Welcome to the HollyFrontier Corporation's Fourth Quarter 2013 Conference Call and Webcast. Hosting the call today from HollyFrontier Corporation is Mike Jennings, President and Chief Executive Officer. He is joined by Doug Aron, Executive Vice President and CFO. At this time all participants have been placed in a listen-only mode and the floor will be opened 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's fourth quarter 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, 2013. If you would like a copy of today's release you can find one on our website at www.hollyfrontier.com. Before Mike and Doug proceed with their prepared remarks, please note the Safe Harbor disclosure statement in today's press release. In summary, it says statements made regarding management expectations, judgments or predictions are forward-looking statements. These statements are intended to be covered under the Safe Harbor provisions and federal securities laws. There are many factors that could cause results to differ from expectations, including those noted in our SEC filings. Today's statements are not guarantees of future outcomes. Today's call may also include discussion of non-GAAP measures and please see today's press release for reconciliations to GAAP financial measures. Also, please note that information presented on today's call speaks only as of today, February 25, 2014. Any time-sensitive information provided may no longer be accurate at the time of any webcast replay or rereading of the transcript. And with that, I’ll turn the call over to Mike Jennings.

Great, thanks, Julia. Good morning. Thank you for joining us on HollyFrontier’s fourth quarter earnings call. Today we reported fourth quarter net income attributable to HFC shareholders of $63 million or $0.31 per diluted share. Our fourth quarter EBITDA was $158 million, 30% below the previous quarterly EBITDA of $225 million. Current quarter earnings were impacted by lower throughputs and weaker refining margins. Fourth quarter throughput was 371,000 barrels per day versus our revised guidance of 370,000 barrels per day. We ran 22% sour and 20% WCS and black wax crudes. Our average laid in crude cost was $5.07 per barrel under WTI. Regionally our average laid in crude cost under WTI was $14.35 in the Rockies, $4.82 in the Mid-Con and $0.51 per barrel over WTI in the Southwest. For the first quarter of 2014, we expect to run 410,000 barrels per day of crude with 22% of this [laid] being price advantaged heavy crudes and 20% sour crudes. Our first quarter crude advantage could charge guidance reflects reduced January crude rates at Navajo, plant maintenance on our El Dorado hydrogen plant and gofiner units and lower rate at Cheyenne following weather related freeze-ups. Total lost opportunity in the fourth quarter was $64 million, the majority relating to reduced rate at the Cheyenne plant coming out of the October turnaround and reduced rates at Navajo which resulted from wastewater treatment plant issues. The Navajo refinery returned to full rates as planned by the end of January after installation of new processing equipment and secondary water filtering technology. We’ve postponed our Navajo crude unit, distillate hydrotreater and [gasol] hydrocracker turnarounds to October 2014 following maintenance work we were able to perform while operating at reduced rates in December and January. The remainder of our turnaround schedule for this year includes…

Thank you, Mike. For the fourth quarter of 2013 cash flow provided by operations totaled $67 million. Fourth quarter capital expenditures totaled a $118 million excluding HEP’s $20.8 million capital spend. This takes our full year capital expenditures to $373.3 million excluding HEP’s $51.9 million. Turnaround spending in the quarter totaled $23.5 million, taking our full year 2013 turnaround spend to $194 million. Our full year 2014 CapEx guidance is $400 million. In addition, we expect to spend approximately $77 million on turnarounds. As we begin to amortize turnarounds at our El Dorado and Cheyenne refineries, we expect depreciation and amortization to increase to a quarterly run rate of between $78 million and $80 million. Total refinery operating costs for the quarter were $245 million. Operating costs were higher as a result of increased environmental accruals, higher maintenance costs, higher natural gas prices, and our final pension settlement expense. Looking forward, I expect a normalized run rate of approximately $260 million per quarter. As of December 31, 2013, our total cash and marketable securities balance stood at $1.7 billion versus $2 billion on September 30 of last year. HollyFrontier debt totaled a $190 million, which excludes non-recourse HEP debt, a little over $800 million. Through 2013, we returned a significant portion of our cash earnings to shareholders with dividends totaling $3.20 per share or 88% of our earnings. We announced and paid $0.80 in dividends in the fourth quarter, reflecting our positive view of the forward earnings environment. We also repurchased approximately 460,000 shares at an average price of $42.89 in the quarter, leaving $312 million of our current repurchase authorization remaining. Since our July 2011 merger, HollyFrontier has returned approximately $2 billion in capital to shareholders through regular dividends, special dividends and share repurchases. As of today, our trailing…

The floor is now open for your questions. (Operator Instructions). And our first question comes from the line of Blake Fernandez from Howard Weil. Your line is open.

Folks, good morning. Mike, in previous calls, I think you had kind of talked about the dynamics of the Gulf Coast and inland refining and how the Gulf Coast seem to start capturing some market share, kind of reaching advantage over the inland refiners. And some of your prepared remarks today and some of the commentary in the press release seems to suggest a bit of a reversal there to where you’re a bit more bullish on inland. I was hoping you could maybe just describe the dynamics that work there.

Sure Blake. In previous discussions, I think the comments particularly in November were pointed toward seasonal weakness in the inlaid market and in particular that the Gulf Coast players and the inland refiners had similar price crude with LL and TI price $4, $5 different and suppose to $18, $20 different in prior years. But that really is the seasonal phenomenon, pointing towards the November to January time period. During the remainder of the year, the inland markets still need to draw product from the Gulf Coast because they are indigenously short. And for that reason, we see these markets pricing at a premium versus Gulf Coast benchmarks through much of the year.

Okay, great. And the second question is, I know you’ve clarified some of the lost opportunity in 4Q as a result of downtime, just as an effort to kind of -- the full year numbers obviously on EPS are below the past couple of years, I was hoping you can maybe quantify some of the lost opportunity on a full year basis due to the downtime, both planned and unplanned. And in conjunction with that, I know you kind of talked about some of the steps being taken to alleviate some of that unplanned downtime, obviously you’ve had some management changes. I was hoping you could just maybe address in detail specifically what you are doing to address that go forward.

Absolutely. First off, as I noted in my prepared remarks, about 30% of the lost opportunity versus our planned related to turnaround execution and overruns and startups following turnarounds. We see those as idiosyncratic events but we had a very heavy turnaround year in 2013. And so for that reason, just by comparison, we don’t anticipate that component repeating in 2014. Beyond that, we are doing a lot on the ground in terms of mechanical integrity, operation process safety management, training, and procedure development. And frankly, we see ourselves as getting better versus where we have been in the past. We had some specific events in 2013 that we don’t see repeating; for example, the Navajo waste water issue, which earlier was one that we couldn’t see coming but had to respond to. It cost us pretty heavily in the fourth quarter. But generally speaking, we have a lot in process pointed toward improving the reliability of our plants. We understand, as I communicated internally, last year we had about a 35,000 barrel per day refinery waiting to be run and we anticipate running that this year.

Okay, fair enough. Thank you.

Our next question comes from the line of Jason Smith from Bank of America Merrill Lynch. Your line is open.

Hey guys, this is actually Doug. Good morning, everybody.

Hi Doug.

I have got -- Mike, I wonder if I could follow up on Blake’s question first of all. So the dynamics in your markets, I think when you and I spent some time together earlier this year, you talked about efforts that you can make to try and mitigate some of that effect by moving your [plug] differently. So I wonder if you could just bring us up-to-date where your thoughts are in terms of what you are doing in terms of your marketing efforts to move product out of the region? And I have got a follow-up question.

Absolutely. Specifically, we are working with the major product pipeline systems to reach additional markets that are to the south and east of us relative to our sort of Tulsa hub, if you will. I won’t be more specific than that but we are generating good progress on those fronts and year-over-year we’re seeing 20,000 barrel per day opportunities to do just that. Beyond that we anticipate using a little bit more of what I’d call the seasonal storage play which basically takes from winter pricing and sends to summer. Obviously there are working capital issues around that but what we think it’s a good investment an opportunity to pick up $10 to $20 per barrel on a crack spread basis at the margin. So those are two principal things that we are doing relative to managing our product markets. And it will be a continuing effort because of the flow of crude oil and the production of crude oil giving the inland refiners and the northern tier refiners great incentive to run, despite obvious seasonal demand issues recognized that the middle of the country has a seasonal demand decline that’s about twice as extreme as either of the coast. So 20%, 25% decline in gasoline demand versus 10% to 12% in the coastal areas. And your second question, Doug?

So Mike, my second question is really on the differentials, obviously we saw some weather disruptions in the quarter so I’m just wondering if you could tell us how you are seeing things right now at least the headline numbers on the screen tell us that differentials have widened again, so I wonder if you could just talk to some of the issues that you saw that disruptive those volume, those normal advantages in the fourth quarter and further not you are seeing the reversal right now and I’ll leave it there? Thanks.

Sure. Yes, so there are three differentials that affect our business greatest would include the light/heavy using WCS benchmark and I think that there were production issues in the fourth quarter, weather-related that system seems to be normalizing, the heavy differential is about $23 a barrel which is really where we expect it to be during the current period unless and until major pipeline capacity is built from the north. Beyond that the Midland-Cushing differential obviously has a strong impact on our southwest refining economics. And right now that differential is out to about $10 a barrel. So it’s very attractive for the southwest players. That product is out by a combination of three things. One is the seasonal downtime in the refining markets in the southwest, second would be the growth in crude production in the Permian and finally the lack of infrastructure, pipeline infrastructure to draw that away from the Permian either to Cushing or to the Gulf Coast. So seeing, towards a seasonal blow out in Midland-Cushing right now, we expect it to normalize more toward what we saw last year once this refinery maintenance period is completed. Final differential we have is obviously strong impact on us is either from TILL depending on how you want to see it and that differential is becoming largely transportation-based, at least between Cushing and the Gulf Coast. We expect to steady go at $4 to $5 a barrel as we look forward into at least the next 12 months. So that’s still advantageous for our business in the middle of the country. And we expect based on pipeline transportation cost for that to be continuing.

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

Hey guys. Mike, I think that you have said that your AGP Permian gathering system will increase from 35,000 to a 100,000 barrel per day. Will you be able to get 100% of your crude from that system and what kind of benefit to your refining system or that it doesn’t really have to physical vertical integration (inaudible)?

Right. Paul, what I would say is that the gathering system is going to bring crude advantage to Navajo. We currently are sourcing all of our crude very locally out there. And so, this will give us more optionality in which barrel we run at the refinery and which we choose to send along to other markets. We will also have crude blending economics, which will show up prospectively in Navajo refining margins that being on the HFC side. But we're locally sourced 100% out there from this point in time. So we may be able to add $0.50 to $1 per barrel based on crude optionality, but that’s really the scope of it beyond the transportation and perspective crude blending economics.

Okay. On earnings you’re saying I think the opportunity corresponding quarter is $64 million, right?

Yes.

Do you have a breakdown by region? And also that you also talk about a bit why that you don’t expect the Sinclair problem is going to happen in 2014? Can you elaborate a little bit more, is there any concrete what kind of concrete step that you’ve taken to ensure a better reliability in your operating result in 2014?

Yes. Let’s start with first question. Regionally we had in the Rockies $30 million worth of lost opportunity in the fourth quarter principally Cheyenne refinery coming out of turnaround slowly and we’d get some start. And also the southwest refinery region hit by the wastewater treatment problems that was about $25 million. So, those two together comprised the bulk of the total. We had small things in our other locations. As to your question of what we’re doing, I think I spoke to it pretty specifically in terms of the initiatives that we have on the ground. We are very focused on refining reliability. We’ve brought in some new people and some new initiatives to get better particularly in the inspection area, which will hopefully give us better preventive insight into potential incidents that could otherwise occur. So that’s really where we are. We expect far better performance in 2014 and forward and finally because of simply having less plant maintenance activity which we tend to correlate with a pretty substantial portion of the unreliability last year, about 30%.

Thank you.

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

Thanks, good morning. I wanted to go back to the Permian gathering system again, just one more question on that, I am sorry if I missed it. But is that growth coming across the whole play or are you focused geographically in either the Midland or Delaware basins or can you just sort of drill down into the logistics expansion there and what kind of assets we know you’re talking about?

Absolutely, our [PG] system is Delaware basin specific, its sits in the area of between Lovington and Artesia, New Mexico generally, bounded on the West South by around White City. We are bringing into service at HEP a segment of what was previously product line and abandoned and now are idle, now bringing that into crude service. So that segment of line and associated gathering expansions to new production sites is going to take our PG gathering capacity from 30,000 to 100,000 barrels a day, which generally speaking goes toward City of Artesia with connections at [Vista] and up to [Slaughter], so you have access to basins in Centurion and the Midland pipelines that connect through Vista. What the impact of that is, there is the obvious and respective crude gathering economics, but also merchant crude opportunities, crude blending opportunities and getting the best barrel from a refinery optimization standpoint into the Artesia plant, again all in the Delaware Basin.

Okay. Thanks so much. And just to bring up quickly RINs I thought that the EPA more or less put this to bed with their last comments the last time they were visible on this, but market has been volatile again. Would you characterize this as just sort of illiquidity and speculators poking their nose in or is there something to this move year-to-date here?

I am stuck speculating. The answer is that Washington has not solved the problem; they basically provided a one year reprieve. We as industry need to keep the effort up to get a substantial reform in the RFS. And until we do that, I would expect volatility. I think the EPA has recognized explicitly and publicly the blend wall and so I don’t expect a blending requirement ahead of the blend wall which means that the structural short of RINs shouldn’t exist, but as long as you have a chorus of uncertainty coming out of Washington, I think you can expect volatility in RIN price and uncertain among investors.

Okay. Thanks very much.

Yes.

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

Yes. Good morning. And thanks for the disclosures on the gathering system in the Permian, I guess I ask this often, but I am just trying to get a sense of how aggressive you’re going to be driving the growth in logistics and whether any of the things like IDRS are a limit in terms of the ability to use HEP and how you might get around that?

Yes. The IDRS are explicitly not a limit to ATPs growth, we’re very pragmatic about that they need to be able to compete based on a reasonable cost of capital. They have a strong regional presence in that Delaware Basin and good customer contacts through both ATP and HFC in terms of further developing that gathering and merchant crew business. So you can expect this to be out in the market and trying to connect up as many customers as we’ll produce in our particular geography, which really is that New Mexico portion, Delaware Basin and the Permian.

I mean I got the sense talking to other management teams in the space that they may be even more aggressive and looking at sort of larger acquisitions to get access to footprints in other basins, is that something that you are also considering?

We are considering but it’s a very competitive space right now. The cost of capital pursued among the MLPs is low and the acquisitions are coming at very high multiples. So we are going to be disciplined, we’re focused first on the area where we have a competitive advantage and put capital to work there to grow that system and if we can find acquisitions that provide a reasonable return to our unitholders on the ATP side, we’ll pursue those.

And then a question coming back to [crudism] and who knows what's going to happen. But at the moment it feels as if the Cushing inventories are going to kind of slush down to the gulf as quickly as people are able to move them and then obviously the Permian crudes are going to find a little bit of a way to get to market when you got somebody’s [rich tanks] et cetera. I mean what sort of, how worried are you about the crude inventory positions they have been Cushing as we get towards the middle of the year?

I guess I don’t worry a lot about that. I think that Cushing will be well supplied. It’s the interim stop for many barrels that otherwise can transit to the Gulf Coast. Certainly we’re going to have to compete for those barrels, but there are transportation costs involved in moving themselves. And I think there will be limits that show up in terms of Gulf Coast appetite for the light sweet barrel.

Okay, very clear. Thanks so much.

Welcome.

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

Good morning.

Hi Jeff.

I wanted to a follow up on the WTI Midland weakness as well and follow up on your ability to take advantage of that. At Navajo, the contracts you have in place, are they tied to WTI Midland or WTI Cushing? And secondly, is there anything that would prevent you from using the capacity you control on basin and Centurion pipelines?

First question is our exposure to Midland versus Cushing and that exposure is about 90% not between 90% and 95%, towards Midland base pricing, feeding our Navajo refinery. Beyond that, second question Jeff was around basin and using that capacity. We've got certain amount of capacity on the basin pipeline and that's very much in the money right now, shipping crude to Cushing. I think through the year, we see that as positive, but not $10 per barrel contributor to our Mid-Con refining economics. I think the annual average if we think in terms of $3 Midland Cushing, $2.50 to $3 that's probably realistic. The plains basin tariff is between $0.50 and a $1 depending on whether it's in incentive or not. So, those are those relative economics. Centurion is one that we currently ship heavy crude West on from Cushing to the Southwest region and we will continue to evaluate that. If Midland is depressed relative to Cushing it obviously makes less economic sense to be sending crude out to the Southwest. But through time that has been a contributor for us and so it’s not going be something that we walk away from quickly.

Okay. And are you seeing any significant changes in Permian crude quality, higher API, more condensate type crudes in the Permian?

There certainly is a lighter sweeter barrel coming out of the Permian now. And I think that’s observed most recently by the Longhorn crude line increasing its gravity spec by about 2 points out of necessity. So, that’s going to be something that industry has to deal with and combinations will have to made within the transportation system in order to do so, crudes like lightening it creates bundling opportunities for some and will create transportation difficulties for others.

Thanks for your comments.

Sure. Thank you Jeff.

Our next question comes from the line of Chi Chow from Macquarie. Your line is open.

Thanks. It’s Chi Chow, Macquarie. Hey Doug I was wondering if you can help us reconcile the cash from operations balance of $67 million at the end of the quarter. Just looking at net income and D&A and looks like you had about $300 million decline in working capital 3Q to 4Q, that can’t seem to get to the $67 million number, can you help us out there?

I think that I can. [Jay] if you have it, it looks like [maybe you’re] ready and want to talk to it, go right ahead.

Sure. The reconciliation to our cash flow from operations, we consumed working capital of about $128 million in the fourth quarter that was a use of our cash, cash flow. And that’s our principal difference turnaround of course used cash flow which was $23 million and then we had a deferred income tax of $67 million going the other way. So again reconcile those two numbers cash flow from operations to EBITDA with those three items.

So it was a use of cash working capital $128 million?

In fourth quarter, yes.

Okay. Maybe I will follow up (inaudible) I have come to number there. Okay. I guess secondly, can you talk about the succession plan for the COO position?

What I tell you is that, we have a strong team internally and that we will get the organizational structure in place that makes best sense for our company, that’s all I have for the time being.

Okay, all right. Thanks Mike, I appreciate.

Yeah.

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

Hi, good morning.

Hi, Roger.

Just a quick question for you, just to kind of come back to the turnaround, the clarity obviously on much lower turnaround spending in ’14. But again the comment on some of the turnarounds didn’t come off as quickly in ’13 is come back online as quickly as you had anticipated. Can you give us an idea of maybe days offline in ‘13, versus expected days offline in ‘14, any sort of maybe rough range on something like that?

I guess I don’t have that immediately available for you. What I would say is that in each of the Navajo and Cheyenne turnarounds in 2013, we had outages that went past the turnaround by an additional two weeks or so, probably up to a month in Cheyenne and that we have effectively one location under turnaround in 2014; El Dorado has large turnaround and that comes in the fall, so substantially lower scope than we had by about half or less in terms of dollar spending during 2014 and with a lot of focus on execution.

Okay. And then the other question I have, you made the comment at the beginning, $2 billion of capital return to shareholders here over the last couple of years; what is the -- or is there any updated thinking about the dividend, the special dividend, a bigger turn toward share repurchases; I mean how often is a program like this sort of reevaluated between management and the Board to make sure that you are getting the impact that you’d like to see from something like that or is simply the goal to give the cash to shareholder and that the method is not that important.

Well, I would say it’s a combination of those things rather; in terms of the frequency, we think about it at minimum quarterly, we talk about it with our Board every time that we see them. Certainly Mike and I visit about it more often. I would say that our view on share repurchases really hasn’t changed that is to buy back shares opportunistically when we see our shares trading at what we believe is a significant discount to its valuation. And we evaluate capital project the same way; we don’t think buying back shares should be any different. And that really hasn’t changed. So we’ll continue to buy back shares opportunistically. In terms of then splitting the remainder between regular dividend and special, what I would say is that we would like to grow the regular dividend steadily over time. It’s been several quarters since we’ve seen that, so something that we’ll look at with more scrutiny in the near term. And the special dividend is an opportunity to return excess cash through the cycle is basically what we’ve said. And that I think over time will be somewhat dependent on earnings, but not until we deplete our existing still very large cash balance relative to our debt. So, I think the message is there is a combination of both art and science in this. But overall, we’ve been market leaders in returning cash to our shareholders since we’ve been a merged company and we wouldn’t expect that to stop certainly in the near to medium term.

Okay. Thank you.

Our next question comes from the line of Clay Rynd from Tudor, Pickering and Holt. Your line is open.

Good morning guys.

Hello.

Your refining operating income looks weaker than implied by kind of the net operating margin from your different regions; is there any outside factors kind of pulling down those earnings?

The actual margins and sales, I mean if you look at it just -- the total barrels that we run certainly pull down our margins. I mean the other contributing factor were -- it was better than in the third quarter, we still had some bottom in the barrel issues, we had backwardation in crude markets and we had RINs. Those would be the first things that come to mind. But unless you could be a little more specific, I think it’s hard for us to pin it on one thing in particular.

Yes. I guess talk a little bit more about the bottom of the barrel and how do you see an asphalt market kind of perform through 4Q and how you expect to perform going in 2014?

Sure. The asphalt market in 4Q was what I would call sort of lackluster with wholesale prices in about the $400 per ton and obviously weak in terms of retail as seasonality took over. As we look forward, there is what I’d consider to be a huge slug of deferred maintenance at the state and local level in many of our markets. It doesn’t mean that it’s all going to come through the system in 2014; that is really not our expectation. But I think as we go forward through time, the roads will have to rebuilt and that our investment in retail asphalt operations will payout for us pretty nicely. There is a good deal of heavy crude available for us and on the other side has been a lot of incremental investment in coking capacity by our competitors. So, the dynamics for the bottom of the barrel should improve over time, it’s really a question of when the state starts to spend.

Alright. Thanks guys.

Thanks.

Our next question comes from the line of Faisel Khan from Citigroup. Your line is open.

Good morning. Thanks for taking my question.

Hi Faisel

Hi. I was wondering if you could give a little bit more color on the naphtha fractionator you guys are building out at El Dorado; is that going to be able to consume some of the light condensates coming out of the Eagle Ford or is it really just designed to improve the yields at that refinery?

It’s the latter, this is not a condensate splitter; it’s a tower in an investment intended to better fractionate our reformer feed, getting what we like to stay the right molecules into the right place. What will happen as a result of that is that we’ll be feeding less naphtha to the reformer and be -- running the reformer at a lower rate incurring lower volume loss through that unit and supplementing our hydrogen needs through a natural gas based steam ethane reformer. So, our hydrogen will be supplied at the margin more by natural gas than by crude oil, we’ll be running the reformer at lower severity. We have all the octane that we need in the form of ethanol blending. So, our question yield improvement project as well as shifting liquids-based hydrogen source to gas-based.

Okay, got it. So the $95 million project also includes that steamed -- the hydrogen reformer too?

Correct, it does.

Okay. And then just could you elaborate a little more on how you guys are thinking about acquisitions in the refining space? I know you like to generally bias to the bottom of the cycle but we’ve seen some activity in the space, just want to get certain updated view from you guys in terms of how are you still thinking about it?

Yes. Our view on acquisitions really hasn’t changed. We’re opportunistic; trying to find those assets that best fit our system and have what we consider to be a durable feedstock based advantage. Looking at our footprint and our profile, our existing assets give us a lot of that. And we would anticipate that as we go forward, our particularly geography will be our first area of focus. I’ve spoken in the past about the potential attractiveness of Gulf Coast in terms of a source from which to export product and otherwise integrate our system from north to south. Those assets come for sales periodically and it will be on an opportunistic basis. But end of the day, deployment of our capital has to compete through internal projects namely CapEx, share repurchase and market opportunities; we are able to [chain] up on the outside.

Okay, thanks. Just last question from me, can you answer how much cash you guys, excess cash you want to retain on the balance sheet overtime. I mean you talked about how your special dividends continue to be a message of delivering some of your excess cash back to shareholders, but what’s the right cash balance at the end of the day on your balance sheet?

What I would say is, and this is a little bit on way thing that you can’t see obviously through the phone, but I think generally $1 billion or so given our CapEx profile, with the Woods Cross Phase 1 expansion still to go possibly at Phase 2 and then a desire to have some dry powder if an acquisition opportunity would present itself. I wouldn’t say that’s hard and fast, but certainly we’d say that we’ve got to go down at least to that level as a target number with the right to change our minds.

Okay, makes sense.

When we talk about acquisitions and internal investments and things through which we allocate and deploy capital, those are the opportunities to significantly change the company strategically and its financial profile and this company has grown through acquisition though slowly overtime as these opportunities present. So you can expect us to maintain a balance sheet that enables that kind of flexibility particularly in down markets when these assets tend to be less valuable.

Okay. Thanks guys. I appreciate the time.

Our next is a follow-up from Chi Chow from Macquarie. Your line is open.

Hi. Great thanks. One more quick question, I noticed in the fourth quarter you realized a loss on the sale of excess crude I think first time in quite a while, can you talk about that trend in the fourth quarter and what we can expect to hear in 2014?

Yes. The losses on sales of excess crude really are unpredictable and then we sometimes have gains sometimes have losses. In that instance what you were talking about is barrels purchased to operate the refinery in the Southwest, we have reduced crude throughput opportunity because of wastewater treatment plant and that comes through the system as we have to dispose those barrels as somewhat of a distressed seller. So it’s those kinds of things that will end up in that line item, as well as normal accesses in shorts as we operate our merchant crude system. I wouldn’t expect large changes in that line, large gains or losses as we go forward, but they’re hard to anticipate.

Okay. So it’s really due to the nominal issue primarily in the fourth quarter?

Yes. And Cheyenne, I think a little bit with the other area we have some crude disposition in Cheyenne as well on counter plus low out of turnaround.

Okay. Thanks a lot.

Okay.

And we have another follow-up from Paul Cheng from Barclays. Your line is open.

Doug, just want to follow-up -- two quick ones. One relate to the working capital, I was looking at that in the -- at year-end if I am looking at working capital excluding cashes, $557 million in the third quarter end is $559 million. So I would think working capital from a cash flow standpoint is relatively flat, but I think you guys were saying that it’s a use of cash of $120 million somewhat, what am I missing here?

Yes Paul, what I have in front of me shows, our accounts payable increased or was a use of cash of nearly $300 million in the quarter that was offset by inventory which was -- we reduced inventory at quarter-end by $212 million, so that's $80 million or so. We have an increase an income tax receivable, which was a use of cash of $35.4 million, a prepayment of $17.6 million; our crude liability is increasing $33.3 million and few other sorts of dogs and cats that got to that number. We’d be happy to I guess walk through that offline, if anybody like to go through, we should have our 10-K filed later today for those that want to get into it. Beyond that I’m not sure I have much intelligent I could offer.

That would be great. I mean I’m just looking at very simple based on what you post in your press release as your balance sheet, you say working capital at the end of the year is $2.2 billion and cash is $1.67 billion, so the difference is that the working capital before cash and that's $557, if I went through the same thing that's $559 in the end of the September?

Yes. Let us work with you offline any others that want to call Julia and I will certainly be available throughout the day to help anybody reconcile.

Okay. That's great. The second one is that Mike, when you’re talking about working with other major product pipeline companies that’s looking for a solution to expand your reach on the marketplace, will HEP be part of the solution or that's not really an option there?

Well, HEP's footprint in Mid-Con really is limited to refineries themselves. So that isn't going to be a near-term solution other than small segments of pipe that are more economically constructed by HEP to tie us into various larger trunk lines. So, I wouldn't expect HEP as larger participant in the Mid-Con certainly in the Southwest where they own the product pipeline systems out of our refinery, we will be using ATP to a much greater degree as we expand our footprint.

Okay. Thank you.

Okay.

And there are no further questions in queue at this time. I'll turn the call back over to Julia Heidenreich for any further remarks.

Thank you all for joining us this morning. Again, if you have any follow-up question, we'll be available all day and we look forward to sharing our first quarter results in early May.

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