Welcome to HollyFrontier Corporation's Fourth Quarter 2014 Conference Call and Webcast. Hosting the call today from HollyFrontier is Mike Jennings, President and Chief Executive Officer. He's 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. [Operator Instructions]. Please note that this conference is being recorded. It is now my pleasure to turn the floor over to Julia Heidenreich, Vice President, Investor Relations. Julia, you may begin.

Good morning, everyone, and welcome to HollyFrontier Corporation's full year 2014 earnings call. I'm Julia Heidenreich, Vice President of Investor Relations. This morning, we issued a press release announcing results for the quarter ending December 31, 2014. If you'd like to see a copy of the press release, you may find one on our website www.hollyfrontier.com. Before Mike, George and Doug proceed with their prepared remarks; please do note the Safe Harbor disclosure statement in today's press release. In summary, it says statements made regarding management's expectations, judgments or predictions are forward-looking statements. These statements are intended to be covered under the safe harbor provisions of federal securities laws. There are many factors that could cause results to differ from expectations, including those noted in our SEC filings. Today's statements are not guarantees of future outcome. Today’s call may also include discussion of non-GAAP measures. Please see today’s press release for reconciliations to GAAP financial measures. Also please note that the information presented on today's call speaks only as of today, February 25, 2015. Any time-sensitive information provided may no longer be accurate at the time of any webcast replay or any rereading of the transcript. And with that, I'll turn it over to Mike Jennings.

Thank you, Julia. Good morning. Thank you all for joining us on HollyFrontier's fourth quarter earnings call. Today we reported a fourth quarter net loss attributable to HFC shareholders of $222 million or a negative $1.13 per diluted share. Excluding the $397 million non-cash pre-tax inventory valuation charge, the net income attributable to HFC shareholders was $21 million or $0.11 per diluted share. Fourth quarter EBITDA excluding the inventory valuation charge was $134 million, 15% below the comparable quarter last year. On a per barrel basis fourth quarter consolidated refining gross margin was $10.76 versus 10.96 per barrel in Q4 of 2013. During 2014, we focused a tremendous amount of energy on improving our refinery reliability. The increased training emphasizing operating procedure and discipline, occupational and process safety management teams were formed and we launched a risk based inspection program across our sites which we expect to further reduce process safety events. In addition every refinery employee participated in training and get improving hazard recognition and accident prevention. The benefit of the another investments being made across our refining systems are evident. Our 2014 refinery utilization rate was 91.7%, nearly a 5% improvement relative to 2013 levels and above our five-year average. 2014 lost opportunity was half the 2013 levels and I am confident we will continue to see improvement during 2015. With limited 2015 plant maintenance and expected operational improvement, we believe we’re well positioned to reap the benefits from improving product margins and widening crude spreads. We have seen a rebound in gasoline demand growth spurred by cheaper gasoline and by an improving labor market in the U.S. Monthly vehicle sales have recovered to pre-recession levels. SUV and light truck sales in particular has hit record levels accounting for over half the vehicles sold in the United States.…

Thanks, Mike. Fourth quarter crude throughput was approximately 350,000 barrels per day versus our revised guidance of 359,000 barrels per day. We ran 32% sour and 11% WCS black wax crude. Our average laid-in crude cost across our refining system was $1.50 per barrel under WTI. Total refinery operating costs per quarter were $270 million. Expenses in the Rockies have increased due to added cost and advance of the Woods Cross expansion and continuing efforts to prove reliability starting on refinery. In the Mid-con we are making improvements to the Tulsa refinery infrastructure demolishing idle tanks and units to make the plant safer and create room for potential future capital projects. In the Rockies crude throughput was 65,000 barrels per day. We ran 1% sour and 46% WCS black wax crude. Average laid-in crude cost was $6.30 per barrel under WTI. Refinery operating cost was $10.29 per throughput barrel. I expect OpEx to revert to historical level in $6 to $7 per barrel range and we'll complete from the Cheyenne investment when the Woods Cross expansion comes on line. In the Mid-con region, crude throughput was 200,000 barrels a day. We ran 27% sour and 5% WTS crude. The mechanical repairs for the El Dorado gas oil hydrotreater prompted a shift for lighter and crude slate requiring us [indiscernible] light heavy differentials in the quarter. As a result average laid-in crude cost was $0.68 per barrel over WTI, refinery operating cost was $7 and $0.05 per throughput barrel. Total lube sales in the fourth quarter were approximately 8,500 barrels per day with an average frac of approximately $75 per barrel. We have since completed repairs to the El Dorado gas oil hydrotreater and are once again running heavy crude at refinery. In the Southwest region, crude throughput was 95,000 barrels per day. We ran 100% Permian crude, of which 63% was sour. Our average laid-in crude cost was $3.56 per barrel under WTI. Refinery operating costs was $5.54 per throughput barrel. We successfully completed planned turnaround to 35,000 barrels per day on Tulsa West crude unit during the first quarter. Total lost opportunity in the quarter was $36 million, much of which was related to the El Dorado gas oil hydrotreater. As Mike mentioned in 2014 we began to see benefits of our efforts improved reliability across our refining system cutting our lost opportunity in half relative to 2013 levels. For the first quarter 2015 we expect to run 400,000 barrels per day of crude with 27% of the slate being sour and another 20% being WTS Black Wax crude. In addition to the Navajo crude unit turnaround which was completed in early February our 2015 turnaround schedule includes expected quarter crude unit turnaround at the Woods Cross refinery. With that I'll turn it over to Doug for some closing remarks.

Thanks, George. For the fourth quarter of 2014, cash flow provided by operations totalled negative $47 million. I'd like to mentioned a few items that impacted the quarter. We incurred a $27 million pre-tax environmental accrual and a $20 million write-off of assets that were no longer usable. Fourth quarter capital expenditures totalled $178 million, which excludes HEP’s $18 million capital spend. This takes our full year capital expenditure to $485 million excluding ATPs $80 million capital. Turnaround spending in the quarter totalled $65 million taking our full year 2014 spend at $97 million. In 2015, we expect to spend $650 million in capital and additionally $70 million on [changing] turnarounds. As of December 31, 2014, our total cash and marketable securities balance stood at $1 billion, a $437 million reduction from the September 30th levels. Cash outflows in the quarter included $187 million in dividends and share repurchases and $178 million in capital expenditures. Through 2014, we returned a significant portion of our cash earnings to shareholders with dividends totalling $3.26 per share. Lastly, we announced our $0.32 per share regular quarterly dividend which puts our yield to 3.1% as of last night’s close towards the top end of the peer group range. Given the pullback in share price we decided last week to reallocate the special dividend spending towards share repurchases. During the fourth quarter we repurchased 540,000 shares at an average price of $43 per share. Year-to-date, we have repurchased an additional 433,000 shares. Last week our Board authorized a new $500 million share repurchase program replacing all existing share repurchase authorizations. Going forward, we expect to be more aggressive in our share repurchase program. HollyFrontier's debt totalled $187 million, including non-recourse HEP debt of $868 million. HollyFrontier owns 39% of Holly Energy Partners, 22.4 million common units plus the 2% general partner interest. The current market value of our LP units is approximately $770 million as of last night’s close. Fourth quarter general partner incentive distributions were $9.8 million, a 22% increase over the same quarter last year. For the full year 2014, we received approximately $83 million in cash distributions from HEP. 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 that are meant to show monthly trends. Realized gross margins per barrel may differ from the indicators for a variety of reasons. You may find the data on our Investor page at hollyfrontier.com. And now Audrey we’re ready to take questions.

The floor is now open for questions [Operator Instructions]. Our first question comes from the line of Paul Cheng with Barclays. Your line is open.

Two questions. Doug I just want to make sure I [indiscernible] you said 2015 [credt] is 600 to 650, there's another 70 million in the turnaround that number seems to be a bit higher than what we expected. Can you put down between on the refining and the logistic?

So Paul that’s mainly all going to be the refining side the reason that number is higher than what you’ve seen in years past is we’ve got the completion of the Woods Cross expansion this year that project is still expected in the previous guidance range of 375 million to 400 million but we’ve got roughly half of that spending still to do in calendar 2015. In addition, the completion of the El Dorado naptha fractionation project that occurs this year that spending largely given 2015 and then the maintenance levels within our plans are roughly the same I can’t think of really any other big items but the completion of those two projects are going to be the ones that stand out taking those numbers higher.

How much is there second project that you mentioned?

The total is a 100, less the spend is 70%.

70%, so….

So of our 600 -- of our 600 to 650 Paul that’s nearly 270 million less the spend this year.

Seems to me a little bit high, I thought your sub spending capital in the refining is smaller in the 300 million or so only.

That’s accurate Paul, so the difference is really those two significant growth projects, basically projects that have been previously appropriated and are being completed now, we have a tier three gasoline project which is obviously environmental compliance related at the El Dorado refinery, that’s going to cost approximately $65 million it’s got a hydrogen plant going in at Cheyenne in its current year in the $45 million to $50 million range, so these are projects that were appropriated a couple of years to go and are coming now into their construction phase and being completed. The sustaining capital for the plants including turnarounds is really very much in the range of $200 million to $250 million, so these growth projects that are now in the construction phase and nearly complete that are going to consume the large part of the cash spending this year.

And what is the HEP CapEx spending for this year?

70 million to 75 million Paul, so I fair certainly said yesterday on the HEP call.

So that means that in your cash flow statement when we're looking at the CapEx [now should be] somewhere in the 670 to maybe 725 something like that, right, because that's fully consolidated in your results.

That is correct.

And Mike can you elaborate a little bit in terms of what is your growth strategy and target for the HEP and did you have a target I mean in terms of somewhat your competitor talking about the third-party [indiscernible] they want to increase it to a certain percentage some people will go for 50-50, some will even go more [indiscernible] to reduce 70-30. Do you have some kind of objective here and also that whether you want to expand the HEP beyond the existing product line in to also looking at the natural gas and gathering and all that or that you are going to speak with call on the refine product and the crude logistic?

That’s a rich question, Paul let me try to address at least the bulk of it. The growth strategy for HEP is twofold. First it's around continuing to partner with HFC in projects that have stable and high cash returns, the El Dorado Naphtha Fractionation project is a very good example of that, it's effectively a gas to liquids project as we described in the past using more natural gas to generate hydrogen less reformer fee to do the same thing. The project returns are somewhere between two and three years of pre-tax cash payback on the original investment amount depending on crude oil price environment that we’re talking about. But this kind of project to my mind fits very well into HEP and we’ll continue to seek those kinds of projects out. Also very important is external growth and the third-party revenue that everyone in this industry covers, our best likelihood of doing that is through expanding the Permian gathering system, we’ve got a strong footprint out there. Malacca was our most recent investment and we’re doing a very good job of doing that ultimately moving those barrels to the Cushing market and to our own refineries. So strategically we like the Permian in terms of third-party revenue growth and we very much like to continue to partner with HFC in these high margin predictable dropdowns the likes of which we called out in terms of the El Dorado Naphtha project and a portion the Woods Cross Phase 1 project.

Your next question comes from the line of Doug Leggate with Bank of America. Your line is open.

Mike, you gave a fairly good estimation earlier in the year about what was going on regarding the extended maintenance, I wonder if you could help quantify an opportunity cost that goes along with that particularly related to the change in crude slight and I guess what I am really trying to understand is most of your competitors reported much stronger capture rates where you guys don’t appear to benefit from that, so I am wondering if you can just help us understand what is going on there? I have got a quick follow-up please.

I am going to let George speak to that, but you're right, we got our timing exactly wrong relative to attractive heavy crude differentials in the fall, but we had a planned turnaround and we obviously needed to take. George in terms of quantify?

As we said, the lost opportunity for the quarter was $36 million and I’d say the vast majority of that was associated was the El Dorado treater and our inability to run WTI and we have [indiscernible] WTI, but beyond that just the nature of having the plan turnaround cost another approximately $50 million, we wouldn’t consider that lost opportunity because there was a planned event and obviously something we needed to do, but relative to competitors and capture rates that might help to reconcile.

I guess my follow-up is to Michael's question because obviously, I mean clearly the whole sector has benefitted from the tailwind that has been the very strong rebound in margins I guess the economic beginning of the year were part of that but similar thing going on at gas with the WTI brent spread and I am just kind of curious what gives you confidence in your double-digit assumption for this year given that we have got a very steep contango currently and obviously there is a lot of refiners offline turn in our respect to come back. I'm just kind of [indiscernible] 50, 60 oil price that tend to almost describe sees wherever it reaches at sustainable levels. I'm just curious what's behind your thoughts and I'll leave it there. Thanks.

Doug I think that the best of levels that we achieved was in less than average levels for the year I really have no idea. But the fact is that despite rigs being laid down and those numbers that we all look carefully at week on week production continues to grow in U.S and a lot of that production is finding its way in the tankage of Cushing, it's incented to do so obviously by the contango storage and we're moving now into more maintenance fees particularly in the Mid-con. So I believe that Cushing is going to spill or close to spill the operating levels and if that will carry over through a decent portion of the year in terms of impacting inland versus costal crude differentials.

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

Just like to start a little bit on the utilization and your comments earlier about kind of taking a more risk based focus everything like that. So utilization of 5% in '14 versus '13 steady level of maintenance expected this year. How do you look at refining utilization potential this year it's 91.7 in '14 can we see that creep up a 100 basis points 200 basis points? And then kind of follow on to Doug's question about the differentials would that affect it if you were looking at an average differential of say $3 as opposed to today's $9. How would you think that might affect the utilization potential?

I think on the utilization side 2015 we are going to have a lighter turnaround schedule than we had the last couple of years. The two notable turnarounds were crude unit [indiscernible] which is already behind us. And then we'll have a turnaround at Woods Cross sometime this summer at that crude unit. So that’s basically yes, those are our two major turnarounds and one of them is [already] behind us so expect we can add to the utilization rate accordingly.

So you commented earlier about spending instead of like the CapEx directed towards maintenance was about the same. So it's just a deeper turnaround of those units but less capacity offline as a result of that.

Roger the comment on maintenance was maintenance capital as opposed to turnaround spending. The turnaround spending this year is really fairly low I think for [memories] in the $40 million range which doesn’t afford much turnaround. The turnaround as we called out crude unit in our [indiscernible] which is the small crude unit in the Navajo system and then the crude unit up in Woods Cross. So the lower turnaround activity coupled with anticipated higher reliability certainly achieves a couple of 100 basis points if not higher.

And then should the share repurchase program now more of a focus the special dividends looking like more of a rare view event. As you look and you commented earlier about being more aggressive in the share repurchase area. What is the sort of economic model for your decision on when the buyback to your shares versus not. I mean just year to date or go back to mid-December the stocks obviously had a real nice move here. And I'm just wondering easy to be aggressive in lay out price how do you evaluate it as the price goes up, just anything you could do to help us understand that.

Sure well lets first talk about I think the question with the big move I saw some commentary we made the announcement last week about not having repurchases made shares perhaps folks would have expected in the fourth quarter. And what I would tell you is that we had our sights sets on what I think was a transformative transaction for our company, one that we thought was a significant opportunity for us and had us in cash saving mode, that opportunity ended up not coming to fruition and I won't be specific but I'm sure most can guess as to what I am talking about and so its taken a direction at our last board meeting. I would tell you that in the near term and having suspended the special dividend we'd expect to repurchase something in the neighbourhood of nearly $100 million worth of stock over the next 90 days that would otherwise match what our special dividend payment would have totalled for the quarter. And also caution though that our current [indiscernible] to favour share repurchase it doesn’t mean that the special dividend's necessarily gone forever. We really just remain committed to maximizing shareholder value and returning capital to shareholders through dividends and share repurchases and would again point to our track record of having returned nearly $3 billion since our merger in 2011 through the combinations of dividends and share repurchases. Beyond that Roger I think probably we’re going be a little more agnostic as to the price and simply allocate capital to share repurchase as compared to our past where we really allocate the bulk of our distributions to cash dividend and then try to be very opportunistic with respect to share repurchase. As we ramp share repurchase up proportionately we’re going to need to be in the market more consistently.

Your next question comes from the line of Ryan Todd with Deutsche Bank. Your line is open.

Maybe if I could ask a question on your thoughts on WCS it would appear that we have material inventories building in Cushing with [this kind of like] wide end to potentially clear those inventories. Can you talk a little bit about your -- about what you’ve seen in WCS your outlook and with widening GI disc as well? How are the results of economics looking between running light and heavy crude right now?

Well as you know WCS bps is coming from roughly $20 per barrel to more of a low teens $13 currently. I think at that level it’s still attractive to run from WCS at our refineries especially Cheyenne which has a lower transportation cost because of WCS but also El Dorado which as you know the past Cushing and we have the alternative there to either run the WCS at El Dorado or sell it into the open market. I think WCS is still very attractive for Gulf Coast refiners relative to Maya, Maya is trading about $3 100 WTI whereas the WCS is trading at about $7 100 WCS and Cushing and with the Cushing the Gulf Coast pipeline capacity available there is a lot of WCS going from the Cushing market to the Gulf Coast compared with Maya.

And from a -- any insight that you guys have in terms of maybe relative level of WCS -- like heavy versus light inventories in Cushing?

I think there is a lot of WCS to be stored as part of the contango play in Cushing. I don’t have any specific volume -- percentage of volume that’s going in towards the WCS versus WTI. I think it’s fair to say that there is a good percentage of the contango play that’s being stored at WCS.

Okay. And maybe, if we could shift gears a little bit to, and I appreciate that maybe there is not much change on this from the last call. But any update on your, on your current thoughts for the potential for the Woods Cross Phase 2 expansion? Is that likely to remain on hold until we see more clarity on the supply outlook, and how the crude compression plays out? Or, I guess, any thoughts on timing and outlook for the expansion there?

I think on hold is a good way to describe it, we’ve done some great good upfront engineering estimating and permitting work and we certainly hope that that comes to fruition but it is a crude specific project and with $50 WTI you don’t see a lot of drilling activity in the Uinta so where I need to see a change in crude price in order to get the producers back in the game and wanting to look forward to these long term supply contracts that would cause us to push forward with that project.

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

I was just wanting to clarify on Woods Cross Phase 1, you've got contractual commitments there for supply. And are those take or pay contracts with the reduction in drilling activity? I just want to confirm you're not at risk there?

Well, the nature of the contract is not that the producer has to produce but there is a consequence if the producer doesn’t produce.

That’s right. So to the extent that production doesn’t meet the contract volume there is a mechanism in place to receive compensation for any volume shortfall neither us nor our suppliers really want this mechanism to be triggered and obviously producers want to produce and refiners want to refine oil. But to the extent that there is a shortfall that shortfall leaves triggers that compensation which provides us with a positive return on investment and that’s for any margin we generate are utilizing that capacity with some outsider crude supplies.

Yes, I'll assume it's a base load -- view it as a base load contract for the suppliers as well. Secondly, could you talk about -- with the west coast refinery outages, and higher margins on the west coast, I assume that's impacting Las Vegas? Is that creating opportunities both for HFC and HEP upon the UNEV pipeline?

Yes, we’re taking as much of volume as we can within our contractual commitments to other customers in Salt Lake and other markets, we’re taking as much of iron as we can to Vegas and the same applies for Navajo where we’re taking as much product as we can to the Phoenix market to take advantage of the West Coast basically being short product right now.

As you identified Jeff that this spot shipments on unit line are higher as well, and there is a pretty strong driver to new product from the Rockies down to the Las Vegas market and it's just really a question of available barrels to do so.

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

Hey, guys. A quick question. Do you have any lease storage space either by you or by HEP in the Cushing area that you can play the contango?

Yes, we do, market package we have is operational in nature but we do have state by the contango well.

That had you guys did increase or change of inventory as a result at contango?

I would say we have not increased our inventory levels significantly.

Is there any reason not then?

Paul, we're telling you as much as we can within the constraints of our large storage both at Cushing and at our refinery.

It is something that we’re really viewing at the refinery level in addition Paul because it's not just Cushing we have tanks as you might imagine throughout the system and the question is how much inventory do we want to carry and with what contango economics but obviously there is a strong driver there.

I have to apologize, I'm sorry. I came in the call and may be late, you have maybe already mentioned that at the beginning of the call. What is the nature of the write-down?

On the aspect write-downs Paul? The largest of that, I mean there were several that were small that sort of add up to a big number, the ones that accounted for $50 million pre-tax and that $0.05 per share after tax was a pipeline and assuming Nebraska that we had we thought potentially and a higher crude price environment might have an ability to move some Niobrara crude or otherwise in the current environment just seeing that was not going to come to fruition in the near-term and as a result made a decision to go ahead and take that off our books.

That mean you're….

Paul, I am sorry to do this to you, if we could maybe get you back in the queue…

Your next question comes from the line of Manoj Gupta with Morgan Stanley. Your line is open.

Thank you for taking my question. You mentioned you expect the Cushing to fill up to operatable capacity. It was a very interesting comment. I'm just trying to understand what is the time frame you think this could happen?

You want us to give both a number and a date that’s something. George appears to be filling at between 4 million and 6 million barrels a week move there probably 30 million barrels of capacity remain to 25 to 30 range, probably 30 is a good number. So as you said over the next eight weeks to 10 weeks, I think that was probably be a pretty conservative number and that’s been also corresponds to a season in which there will be some significant maintenance in Cushing market and in the Mid-con more generally. So that will be my forecast.

That is very helpful. And I'm extremely sorry if I missed this, but can you give your throughput guidance for 1Q, one time again? I'm sorry if I missed it.

Yes, we gave guidance of 400,000 barrels a day.

And can you split it by region, sir?

No, we don’t tend to do that, but I will tell you that number doesn’t include the Navajo turnaround that George already mentioned. So you’d expect the Southwest region to be on the lower end, but otherwise we only give consolidated guidance.

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

Thanks very much for the questions. The MLP you mentioned, obviously that you got a high tax base on. Some of the assets that you are building in the refining space, and obviously those are going to be very profitable assets, so it makes sense. So is there -- is there a sense of how much EBITDA you would be willing to discuss today that would form the basis of those drops?

We really haven’t scoped that quite yet, but we think in the neighbourhood of more than 10 and less than 50 for those assets that we called out that’s probably a good range. But there will be more to come certainly by the second quarter call.

Right. And is this a shift to -- obviously, some of your competitors in the space are sort of drawing lines around different parts of their refineries, and dropping them down into the MLPs, and creating fee income, and then just taking the hits on OpEx at the refinery level. Is this a general thought process to do more of that?

Well what I would say is we're not ignorant of the 5x versus 15x multiple differentials between these securities. How we play it I think what we've said is really what we're looking for the high basis steady return portions of the refinery each business is different some folks look to retail versus wholesale and such like that, it depends a lot on one owns business strategy. Ours really has been to emphasize the newer projects which have more stable returns and that’s where we're going be taking it for the next little while.

Okay. And then, a separate question. Obviously a lot of focus on crude, but product inventories up in Group 3 and in the Mid-Con are relatively high. So I guess, I'm just wondering, how would you think that might affect your capture of this very good environment that we should expect over the next few months?

Inventories in the Magellan system and has been pretty well behaved given the time of the year. We had very high run rates in December and even January and still there is inventory capacity that is just functioning well and the margins are good. I suggest the question is will the refiners store this cheap through this products and I see demand as offsetting that, right now you've got some winter weather that's supressing that but gasoline demand is very good in the markets that we serve and then we expect it will get better as we claw out of winter towards the more normal driving seat.

Just to add I think it's also significant turnaround in the mid-continent that resulted in inventory levels falling faster than they have in prior years.

Yes, it is just a complexity, it was close to you guys, was worried about it. So I just wanted to check your thoughts.

Your next question comes from the line of Chi Chow with Tudor Pickering Colt. Your line is open.

Great. Thank you. Just Mike, a point of clarification on the -- acid drops, the fractionator and the Woods Cross expansion. Are you talking about a tolling arrangement that you are hoping to create at HFC?

Well how you construe whether T.H.B. or tolling effectively its fees for service relative to the MLP potentially funding a significant portion if not all of the assets. And so I wouldn’t be proposing puts much if any margin risk into the MLP we have a fixed distribution MLP which traditionally has provided terminal pipeline tankage services to the refining company. And I think at least that we see processing units in there it would under the same service concept. Does that answer your question?

Yes I think I do so.

I that's synonymous with totalling, I haven’t really construed it that way. But I think it's the same thing.

Okay, good. And Doug, could you give us the hedging impact in the quarter, both on the, I guess on the crude side, and WCS side, and then the products? -

Yes I can -- well let me -- yes, I will, the answer is on the product side we had a quarter about a $20 million accounting gain and on the economic side which is basically the crude drop we had a $65 million economic gain 55 million of that was realized in the quarter of the other it's sort of mark to market Chi. So in total about $85.3 million of derivative gain for the quarter that was in total completely offset by life of revaluation if you will of almost we hit that same number which is why it shows not to call them out if the net was about a zero but as you can imagine with the big price moves there was large life of loss also in the period which was again almost right at the $85 million number.

Okay. Great. Can you provide any guidance for 2015 on your hedge positions, both on product and crude?

Crude our position is to continue to just only hedge inventory in excess of what we call our base levels. So when we build inventories for turnarounds or otherwise and there aren’t many turnarounds so we don’t have a whole lot of excess inventory plan this year we tend to hedge that. So certainly wouldn’t plan for anything there in terms of our product hedges I think the number is 12,000 barrels a day a diesel head in the mid-continent for a little bit north of $30 a barrel.

Okay, great. Thanks. And maybe just one more. Any impact on your end, or how you are preparing for any strike activities that may come your way from the USW?

We’re in strike preparation right now Chi. We think we’re going to be ready if and when it comes, we don’t think it’s close to our plant but one never knows where this is going to go. And as you probably know the plants where we have USW representation is El Dorado, Cheyenne those are the two and then Woods Cross as well.

Okay, great thanks I appreciate it.

What I had for unsolicited color is that our local relationships are between very good and excellent and I think you’ve been the reading press, good characterization of the driver in terms of this current strike it has maybe less to do with wages and safety and things like that and more to do with our bringing non-union contractors on the union payrolls. And it’s going to be a difficult conversation at the national level but locally we have great work force and good relations with them.

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

Good morning, everyone. Maybe a question for Doug. You've talked in the past about how you are comfortable at a much higher leverage level on the balance sheet than you are currently at. I was wondering, what are the items that you would potentially use the balance sheet for? Is that strictly acquisitions? Or is there a chance that you would use that to repurchase shares?

Well I think the answer is certainly we would use the balance sheet if we had what we saw the high return accretive acquisition opportunity in terms of the share repurchase or using debt to pay dividends I think we probably need to at least deplete our existing cash balance of $1 billion before we entertain that conversation. What I would tell you and what I’ve said in the past is certainly our current capital structure is not optimal especially given the low rates that are available for investment grade companies to borrow money. So over the course of the next 24 months and maybe sooner than that as we enumerated a pretty large capital expenditure program for 2015 I think taking some debt under the balance sheet over the next year or two may very much make some sense absent acquisition opportunity but we’re not there yet.

Okay, and can you remind us what sort of minimum cash balance you are comfortable with?

I would say that that depends I guess a bit in the price of WTI you certainly want to be able to afford to buy crude oil we do have $1 billion revolver which is really largely and completely unused, I mean we’ve got a couple of LCs government agencies that I can think of. But other than that it’s largely unused. So we have pegged $1 billion historically as saying that would be where we would reconsider the special dividend or share repurchases. I think especially in a $50 WTI environment we’re certainly comfortable inside of that whether that new number is 500 million or something even less than that I am not sure I want to commit to that. But we certain want to -- it's better safe to make sure that we have sufficient liquidity to run our business and that includes the ability to fund our capital programs and to buy crude oil for our plants and that number moves around a bit but it’s lower than what our cash balance is today.

Bottom line is we feel like we have a lot of running room in terms of share repurchase and other distributions to shareholders but before we did any kind of liquidity of capital structure constraint.

Okay. That's great color. Thanks. And then, speaking about El Dorado and the hydrotreater issues, was there any of that spilled over into the first quarter, or maybe affected the crude slate?

I think we might have a couple of days but nothing significant.

Okay, great. Thank you.

Those repairs were completed in early January.

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

My questions have been answered. Thank you.

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

Yes, thank you for taking my question. Just wanted to follow-up on, on the dropdown potential from the two projects that you are considering? So if you look at the guidance that you have given for both Woods Cross and also for El Dorado, how much of that total EBITDA that you expect could be dropped? I know that you mentioned $10 million to $15 million, but is it possible that the entire say, $115 million could be dropped, if the right arrangement was made?

I think doing that would require either the two entities to take a lot of what I'll call pay out risk or residual risk we’re probably more comfortable dropping a portion of the EBITDA and then retaining a significant portion into refining company and the reason for that is to be able to drop a steady stream of cash flow into the MLP as opposed to a variable stream, sort of giving us margin for air or for margin for pricing margin volatility in the future. Its early areas and upward limit on this other than what’s reasonably appropriate. We also have as you might imagine the capital cost as a tax basis in the assets when you exceed that you start to pay tax which is considerably less efficient when you give away 40% of the price to the government in the process.

Thanks for that. And just on, on Tulsa, is there any update on the permit filing to utilize the -- that 170,000 barrels per day over there?

Well, that require some time. I think everything is proceeding as we anticipated on that permit, and we expect to get it sometime soon.

Looks like the question queue has been depleted. Thank you all for joining us on our call and we look forward to talking to you next year in early interim. Thank you.

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