $300,000 or $400,000 from the second quarter. And then really the big gains were made in the Mid-Continent in Q3, where we showed about $5.5 million of EBITDA from asphalt compared to about $1.8 million, nearly $2 million in the second quarter..

Thanks, Doug..

Next question please, Brandon?.

Okay. And your next question comes from Phil Gresh from JP Morgan..

Good morning. A couple of quick ones. One is on the working capital. I know you had some negative working capital impacts in the first half.

It looks like also – if I looked at my CFO number for the third quarter, there was also some in the third quarter likely due to lower crude prices, but just wondering is there any expected, kind of, benefits from a volumetric perspective that we should expect in the fourth quarter, or is this kind of the new level of working capital?.

Well, I think you hit the nail on the head. The crude price makes a difference. So what I would tell you in the fourth quarter is pipelines are moving. Particularly, Canadian pipes are moving a little faster, which means maybe not quite as much inventory in the line.

But generally speaking, there has not been any material change in the amount of inventory that we are holding. So you shouldn't necessarily call this the new normal. I think it's a little dependent on price and the speed of pipelines. But overall, our strategy is the same..

It's mostly a price factor. The fourth quarter of the year we tend to come in by 1 million barrels out of 18 (58:30) or so. But otherwise the needs of our system are typically in transit barrels, what I'll call safety stock outside the plants and in the intermediate tanks.

And then, obviously, our minimums are more in the product systems, but those are very consistent over time, so the big swings in working capital are typically crude price-induced..

Got it. Okay. Second question.

Just one more project question with the Woods Cross startup and with the timing of it, when would you expect to hit the full run rate of capacity on that as we look through and think about the quarters in 2016? Do you have a view on the timing of hitting capacity as well as hitting the run rate EBITDA relative to that capacity?.

Yeah. I think a reasonable expectation with the January startup that some time in the second quarter, give us a quarter to line out the units and make sure everything operates correctly and – so sometime late second quarter, third quarter, you will see the full effect..

Okay. And then last question just on those Mid-Con capture rates. You gave us those asphalt numbers, which was very helpful. So it sounds like a good part of that step-up 3Q versus 2Q was due to that.

So, are you basically saying that you would expect capture rates, kind of, 4Q to be, all else equal, a bit lower than 3Q, kind of, similar 2Q, 3Q is in between that is a reasonable run rate moving forward before adding in the self-help?.

Again, that's solely the asphalt impact on capture rates. It should be seasonally weaker in the fourth and first quarters. Just because, again, seasonally asphalt prices and demand slacken versus the second quarter and third quarter. But you'll have the benefit of the Midland to Cushing differential going back to more normal levels.

It should help us as far as capture rate goes in the fourth quarter versus the third quarter..

Sure. Okay. All right. Thanks a lot..

Sure..

And your next question comes from Vikas Dwivedi from Macquarie Securities..

Hi, guys. This is Matt Lair actually stepping in for Vikas. I wanted to get your thoughts on U.S. spring turnarounds. We know Pad 2 had a large turnaround season this fall, especially on the distillation units. But how do you see the spring shaping up for turnarounds in your region and the greater U.S.

in general? We've seen a consultant forecasts so far look a bit live, which is surprising to us given the high runs we're seeing this year?.

Matt, I don't think that this is going to be a particularly heavy spring. I mean, the things that I've been reading and they're probably the same press clippings that are available to people on the call, reflect sort of a normal turnaround basis in the spring of 2016.

That's compared to probably a pretty heavy turnaround activity in our Pad 2 and particularly Group Three markets in the third quarter of 2015. So, possibly, directionally lighter, but I will tell you that these things tend to get pushed around. And I know that some turnarounds have been pushed.

Particularly trying to take advantage of higher Mid-Con margins in the third quarter and whether those turnarounds got through all the maintenance that they would have otherwise done and whether they have some left to do thus in the spring, we really don't have insight into that..

Okay. Thank you. Secondly, real quick. We know there is an octane shortage in gasoline markets this past spring and summer.

Is that a situation that you view as transient? Or do you think it's more structural as we head into the spring and summer and even beyond that?.

Well, there's lot of prediction in all of that, but I'll give you what I think I know.

First, the naphtha-rich crude that we're getting out of the tight rock and the condensate tends to mean that we can use – that we can make less octane, because you got now more light naphtha proportionally in the crude slate, okay? So you're directionally headed towards a sub-grade barrel or sub-octane barrel just based upon the crude you're running.

Second, you've got less incentive to run your reformer, because natural gas is so cheap as a source of hydrogen. So running that reformer to make octane, you need an economic premium in order to do it or the market will be under-supplied.

The final factor, and you may have read about this recently, but with the low flat price of crude and the low price at the pump of gasoline, you've got consumer behavior of people buying up to the premium gasoline whose engines don't necessarily require it.

So, it's a consumer preference issue creating a pull on the octane pool, which we haven't experienced certainly through the last four years or five years. And you can see that article in the press, if you research it.

But I thought that was very interesting and something that hadn't come to mind is that the consumers are actually creating some octane shortfall and less premium..

Okay. Great. Thanks for your comments..

You bet..

And at this time, we have no further questions in queue. Mr. Biery, would you like to have any closing remarks..

Thanks, everyone. 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 Investor Relations. Otherwise, we look forward to sharing our fourth quarter results with you in February..

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