Neale Hickerson – Vice President, Investor Relations Mike Jennings – President and CEO Doug Aron – Executive Vice President and CFO Dave Lamp – Executive Vice President and COO

Jeff Dietert – Simmons Evan Calio – Morgan Stanley Arjun Murti – Goldman Sachs Chi Chow – Macquarie Capital Ed Westlake – Credit Suisse Doug Leggate – Bank of America Merrill Lynch Paul Sankey – Deutsche Bank Roger Reed – Wells Fargo Paul Cheng – Barclays Faisel Khan – Citigroup Cory Garcia – Raymond James

Good morning, everyone. This morning we are proud to present our second quarter 2012 results.

I’m Neale Hickerson, Vice President of Investor Relations at HollyFrontier. In addition to Mike, Dave and Doug, who Bravely has already introduced, we also have other team members of our management team here to assist us with the Q&A portion of our webcast.

We issued a press release this morning which announced our results for the second quarter 2012. This press release can be found on our website at www.hollyfrontier.com.

For our call this morning Mike, Dave and Doug will have prepared remarks and details around our operating and financial performance for the second quarter. At the conclusion of these remarks, our team will be ready to take your questions.

Before we move to prepared remarks, please note the Safe Harbor disclosure statement that’s in our press release today. Statements today and in our press release are made under the Private Securities Litigation Reform Act of 1995.

In summary, the Safe Harbor statement says that 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 securities laws.

There are many factors that could affect our actual results and outcomes. We’ve noted many of these in our 10-K, 10-Qs and other financial filings with the SEC.

Today’s statements are not guarantees of future outcomes. This morning’s webcast may also include presentation and discussion of non-GAAP financial measures that we use in analyzing our financial results.

Please refer to today’s press release and our financial filings for required reconciliations to GAAP financial measures and other related disclosures. And lastly, please note that information presented on the call today speaks only as of today, August 8, 2012 and any time-sensitive information provided may no longer be accurate at the time of any webcast replay, or rereading of the transcript of our call.

And now, I’d like to turn things over to Mike Jennings.

Okay. Thank you, Neale.

Good morning. Thanks for joining us on HollyFrontier’s second quarter earnings call.

Today we reported second quarter net income attributable to HFC shareholders of $493.5 million, or $2.39 per diluted share, which was a 157% improvement over the $192 million or $1.79 per diluted share posted by the company in the second quarter of 2011 that was for Holly Corporation standalone. The prior year comparable results exclude Frontier Oil earnings but considered indicative given the stock-for-stock consideration in the merger.

During the current quarter we generated $862 million in EBITDA, nearly 2.5 times the second quarter 2011 EBITDA of $350 million. Unit profitability for the quarter was very strong with greater than $12 of net income per capacity barrel and refining gross margins ranging from $25 in Mid-Con to 35 in the Rockies.

During the second quarter, we continued to advance our capital allocation strategy as well with emphasis on cash distributions to shareholder along side prudent reinvestment in our refining capacity. In May we raised our regular dividend by 50% from $0.10 a share per quarter to $0.15.

This was the third time we raised the regular dividend in the less than a year and the regular dividend has doubled since our merger last July. Also in May we declared our fourth consecutive quarterly special dividend of $0.50 per share.

Our last 12 months cash dividend yield stands at 6.2% when compared to yesterday’s closing price of $39.42. Additionally, we continue to repurchase shares opportunistically.

Year-to-date, we’ve executed approximately $190 million of repurchases, plus an additional $100 million in the form of a structured repurchase transaction that is not yet matured. Going forward, our primary focus is on growing free cash flow per share with our capital allocation strategy emphasizing distributions to shareholder via regular dividends, special dividends and repurchases.

We will also invest in our core refining business to maintain our production capacity and grow this business in areas where we have a distinct competitive advantage. Most typically, involving unique access to crude and other feedstocks that support attractive and more predictable refining margins.

Last quarter we announced the Woods Cross Refinery expansion in conjunction with long-term crude supply agreement. We are continuing to advance this project through permitting and engineering phases with expected startup still at year end 2014.

Woods Cross Refinery expansion will allow us to compete in a new market unlocked by the recently completed 62,000 barrel a day UNEV pipeline, a 400 mile 12-inch refined product line that runs from Salt Lake City to Las Vegas. In July, HollyFrontier sold its 75% interest in the UNEV pipeline to Holly Energy Partners for $315 million, of which $260 million was paid in cash and $55 million in Holly Energy common units.

The UNEV drop-down is a good example of this synergistic nature of our refining and related logistics operations as represented by the HFC and AGP securities. We expect logistics development for both crude and refined products to be fundamental to our success in refining and marketing business as we look forward.

HollyFrontier is obviously a big beneficiary of North American crude production growth as significant volumes of additional crude oil are either produced Navajo Refinery’s much will pass them in route to larger market centers. Recent estimates indicate total North American crude production of more than 10 million barrels a day by 2015, up 6 million barrels per day currently, with a good portion of this growth right in our backyard.

For the second quarter the Brent WTI differential averaged just north of $15, similar to first quarter levels, despite startup of the Seaway Pipeline reversal which was completed in May. Going beyond Brent TI, we are sourcing crude from a variety of locations and running numerous different crude qualities, with many of these having attractive evaluation from the refiner’s perspective.

Further pipeline reversals and expansions will likely compress certain of these crude differentials with the Brent TI being most susceptible in the near-term due to expected capacity increases in Seaway, Keystone XL and other pipelines being potentially developed from West Texas. Moving to the sweet crude of the Gulf Coast, however, will most likely create another logistical bottleneck, that being within the Gulf of Mexico refining capacity, which has generally been configured with the preference toward the medium to heavy sour barrel.

While it might be concurring view, I don't see attractive crude differentials and the related race to build new logistics capacity as a zero sum game. Currently, HFC is enjoying strong refining margins due in part to growing supplies of domestic and Canadian crude production.

We believe this scenario will continue for a number of years as North American crude production remains well ahead of efficient transportation alternatives. Longer term, the availability of reasonably priced crude to feed our refineries and power our economy will benefit both HollyFrontier and other companies within the U.S.

energy complex who are investing to produce competitively price motor fuels. We expect that HollyFrontier with its Mid-Continent, Rockies and Southwest geographic presence will operate with a long-term structural advantage driven by lower cost access to refinery feedstocks and by lower operating costs assisted by abundant U.S.

natural gas supplies. With that, let me turn it over to Dave Lamp, our Chief Operating Officer for a review of quarterly operations.

Thanks, Mike. Throughput for the second quarter was 412,000 barrels per day of crude and 440,000 barrels per day of crude total charge.

The crude slate was approximately 20% disadvantage crude which are mainly made up of WCS and black wax, and 22% sour. During the quarter light-heavy and sweet-sour spreads widened versus WTI, so in general our crude slate moved towards heavier crude -- heavy crudes up to pipeline constraints.

Average laid in costs for our system -- crude cost for our system was $5.50 under WTI. Brent versus WTI differential was $15.37 for the quarter, just another significant crude that made the adventures WCS was 2300, WTS was 5,3600 and North Dakota light was 99,100.

Total refining operating cost for the quarter were $201 million. Throughputs in the second quarter for the Rockies regions were 76,000 barrels per day of crude and 84,000 barrels a day of total charge.

Disadvantaged crudes were approximately 45% of the slate and 2% sour. Average laid in crude costs for the Rockies region was $12 a barrel -- minus $12 below WTI and operating costs were $5.79 per barrel.

Cheyenne rates were affected by an unscheduled naphtha hydrotreater outage and DHT or distillate hydrotreater outage. Throughputs in the second quarter for the Mid-Con region were 243,000 barrels per day of crude and 259,000 barrels a day of total charge.

Disadvantaged crudes were approximately 16% of the crude slate and 7% sour. Average laid in crude costs for the Mid-Con region was $3.28 under WTI.

Refinery operating costs were approximately $4.33 a barrel. The El Dorado refinery had a scheduled turnaround during the quarter of its large distillate hydrotreater unit and hydrogen plant.

Also an unscheduled outages on the El Dorado distillate hydrotreater and large reformer units, as well as slowdown in the Tulsa distillate hydrotreater during the quarter reduced total crude rates and profitability. Tulsa lub sales were very strong during the quarter at 13,148 barrels per day with an average crack of $90.71.

I’ll also note that the El Dorado refinery began processing 10,000 barrels per day of Christina Lake crude this quarter. Christina Lake has a very high asset number of crude which sells at the discount to WCS.

Current market is about $5.50 under WCS but typically ranges between $10 and $5 under WCS. Throughputs in the second quarter for the Southwest region were 93,000 barrels per day of crude and 101,000 barrels of total charge.

Disadvantaged crudes were approximately 8% of the slate and 80% sour. Average laid in crude costs for the Southwest region was $6.07 of barrel under WTI.

Refining operating costs were approximately $4.49 barrel, Navajo's rates -- crude rates were affected by an unscheduled FCC outage to repair its flue gas cooler. I will say, however, Navajo’s rates averaged over 100,000 barrels per day in May and June.

For the third quarter 2012 we expect to run 420,000 barrels a day crude with the 21% of the slate being disadvantaged heavy crudes and 23% sour. Lastly, we expire our Tulsa refineries distillate hydrotreater will reduces Mid-Con regions crude rates.

We are still evaluating the damage of the fire, but believe repairs will take up to six weeks maybe eight. The last opportunity associated with the fire will result from approximately a 30,000 to 40,000 barrel a day cut in crude rate while DHT.

Distillate hydrotreater is down and result in depressed prices on diesel sales. The Woods Cross FCC and alky turnaround will begin late in the third quarter.

The Cheyenne crude, excuse me, Cheyenne coker turnaround will be completed during the third quarter. No other downtime is planned in third quarter that will affect crude rates.

As a reminder, the Tulsa refinery will have major turnaround in the fourth quarter involvement its entire west plan. Our permit for the Utah black wax expansion of our Woods Cross Refinery has been declared administratively complete by the State of Utah.

The next step is review and approval by federal land managers, followed by a 30-day public comment period. We expect the permit to be approved before the end of the year, engineering is preceding and major long lead equipment will be ready for purchase while the time of permit approval.

The Salt Lake to Las Vegas pipeline UNEV moved approximately 13 -- 12,900 barrels of a product during the quarter. With that I'll turn over to Doug for some closing remarks.

Thanks, Dave. For the second quarter of 2012, cash flow provided by operations totaled $175.6 million.

Second quarter capital expenditures totaled $61 million, excluding ATPs $5.7 million capital spent. Turnaround spending in the quarter totaled $25.2 million.

We maintained our full-year 2012 CapEx guidance of $350 million and turnaround spending of $120 million, with the caution that we might not get all of the capital spent in calendar ’12, but expect to get what we don't have spent by the end of the year and in the first part of 2013. In the second quarter, we returned over $250 million in capital to shareholders as dividends.

As dividends totaled about $127 million and we repurchased 4.2 million shares for a total of $125.6 million in the quarter. During the second quarter as Mike mentioned, we also entered into a $100 million structured share repurchase contract.

If our share price is below the said strike price, when the contract expires later this year we will repurchase up to 3.7 million shares for $100 million. If our share price is above the agreed-upon strike price, we will either receive a lesser number of shares or approximately $108 million in cash.

For obvious reasons, we will not disclose the actual maturity date other than to say it’s later this year or the strike price. Not included in the structured component or rather not including the structured component, year-to-date we have repurchased 6.4 million shares and spent $189.7 million.

We have reduced our share count from 209.3 million shares outstanding in December of last year up to 203.6 million shares at the end of June. At the end of June, coinciding with the announcement of the UNEV transaction, our Board authorized an additional $350 million share repurchase program.

Year-to-date, we’ve returned over $440 million through regular dividends, special dividends and share repurchases. And overall since our July 2011 merger, HollyFrontier has returned over $700 million in capital to shareholders.

As of June 30th, our total cash balance including marketable securities totaled $1.6 billion versus $1.9 billion at the end of the first quarter. Our debt totaled $681.9 million excluding non-recourse HEP debt of $613.2 million.

In addition to the more than $250 million of cash used on share repurchases and dividends in the second quarter and the $100 million of cash used for the structured share repurchase, our quarter-end cash balance was impacted by a temporary built-in inventory, due to the unplanned downtime at El Dorado that Dave mentioned earlier in the call, as well as a drop in crude oil prices during the quarter. Declining crude prices called the short-term use of working capital as lower refine product proceeds were recognized more quickly than crude oil payables.

The opposite is obviously true in a rising crude price environment. As of July 31, 2012, our cash balance was significantly higher at approximately $2.2 billion.

Now, for an update on our hedging program and I don't believe there's much changed since the first quarter. But in the fourth quarter of last year, we had sold forward 40,000 barrels a day of gasoline and diesel, that’s 20,000 of each product for all of calendar 2012 at an average 211 crack spread of $27.63.

Earlier this year, we sold forward 9,000 barrels a day of each gasoline and diesel for a total of 18,000 barrels for the fourth quarter of this year 2012, at an average 211 crack spread of $20.60. And we sold forward 6,000 barrels a day of each gasoline and diesel for a total of 12,000 barrels for the first quarter of next year 2013 at an average crack spread of $18.50.

Now, a quick update on our crack spreads for the month of July. For the Rockies region, the April gasoline crack spread averaged about $30 and the diesel crack spread $32 for the month of July.

In the Mid-Continent, our gasoline crack spread was $28. The diesel crack spread was $34.

And in our Mid-Continent as you know, we make lubricants. The lubricants crack averaged about $72 for the month of July.

In the Southwest region, gasoline crack spread averaged about $23 for the month of July and diesel was about $32. And so far in August, obviously, only a few days in but we are seeing distillate margins continuing to be outstanding in most cases higher than the numbers that we read for the month of July, with gasoline flat to perhaps slightly down in each of our markets.

Lastly, as this is in all likelihood his final earnings call prior to his retirement, I want to take a second to recognize Neale Hickerson for 18 years of service to Holly and now HollyFrontier. Neale was responsible for starting the Investor Relations effort in Holly and when Neale started at Holly in 1994, the market capitalization of the company was approximately $350 million.

Today, it’s $8 billion. That and the fact that the USC football team is poised for national title run, certainly helps explain why we won't be seeing much of Neale after October.

Please help me in congratulating and thanking Neale for his service to HollyFrontier and to its shareholders. After Neale’s retirement, Julia Heidenreich will be heading up our IR effort and, I believe most of you have already had a chance to interact with her.

And with that Beverly, we are now ready to take questions.

Good morning.

Hi, Jeff.

I had a question on Canadian heavy. I know you’ve got some access to pipeline capacity on Keystone, Spearhead and Express.

I was hoping you could remind me what those volumes were. And I think as we look at the growth in Canadian production and the amount of pipeline capacity out, we think there is going to be constraints getting crude out of Canada and that those are going to be valuable assets.

Are you seeing any pipeline constraints at this point? Did you see any in the second quarter?

Jeff, I’ll have Dave review the capacities with you, but the Canadian barrel land in the Mid-Con currently is probably $5 or $10 of the money. So, I think that reflects an obvious constraint as to transportation capacity.

We are using all that we have and using it profitably. Dave, can you review the individual lines for us, please?

Yeah. I don’t have Express in my mind, Mike.

But we have 11 on Keystone, 10 on Enbridge and 35 on Keystone via Frontier. Express typically runs 20 to 25.

Jeff, it tallies up to about 60 a day land in the Mid-Con via Keystone and Spearhead, excuse me and then another 35 to 40 going south to the Rockies via Express. And as to forward constraints, that’s an opportunity – our company has considerably more appetite than we have.

Pipeline capacity, it’s something that we are actively working on as are many others. It’s sort of a high-class problem and that while the constraint exists the differentials on the crude are obviously that much more in our favor.

That’s right. And the economics are such that it's economical to maximize to use the Canadian heavy and currently you are moving more than, what you had from transportation under control.

Were you limited in the amount of Canadian heavy? You could get in my pipeline capacity or did you run based on the LPs?

Well, Jeff, we were limited by pipelines in the second quarter, strictly and our alternative is to buy in Cushing on those desks, which is much less attractive than buying in Hardisty.

Thank you very much and Neale, greatly appreciate all the help over the years.

Thanks.

Good morning, guys. Possibly in echo and I wish, Neale, all the best and I’ve clearly enjoyed working with you over the years.

My first question is on the Woods Cross, extension. I know your notice of intent, would you try to partner environmental quality, appears to contemplate, maybe a broader scope or scale exceeding the January announced expansion.

I’m just kind of wondering if you could maybe discuss and it would obviously be pending on a permitting or a board approval. But what the potential additional expansion could entail or any rare views on the Group Two or Three base of our business and I have a follow-up?

Thank you.

Evan. The first phase of this expansion is a fuels refinery.

That’s the one that we've announced, with about $225 million of costs associated and intending to focus on converting that black wax barrel, which is an advantage barrel for us to run in the gasoline and diesel, with the expected marketing being through down through Las Vegas. Phase 2, which is – pardon me, current – included in the current permit, but not yet approved internally as to capital, is a loop’s focused investment intended to produce Group Three or Three plus lubricants.

It’s very high spec motor oil, which is required by the newer high compression engines. We believe that the black wax feedstock would be an attractive feedstock for this.

We are currently working to develop enough supply among the producers to warrant this investment. So we believe it can be very attractive, but it needs to be feed by increasing production in the Utah waxy crudes and that’s the principal focus of our effort right now.

Understood. And a thought that we may gear more on that, whether it’s the permitting and the negotiation, additional of black wax sourcing.

Is that something you may have by year end in your guidance there?

We are not able to provide guidance on that right now. That’s within our commercial shop and it’s been worked very hard internally and with these producers.

But until we have something that's fairly specific, I don’t think we are going to be able to share more about the project.

Okay. I appreciate that.

My second question is on Tulsa and I appreciate the color regarding the five diesel hydrofluoric unit. On your guidance – I guess can you update, is the east crude unit I guess currently down and the guidance that you gave 30 to 40 lower?

Is that average in the quarter assuming a six week type of fix?

Dave, can you hit that, please?

Yeah, sure. The east crude is currently down.

The west is running full blast. We will be ramping up the east crude, as soon as we get couple of pieces of equipment back in line.

The 30,000 to 40,000 I gave you is while, the DHT is down, although we hope to better that by increasing royalties from sales.

Okay. So, even they are some that you get some runs in that.

I think it was 75,000 barrels of unit. Is that the east unit size?

It’s actually nine but the west is 90 and the east is about 65, so.

Okay. I appreciate all the color.

Thanks, Evan.

Thank you. Mike.

Congratulations to welcome Neale. Neale was always appreciate to help and always gave you credit for the best-in-class disclosure policy.

So, thank you so much. I had a couple of questions.

Just on stock buyback, Doug, does the spending and the shares, did that show up in 2Q or that will show up when it, I guess gets finalized later this year?

Yeah. So the open market repurchases, obviously were as described as in the structured piece, does not affect the share count until the sort of final verdict is in.

What ends up happening is it’s a decrease in cash as well as a decrease in the equity balance. So it’s – as if sort of that money was gone and if the shares are ultimately retired then we will obviously reduce that at the time, if not we will see the cash balance come back as that cash is returned.

Got it. And thank you and it sounds like on the working capital issue for 2Q, basically in your comments it’s reversed here and in July it sounds like.

It has. So, are largely reversed, we still have probably some inventory to liquidate in August.

We did increase our cash balance by the $260 million proceeds from the UNEV sale. But the $600 million or so million dollars of change from June to July is largely explained in either in that working capital you piece described in the liquidation of some of that inventory that was built around the unplanned downtime in El Dorado.

Yeah. And thank you.

And then, David, mentioned the Christina Lake, 10,000 barrels a day, 550 under WCS. What is your, what do you end up paying in transport costs relative to that?

I think it’s seven or eight bucks from up there to your refinery.

About six bucks.

About six bucks. Got it.

So you end up getting close to actually paying almost the two WCS price at the wellhead then when you take that into account.

Right.

Yeah. That’s terrific.

How much additional volumes of that could you run?

10,000s. We could run more, but I think the availability is about 10,000.

That all we can get.

Got it. That’s great.

Thank you so much.

Thanks, Arjun.

Hi. Thanks.

Neale, thanks for all the tremendous help over the years and best of luck going forward. On your OpEx, it seems like you guys did pretty good job on lowering OpEx cost in 2Q.

Dave, can you maybe talk about, if there is some specific action, you took to lower that OpEx and what’s the sustainability of the 2Q trend going forward?

I don’t know there is anything specific that was done other than we ran a little higher crude rate than we had before. Nothing else really comes out cheap.

Okay. So kind of a per barrel rates that we’re going to expect going forward her in 3Q?

I would think so. I don’t know if any -- it is pretty similar on natural gas price of course but I don’t see anything out of line, we really would mean it.

So it’s not sustainable.

Okay. I got a question on evaluation on your shares.

I know you got a lot of synergies with HEP. Mike, do you think you’re getting better credit now for you LP and GP interest in HEP and the share price.

What if it still be like there is lot of inefficiencies in the stock?

As you will know, that it’s hard question to answer. I think there has been a lot of investor focus on MLPs or potential MLPs and people are starting to do more of some of the products type assessment of these companies which is obviously the appropriate way to look at them, where they were getting full credit, here I don’t know but through time, I think as we continue these drop downs and grow HEP along side HFC, it’s pretty self evident that that lower cost of capital gives the refining company a great advantage and also allows the MLP to grow nicely.

So we believe, we will be recognized at $40 a share, probably there is more recognition of that but it’s obviously hard to tell.

Do you have any thoughts, maybe just going down your interest in HEP or maybe even spinning of part of HEP, just established the valuation marker?

We look at all kinds of things as you might imagine. For the time being, Chi, we have a very healthy cash balance and then we’re focussing on distributing that out to our shareholders.

The investment in the MLP has proven to be a very good investment for our company and it’s yielding currently right around 6% while our cash balance is yielding zero. So absent a compelling need to set a valuation by that kind of mechanism, you described.

I don’t think we’d go down in that path at least in the near term. We like the asset.

We like the investment.

Thanks Mike.

Yeah.

Yeah. Good morning.

And again, before I ask a question, thanks very much Neale for your help. Just on, sort of, the -- you mentioned you have more appetite than capacity for some of these Mid-Con crudes.

Can you just maybe give us an update of general gathering projects or rail projects over and above the pipelines as you look around the refining system?

Ed, within our own system or broadly in the industry?

Within your own system, in terms of ability to capture some of the new crudes at discounts to perhaps what we’re seeing over and above what you’re already doing?

Sure. Our internal activities are focusing principally on the area around Artesia refinery in New Mexico due to the significant growth in production out there.

And with the MLP, with HEP, we’ve got activities underway to increase delivery capacity of those New Mexico sweet crudes into Artesia. Beyond that, we are working and confidentially for the time being on additional capacity to get the northern barrels thus being Canadian heavy and Bakken type barrels To Our Mid-Con refineries and those development activities take time but we believe that through time, we’ll be able to do more than we have today to access this crudes.

And then the logical plan would be once you’ve set those up, so then drop those down into HEP?

Assuming we have ownership in those lines, absolutely. I mean, that is the heart of our logistic strategy is to work on logistics that help both companies grow and are strategic to the refining company but obviously benefit from the cost of capital at HEP.

And then on the, say, the Mississippi and on some of the local crudes around the Mid-Continent and we’re starting to see a little bit of acceleration in growth. Is there any sort of cost to yield advantage that you can capture for that part of the barrel?

What I’ll tell you is our focus is more on the northern crude at this point in time. We were looking at the Mississippi and we believe that production could be relevant but for the time being, we’re looking North.

Which makes sense. And then a final question, just on buybacks, you’ve got, I think, $400 million still outstanding obviously that subject to the board but the plan I presume would be, if you continue to generate access cash that you’ll continue on that buyback deal in that level?

Yeah. Absolutely.

I mean, recognize that our distribution program is three pronged. It doesn’t just focus on buybacks and the regulars and the specials are intended to be meaningful.

So I would say that relative to your comment, assuming we still we continue to generate cash at these levels, the expectation would be significant distributions across all three tools.

Thank you.

Thanks. Good morning.

Neale, this is the second time you’ve tried this. Hope it sticks this time.

Good luck. I just have a couple of quick follow-ups to the questions that already have been asked.

If you don’t mind, first of all, Mike on the -- or maybe Doug. On the special, I mean, at what point do you think about rebouncing between special and the ordinary dividend might be sustainable.

I guess, confirming to what extent the combined dividend must be sustainable, I guess, asking that question.

Yeah. It’s something that we talk about quarterly with the Board and through time, I think we probably believe that the regular dividend has better visibility and then let’s say gets more credit than perhaps a special dividend.

With that said, we’ve been consistent quarter-by-quarter in providing these specials. And I think that we’re getting traction with investors that these distributions are real and likely sustainable.

So directionally, we will probably go towards the time where you’re heading and growing that regular dividend as we’ve said before. But the specials are going to remain part of the game for a while.

Got it. Couple of quick follow-ups if I may.

Operationally, at Navajo, looks like for the first time, you’ve had a gas award. You defined us we could.

I’m assuming that’s Permian Basin, crude spending, little bit of refinery is not going to trend higher from Europe. So can you help maybe quantify what the capacity as before your healthy infrastructure expansions?

Dave, can you talk to that please?

Well, I’m not sure I understand your question completely. I mean, we have the capacity to run greater than 100,000 barrels of either WTI or WTS.

I guess, what I’m looking at is the yield was -- I mean, you actually broke it out this quarter is about 4% fairly modest, I guess, as just trying to sweep good reserve and appeal difference between sweet and sour. I’m just curious if that’s sprouting a more meaningful trend given the ramp-up that we’re seeing in Navajo area?

I don’t think its any robust change in our historical slated Narvajo is WTS, a live WTS barrel. And we’re seeing some more of those crudes come in and we’ll buy them.

But we also the 4%, WTI-based sweet is kind of a historical number. It goes up and down a little bit but generally stays in that same number.

It’s just a crude that’s in the area that we always buy.

Got it. Okay.

And if anyone for me, just noting what’s going in the west coast right now. Are you guys seeing any Nor Krone effect into the revolving market.

And I’m just thinking about how -- you might see the benefit, just little quicker and I’ll leave it there. Thanks.

Dave, do you want to speak to that?

Sure. Obviously, we’re seeing some change in the markets but it’s kind of slow.

It will take a while to come around. The San Francisco area jumped up a lot and of course, that supplies the north east which also is the back end of the Chevron pipeline that goes north out of salt lake.

We’re also seeing a little top in Phoenix from the effects of that outage. But I don’t think its all credit in yet.

All right. Thanks guys.

Thank you, Doug.

Hi guys. Thanks Neale and welcome Julia.

Doug, I was on the call there, have you made the forward-looking statements before you made the Company USC? Just had a couple.

One was, if you hedging strategy, I know you haven’t changed it. Even though you haven’t changed your positioning, even the face value.

The market will support most hedging? Hello.

Paul, you’re speaking to opportunistic, sort of, product crack hedging.

Yeah. Exactly, I mean, so I probably doubled that.

What I was trying to say is you haven’t changed your hedge positions as far as I can make out from your comments but I guess, you’d be in position to do more, If you wanted to what you would consider but you previously would have considered attractive levels. So is there a reason that you’re backing off hedging effectively or am I missing something or…

No. You are not missing anything other than the fact that does -- that forward market has improved pretty significantly over the course of the last two weeks maybe.

So it’s a fairly recent phenomenon particularly in our geography which is its victory that we can get some hedges off without a lot of basic risk. It’s a thin market as if we’ve told you before.

And it’s just now starting to improve. So what I’d say is that we’re evaluating it.

We don’t provide market prices as to where we’re in and out until we put the trades on the books but things are a lot closer to our real house now when they were a month ago.

Okay. So it’s brilliant in the realms of the opportunistic ongoing program essentially?

That’s right.

Similar kind of strategy question on what you’ve done with the buyback. Can you just talk about -- to the extent that you haven’t addressed, could you just talk a bit more about the change in how you’ll are actually structuring buybacks and why you’re doing that.

What the advantages are? Thanks.

Sure. We have two things going on the buyback world.

First is what I’d called plain vanilla and that is we have as we describe a desired buyback shares in quantity but inside our view of intrinsic value of the company and with the margin inside the instrinsic value of the company. So we are not in the market at every price in that buyback program but we have been in the market pretty consistently.

Relative to the structured transaction, our view was simple and that is that if you can take a premium to towards your willingness to buy stock at a certain price, that probably makes sense to do that in size. And that’s what we did in a very sort of concentrated transaction that represents the structured share repurchase.

So we have the two operating in parallel and then I don’t think one to the exclusion of the other.

I’ll just add to that Paul. We’ve always said our repurchases are opportunistic and in this instance, as is the case with all of our funding stocks, volatility is high and we saw an opportunity to take advantage of that with a structured format and think it’s something that if volatility remains solid that we would continue to use.’

And so to be clear on this, you get a more attractive price basically at a guarantee level. Is that what it gives you?

By giving the ability to counter party to, we’ll say good shares to you through time, you get the benefit of that premium.

Yeah. It’s been a key to maintenance but I think it bears a peachiness.

It’s my final point -- your strategy when it comes down to is to operate safely and to return excess cash to shareholders and your history says you’ll only make acquisitions at the bottom of the cycle. We’re still on that page right.

We haven’t changed the history book. I don’t think any company ever precludes the potential for an acquisition but what we know is that we operate within a geography that we like a lot.

The value of available assets or the availability of assets that are attractive to us in that geography is limited to non-existent. And the prices that which we try to buy our refineries tends to be at the bottom part of the cycle .

So that’s a little less succinct the near view but I think we’re seeing the same thing.

Okay. Thank a lot guys.

Good morning. Neale, I’ll say thanks short time working with you but you were very helpful in the process.

Anyway quick question, as you do the work on the Tulsa refinery here in the third quarter. Does that have any benefits in front of the turnaround in Q4, in other words, is there any work you can bring forward or anything.

We should thank over that maybe shortens that turnaround and then any cost numbers on the work in the third quarter. I didn’t catch it if you mentioned it before.

No effect on the turnaround in the fourth quarter with Tulsa. As far as cost of the turnaround you’re talking about.

Well, just the work and uses of third quarter or fourth quarters.

We haven’t announced anything on what the cost of those would be and we’re still working on those numbers.

Okay.

Roger, second follow-up, the part of the -- I’ll say ability to continue running crude at Tulsa despite this incident is that we have two locations, the West Plant and East Plant. The East Plant is decided to diesel hydrotreater and that plant is the one which is currently down, it typically runs 30 to 40 day of crude.

The West Plant is largely unaffected. The West Plant is going to be decided fourth quarter turnaround.

So, we can’t run that thing full right now and do prefatory activities for the turnaround. So, it’s not the same opportunity that would have -- that would present itself, if we are at single location that was just down than we try to do opportunistic maintenance.

Okay. That’s helpful.

Thanks. And then follow-up question on the improving your excess to what you call I think the Northern crudes, what -- I mean whether it’s your pipelines or somebody else is.

What is the expectation here that you would be able to tap into the main lines as they come down or we talking about something is significant is trying to build lines all the way from North Dakota down to Kansas or Oklahoma?

Roger, we’d loved to have proprietary lines modestly El Dorado but…

I thought I throw that out there for…

Just as much is going from clear (inaudible) it’s also would be attractive, that’s not economically feasible. So what we are evaluating is collaboration with other industry participants toward developing projects, and whether that’s present us an opportunity for our MLP, HEP or not we will display that out.

But obviously, if it’s attractive project for us and reasonably support with economics HEP is probably interested.

And any thoughts on the timeframe when that could be operationally effective?

These projects take a couple years anyway, so...

Okay. So, 2014, '15 something like that.

Yeah. Yeah.

Okay. Great.

Thank you.

Thank you, Rog.

Hey, guys.

Hi, Paul.

First, Neale, we really appreciate all the help and that wish you a very, very wonderful retirement and then we see their house that football came to us. I have number of quick questions.

Doug, can you given the -- what is the market value of your inventory in excess above?

I will ask J. Gann, who is a recently joined us.

He is our Controller. I will give that number Paul.

Okay.

Replacement -- the replacement value of the June 30th inventory as a $1.6 million by crude and refined products.

$1.6 billion, yeah.

A $1.6 billion by crude and refined products.

Book was $1.3 billion so delta there is what $300 million, $350 million.

Yeah. $350 million.

Yeah.

Okay. And then, I might want just a SLC pipe, Michael line and throughput run rate?

I am sorry, Paul. I didn’t understand.

Pipeline…

You know pipeline, Paul.

Yeah.

That the current run rate on inner.

Dave, do you have the current throughput for inner line.

Yeah. For the second quarter was about 30,000 barrels a day.

Thank you. And do you expect that just roughly that I mean is going to be push slowing, when that you think is going to start ramping up?

Now, we expect to ramp up in the winter and be slow in summer.

So what kind of run rate that you have in mind that going to winter?

More towards of 30,000 -- 32,000 barrels a day roughly.

Okay. And Doug, earlier that you are very kind to get that you nine number for the gasoline and diesel crack and look, do you have the second quarter outage by region?

I do Paul. So, starting in the Rockies for quarter -- second quarter, gasoline was $37 and diesel was $34.

In Southwest gasoline was $33 and diesel was $31. In the Mid-Continent gasoline was $28 and diesel was $33, and lubricants was $87.

Perfect. And earlier that you guys say that third quarter the true expectation is 420 what is the total throughput expectation that you have?

Dave, do you have total charges for the third quarter based on 420 approved input.

Total charges of crude is 420, as I mentioned in my prepared remarks.

And crude plus other?

Plus other is you are typically another 30,000 barrels.

So, 450, okay.

Only 450.

Mike, wondering that, I am sure that you guys looked at one of your competitor that one of a new company that not more than nine picking the form a very bold refining MLP. Have you guys look at that and determined whether that this is something that may fit what you want to do or that you don’t think that you are pick into strategic coding that what you are trying to do?

Well, I congratulate Marion, his group for getting that deal off. I think it’s attractive for them.

I point you to the fact that HEP trades to about a 6% yield and '12, '13 multiple of EBITDA. And that has been the tool of our choice in terms of tapping the MLP market and growing our own fixed distribution MLP based on committing tariffs.

Whether the industry moves more towards this variable rate MLP concept, and I think if you see those securities trade 10 times EBITDA and we’re trading at three its fairly easy math, then it’s a measure of how much depth there is to that market, which with our $8 billion market cap getting -- the company converted to a different security $250 million a ton would be quite a process. So I don’t think that is feasible and let’s that market developed squad lab for where it is today.

Okay. That’s great.

And then final one on retail, you guys never willing into retail and given the end market clearly have a true advantage and everyone just wondering Brett so as we felt and I think that concern that we may start to seeing too much broader in the in end market from that angle, I don’t know whether that you think having more of antically moto including retail in some of your say niche market space, mix sense or not?

Well, our strategy has been to focus on a wholesale. And I think that we can do contractually with people who have deep experience and a big footprint in retail, everything we want to do to distribute our products.

And I understand that the concern, the risk around product demand and the incentive we have to run given the great crude differentials we have particular in the Mid-Con. We are focused on it and we will likely do that through contractual relationships and customer relationships as opposed to through trying to build out a retail network.

Very good. Thank you.

Thanks, Paul.

Thank you and good morning.

Hi, Faisel.

Hi. I was wondering if you could give me a little bit more -- give us a little bit more color on the wider gasoline and diesel basis, you are seeing -- you saw in the quarter in the Rockies versus the Mid-Continent and Southwest, and it seems like you seeing at the same level of basis if not wider in July.

Can you just elaborate in terms of what’s going on with the product basis?

Sure. Dave, can you speak to that please?

Well, I don’t know that I have much insight into that. There is probably a bigger disparity between Chicago the group, the Gulf and historically been.

And a lot of that back to just the crude differentials in the incentive to refine. I don’t think its going to change much, because you get the pipeline distribution systems are controlling, trucking and all that and I just think you are going to see more of it.

Faisel, I’ll just add historically, if you look at, Frontier when we own the Cheyenne Refinery. The Rockies in the summer time was historically a very good market difficult to get product and pipeline were full, demand tends to be better, lot of additional travelers, et cetera in the region, and tends to be a very good market in the summer and tends to sometimes underperform in the winter.

Right. I was just trying to figure out like the basis seems to widen out versus same time last year.

So I was trying to see if there were something different this year versus last year, was there more downtime impact for, was demand has been more robust, are those economies kind of doing better than rest of the country, I’m not really sure?

Yeah. I think the Rockies has pretty delicate balance and there was sometime downtime in Texas than have refiner that tends to supply the front range.

The Commerce City plant I think struggle in the month of May as well perhaps. But as I said, the delicate balance in the summer time tends to be very favorable in terms of margins.

The winter time demand falls in the Rockies, so it’s seasonal.

Okay. Fair enough.

In the Southwest, you ran at a pretty high utilization rate, actually despite a turnaround that you had in the quarter. Can you kind of discuss the how long that turnaround was in and how you are able to run at a pretty high rate despite the turnaround?

We had unscheduled outage during that turnaround in the Southeast, which was the Southwest, which was the SEC. And we basically sold gaso during the period of time either to ourselves and other refineries or to the market.

Okay. So…

I’ll add to that, Faisel, I’ll just tell you that the folks at the Navajo Refinery are hit in the cover after ball, that plant is running well in excess of 100,000 barrels a day, very consistently in the month of May and June. And when we had our bubble relative to cat cracker, we were able to take advantage of the broader company system to distribute gaso around to keep the crude rate up.

So things are going work very well for us there in Artesia and Lovington.

Okay. That makes sense.

And then just with the -- with all the -- with some of the derivatives you have in place. Do you guys have, are there any mark-to-market impacts that you guys experienced in the quarter or do you experience any sort of mark-to-market impacts with the derivatives you have in place?

We did. So we have some that are accounted for us accounting hedges and flow through comprehensive income that aren’t mark-to-market and then we have others that hedge length and inventory of crude that our hedges that are mark-to-market.

And so, what I would tell you, as you had an unrealized gain in comprehensive income about $31 million in the quarter. On our accounting hedges and realized loss and that speaks to crack spread hedges that we had and what was a very strong margin environment in the second quarter.

Our realize loss of about $7.3 million for the quarter that was on the accounting hedges and all knows that were not, that were mark-to-market, we have a $52 million gain due to the drop in crude price during the quarter.

Okay. So the unrealized gain was $31 million and then the, you realized gains and losses were part of the physical delivery of crude oil product that right?

That’s correct.

Okay. Understood.

Thanks.

So, let me just add there was a re-class of some -- of that $7.3 million, so that realized loss on the accounting hedges sort of offsets the gain that we had from the crude oil hedges, which net, net the actual P&L gain for the quarter was $45 million.

Okay. Got it.

Okay. Great.

Thanks for time. Appreciate it.

Good morning, guys. Congrats on a strong quarter.

And I guess I had echo the others on the call wish Neale the very best of around the West Coast. Just one quick follow-up though related to sort of an earlier sourcing, logistics type of question.

As it relates to Woods Cross projects, how should we view the gathering side of that, were you looking to, I guess, source third-party trucks as Newfield actually stepping into this or are there opportunities for you guys actually get some investment on that aspect as well?

The logistics piece of moving that amount of crude from Uinta Basin down to Salt Lake City is significant. Currently the waxy crudes are running by truck and I think through the near-term anyway and medium-term that’s probably how we will continue.

There have been different alternatives discussed heated railcars insulated and heated pipelines all which require pretty significant investment. But we don’t want to ignore the possibility of doing things more efficiently overtime.

So, we’ll be looking at that stuff and evaluating its merit versus the base case, which is trucking. And whether there is an opportunity, therefore AGP that’s something we will evaluate as well.

I appreciate the color.

Yeah.

Well, we appreciate everyone for listening today. I appreciated all of you in the Q&A queue for your time, comments and remarks.

Certainly, what I also think the company for provide any opportunity to be able to work with you. The last thing I would say is, as far as next quarter goes, Julia and the rest of the team will be looking forward to sharing results with you in early November.

Thanks a lot everyone.