HF Sinclair Corporation (DINO) Q3 2013 Earnings Report, Transcript and Summary

Welcome to HollyFrontier Corporation's Third Quarter 2013 Earnings 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 Chief Financial Officer; and Dave Lamp, Executive Vice President and Chief Operating Officer. [Operator Instructions] Please note, this conference is being recorded. It is now my pleasure to turn the floor over to Julia Heidenreich. Julia, you may begin.

Good morning, everyone, and welcome to HollyFrontier Corporation's Third Quarter Earnings Call. I'm Julia Heidenreich, Vice President of Investor Relations. This morning, we issued a press release announcing the results for the quarter ending September 30, 2013. If you would like a copy of today's press release, you may find one on our website, www.hollyfrontier.com. Before Mike, Dave, 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's 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. Please see the press release for reconciliations to GAAP financial measures. Also, please note that information presented on today's call speaks only as of today, November 6, 2013. 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.

Thanks, Julia. Good morning. Thanks for joining us on today's HollyFrontier's third quarter earnings call. Today we reported third quarter net income attributable to HFC shareholders of $82.3 million or $0.41 per diluted share. Third quarter EBITDA was $225 million, which is about 57% below the prior quarterly EBITDA of $521 million. The current quarter's earnings were impacted by lower refining margins, compressed crude differentials, weaker capture rates, partly due to elevated regulatory costs, which related to the RFS mandate. In addition, we incurred higher crude oil cost on account of the backwardated WTI curve, which persisted throughout the quarter, and also had lower coke product margins on asphalt and fuel oil. Dave and Doug will discuss these impacts in further detail. On a per barrel basis, our third quarter consolidated refining gross margin was $10.64, which was about 48% below the $20.28 of gross margin per produced barrel that we recorded in the second quarter of 2013. On a WTI basis, gasoline cracks fell 45% to 50% across all regions, and diesel cracks fell by more than 20% across all regions from Q2 levels. Our gross margins were further impacted by declining crude diffs as the WTI discount to Brent averaged just about $5 in the quarter, less than 1/2 of the $11 we saw during -- on average during Q2. During the third quarter, we announced and paid $0.80 in dividends, reflecting our continued focus on generating shareholder value through cash returns to shareholders despite current margin weakness and compressed differentials. As of today, our trailing 12-month cash dividend yield stands at 5.2%, relative to yesterday's closing price of $46.43. As anticipated, inland-coastal crude differentials were volatile during the quarter, and I expect this volatility to continue during the near term, particularly as we approach line fill for…

Thanks, Mike. During the third quarter, crude throughput was 417,000 barrels per day and total charge was 448,000 barrels per day. The crude to date was 19% disadvantaged crude, which are mainly WCS and black wax and 22% sour. The average laid in crude cost under WTI was $2.50 per barrel. For the quarter, the average Brent-WTI differential was $5.39 under WTI. WCS, for reference; was $21.52 under WTI. WTS was $0.58 under WTI, and North Dakota light was $4.87 under WTI. Total refinery operating costs for the quarter were $225 million. Total lost opportunity in the quarter was $42 million, the majority of which was related to reduced rates at Tulsa East due to a crude unit problems coming out of turnaround and reduced rates at Cheyenne and Woods Cross due to reformer issues and a crude unit failing, respectively. For the Rockies region, throughput was 68,000 barrels per day and 73,000 total. Disadvantaged crudes were approximately 49% of the slate and 1% sour. The average laid in crude cost was $8.25 under WTI. Refinery operating costs were approximately $11.8 -- excuse me, $8.11 per barrel. For the Mid-Con region, throughput was 248,000 barrels per day and 265,000 barrels per day of total charge. Disadvantaged crudes were approximately 15% of the slate and 8% sour. We ran about 10,000 barrels per day at Christina Lake, a high asset crude number -- asset number of crude, which sold at an average discount to WCS for the quarter of $7.97. The average laid in crude cost for the Mid-Con was $2.00 per barrel under WTI. Refinery operating costs were approximately $4.86 per barrel. Tulsa lube sales from the third quarter were approximately 11,200 barrels per day and an average crack of $60. The backwardated crude market in the quarter negatively impacted…

Thank you, Dave. For the third quarter of 2013, cash flow provided by operations totaled $351 million. Third quarter capital expenditures totaled $101 million, excluding AGP's $14.2 million capital spend. Turnaround spending in the quarter totaled $10.7 million. We maintained our full year 2013 CapEx guidance of $400 million to $450 million and turnaround spending budget of $200 million. As of September 30, 2013, our total cash and marketable securities balance stood at approximately $2 billion, basically unchanged from the $2 billion balance on June 30 of 2013. HollyFrontier debt totaled $190 million, excluding nonrecourse ATP debt of $809 million. In the third quarter, we distributed $220.5 million in dividends to shareholders, which includes the $0.30 regular dividend declared in the second quarter but paid in the third quarter, as well as the $0.30 regular and $0.50 special dividend, both declared and paid in the third quarter. In the third quarter, we've repurchased approximately 598,000 shares at an average price of $41.60, leaving $331 million of our current repurchase authorization remaining. So far in the fourth quarter, we've also repurchased 423,000 shares at an average price of $42.70. Since our July 2011 merger, HollyFrontier has returned nearly $1.8 billion in capital to shareholders through regular dividends, special dividends and share repurchases. The rating agencies have recognized the financial strength of HollyFrontier, with Standard & Poor's and more recently, Moody's, upgrading HollyFrontier to investment grade with a BBB- and Baa3 rating, respectively. Investment grade rating should result in lower cost of capital over time, will suspend some provision in our bank covenants, as well as our long-term debt, enable us to likely cancel any LCs we currently have outstanding. In the quarter, we recorded an unrealized hedging loss of $27 million, relating to the Western Canadian Select hedges. The impact of…

[Operator Instructions] And your first question comes from Paul Cheng of Barclays.

A number of hopefully really short questions. In Southwest, Dave, when you buy WTS order, the WTI Midland, is it based on one month lag, or that is nearly spot?

Well, it's calendar month average, Paul.

It's calendar month average. So basically, you already know 2 months of the discount that you're receiving for the fourth quarter right now?

Yes. Sure.

Okay. On the -- Doug, do you have a -- the inventory market value in excess of book?

I'm not sure that I do. Julia, do you have it?

The difference between current cost and LIFO is $436 million and between market cost and LIFO $476 million.

$476 million?

Yes.

And Dave, do you have -- what is your Cheyenne light/heavy differential that you realized in the third quarter?

Light/heavy diff? Well, we don't have it by Cheyenne, we'll have it for the Rockies, Paul. It looks like -- average laid in crude cost was $8.25 under for the Rockies.

And I'm trying to understand -- I mean, by looking at the WCS on a trademan basis, looked like this Con versus WTI in the month of October and November, it looks like that they have expand easily by about $8 or $9 comparing to the third quarter. So is there any particular reason we should not assume you will be able to benefit by the 4-month in the fourth quarter versus your third quarter.

Well, we've had the plant down for the month of October, Paul. So that would be the principal reason. But other than that, no. The increase in differentials should be incremental to realized crude differentials, recognizing Cheyenne's average slate is approximately 55% to 60% heavy, with the remainder being North Dakota light, or similar.

And so how much is the heavy oil that you're going to run in the fourth quarter?

Well, we gave a guidance of 23% on average disadvantaged crudes, 19% sour. And that's the whole slate.

So the 23% is all WCS?

WCS, as well as Christina Lake, as well as black wax.

Right, so roughly about 90,000. So I should assume that you're still running WCS or that the Canadian heavy somewhere in the 70,000, 80,000 barrels per day?

Yes, very close.

All right. Dave, have you been doing any, in the Southwest, any product export? I think you guys have talked about it at one point.

We do export to Mexico. Diesel, basically, a little less on gasoline.

Do you have a volume then, how much you export in the third quarter?

I don't have that number with me, Paul. I can get it for you.

Is there any opportunity that you'll further expand the volume that you can export?

It's always a potential to do it. It's probably an open market for us as Mexico is net short refined products. But that is a very competitive market, too.

I see. All right, a final one. On the $42 million of the third quarter opportunity cost that you've mentioned, do you have a spin in Tulsa and in Cheyenne?

Let's see. Let's see, Cheyenne was about $6 million of that. Tulsa was about $23 million. Navajo was about $3 million, or call it, $4 million, and Woods Cross is about $7 million.

Your next question comes from Paul Sankey of Deutsche Bank.

Just a detailed question to start with -- struggling to reconcile cash flows and earnings and working capital. Could you just clarify how come cash flow is seemingly so strong?

Paul, I think the big change that maybe you haven't seen and you'll see on the 10-Q is because of the rising crude prices, we had a $144 million benefit to change in working capital. So at the back of the envelope for me is $225 million of EBITDA, $144 million of working capital, take out of that interest expense, which isn't part of, obviously, cash flow from operations and I get the $355 million, which is, I realized, our press release is $350 million, $351 million, I'm not sure what that extra couple of million is, but I'm sure that gets you close.

Yes. And then a high-level question for you. This was obviously a very tough quarter. It's unusual to have such a tough quarter in Q3. It was kind of a confluence of events, I guess, almost a perfect storm on negative elements. A lot of those, obviously, have changed. We're going through a period of unprecedented volatility in U.S. refining. Can you just explain what you think were the big problems in Q3, and then give us an outlook, Mike, for how you see the market changing over the coming year or so and any particular catalyst events that you see occurring in the market?

Sure. I mean, we could boil the ocean, I suppose, but Q3 was a perfect storm in a lot of different respects, a perfect negative storm. One of the biggies that is underappreciated is the impact of the serious situation and rising crude prices on U.S. refining profitability. The run of crude from mid-$90s to $110 on a WTI basis was frankly brutal in respect of both light product margins and more importantly, heavy product or co-product margins at the bottom of the barrel and at the top of the barrel. The LPGs got hit in that process. So I think what you have is a certain amount of demand elasticity when you see the price at the pump going higher, you lose volume, the RINs compounded that, adding to our compliance costs, obviously. So that is unrelated to crude price, but it piled on. We had further development of Pipeline Transportation capacity out of the Permian, drawing that differential away from us in terms of the TILL differential, which is important again in setting light product margins in the U.S. inland. So I'd say those are probably principal factors. There may have been a few more, but those are the ones that come immediately to mind and they all worked against us.

Yes. And then looking forward, Mike, obviously, this quarter, so far, gasoline is still awful, but a lot of other elements are working much better for you. And then could you just talk a little bit about how you see 2014 developing?

Yes, sure. So for this quarter, you've got the more traditional seasonal effects in terms of gasoline demand and prices. But crude differentials have returned, and I think the $64,000 question, with respect to 2014, continues to be the effect of U.S. product exports and coming principally off the Gulf Coast, how effective those producers will be in placing products into other markets, taking pressure off the U.S. markets in terms of product margins. In addition, prospectively, we see continuing growth in crude production and that's, for us, coming out of the Permian, the Bakken and Canada, all of those contributing to crude differentials. The production remains ahead of pipeline capacity in most instances. We have seen what was expected during 2013, which is the pileup of light barrels on the U.S. Gulf Coast, with that LLTI differential narrowing to $1 or $2. So incrementally, from there, I think it probably backs up not being light crude into the Mid-Con and that should be good for our company.

Your next question comes from Jeff Dietert of Simmons.

I think as we look back whenever WTI Brent differentials widened, it seemed the Mid-Continent refineries got that increment on margin. And now you look at WTI brand, it's approaching $12 and yet the Mid-Con 211 is between $14 and $15. So it doesn't look like at the moment that Mid-Con refiners are really getting the benefit of that crude discount. Could you talk about what you think has changed? And is it temporary? Or how do you see that phenomenon?

Looking forward, I think to get that benefit through our crack spread, we're going to have to see a difference between TI and LL because the Gulf Coast producers refiners still have the opportunity to come north with some of the production. And so I think the relevant market going forward is more nearly TI versus LL in terms of driving a wider Mid-Con gas crack in particular. We still stand to benefit probably nicely from the northern barrels, that being Bakken and WCS. But the TI brand is an indicator of Mid-Con profitability on gasoline, probably will be replaced by TILL.

Got you. Secondly, on capital spending, could you give us an indication on 2014, what does cross spending look like? Are there investments in additional cracking or higher distillate yield that might not be coming down the pipe? Or any other capital investments on infrastructure to take advantage of unconventional oil supply grade?

Well, Jeff, this is Dave. We're thinking that we're -- right now, we're looking at about $500 million in terms of capital spending next quarter -- next year. A lot of that is in the Woods Cross Phase 1 project. The other big piece of it is in the El Dorado. We're building a naptha crack, which allows us to increase liquid yield and also take advantage of this upgrade that's there in that area. So those are the 2 main issues that we're spending on. The rest is mostly compliance. As far as additional yields of diesel, we are looking at other ways to shift more gasoline to diesel. Most of that is in the form of the hydrocrackers we have at both Woods Cross and Navajo, and up to some extent, at El Dorado. But those, we don't have any real guidance on those yet.

And, Jeff, for the abundance of clarity here, that does -- that $500 million number includes our tank and turnaround spending. So if you compare that to 2013 spend, basically flat.

Your next question comes from Robert Kessler of Tudor, Pickering, Holt.

I wanted to see if you could comment a little bit about the supply and demand dynamics for the Uintah black wax. I mean, local refining capacity versus transport out of the market by rail. Obviously, local refining capacity expansions improved, let's say, a little bit longer to develop than previously expected, and perhaps, a little more expensive. And then as far as transport by rail, the producers are now sending some to other markets, citing reasonably good demand. I'm sure there's a higher cost to move it out of the local market. But if you've already got established refining capacity in the destination market, to what extent does that threaten your economics at Woods Cross in the long term?

Robert, I think that long-term, that Uintah waxy crude will flow in to the Salt Lake basin. It is a much more attractive market for that barrel than the coastal market based upon transportation. And while that barrel can move to the coasts to be refined, it needs to go towards a refinery that has significant available bottoms processing capacity and conversion capacity. It's not equatable with a North Dakota light or a TI or even an ANS type barrel. So I think that's important to understand. Our job, as I see it, is to ensure that we're putting capital on the ground that makes sense in terms of return, but also provides a market for that crude stream in a way that both we and the producers can benefit from it. And so that's our intention. That's what we're doing in the Phase 1 expansion, Phase 2 expansion will follow, if it's warranted by crude production. I think that we can be more competitive than the coastal markets for that barrel.

Do you have a transportation cost figure in mind in terms of dollars per barrel to get into these alternate markets? That gives you that -- similar to how you mentioned this kind of WTI versus LLS that gives you fundamental buffer, can you do the same thing for the black wax?

When I asked about our transport guys what it cost to move anything by rail, the standard answer is about $8. And then the question is how far. And frankly, the distance is not terribly impactful of transportation cost until it gets to be a longer distance. But if you spend $1 to load it, $1 to unload it and $8 to $10 to get it there, that probably is a good approximation. Recognize that with the waxy crude, you're going to have to steam the rail cars. A little higher-cost rail car. It's a little longer to unload it, but if you pull that number of $10 to $12, that probably reflects, at least, the rail cost and you've got trucking cost from the wellhead to the rail loading station incremental to that.

Okay. Then lastly for me on this, and then I'll leave it alone. Any thoughts about whether or not contracts might develop between, say, the Gulf Coast refineries and the producers that might kind of threaten your ability to contract at a given discount going forward?

The trip to the Gulf Coast is a fairly long trip. And again, importantly, one needs to have available bottoms processing capacity. I think the Gulf Coast plants are generally better configured to run a naturally heavy barrel. The Mayan, WCS, Venezuelan-type crudes, as opposed to a rail barrel of black wax, which would land at the Gulf Coast at approximately, call it, LL flat, not particularly discounted after transportation costs. So that gets me back to the initial point. I believe that we can provide the most competitive market for these barrels in the Salt Lake City refining centers through projects like our expansion, Tesoro as an example as well, our Phase 2 expansion which could follow if the crude is there. So I don't believe, long term, that, that barrel will leave Salt Lake.

Your next question comes from Evan Calio of Morgan Stanley.

My first question is on the fourth quarter capture rate. And Mike, I know you alluded this in your comments. Would you expect a better capture rate in 4Q, with RINs low, or curve flat or rated change on diffs and oil price? Any help on what that funny blue cellular [ph] model might look like in October?

My success in modeling capture rate isn't great, but I think it should be significantly better than third quarter. I mean, directionally, the indicators point there, right? The crack spread for gasoline is not attractive right now in the fourth quarter. And I think that's our weakness, but capture should be reasonably good. And you've got the TI curve pointing back toward contango. That quarter-over-quarter was $1, so negative to overall capture comparing Q2 and Q3, that piece alone. And then you compound that with the higher absolute crude price and fuel oil and asphalt, propane and butane that didn't follow. So those were the drivers, at least, in the third quarter.

Okay. That makes sense. Second, I know we've discussed this before, it's on seasonality. I mean, as you head into 2014, do you expect seasonality to be more -- to be worse versus prior years, given an average weather outlook, given demand trends inventory levels and higher capacity? And I also know you're really in 3 specific markets, right? Rockies, Mid-Con, Southwest. Could you discuss how you think each of these markets clears kind of what the longer-term solution maybe to alleviate the -- some margin pressure during the seasonally lower demand period in the first quarter?

I'm going to start out with a very high level comment, and I'm going to push the rest of it to David. And effectively, last year, we didn't have seasonality, and it was covered. That which we did have was covered up by a very wide Brent TI spread, that provided the majority of our margin. That fundamental is not driving wide gasoline margins for us this winter. So we can expect, I think, some more traditional seasonality. Light product demand isn't terrible. It's hanging in there reasonably well. And I think the economy, as I said in my opening remarks, is doing okay. As to how these markets clear in the 3 different markets, Dave.

Yes, I think some of the steps we'll take from a Mid-Con standpoint is we're planning to store more barrels, we have tankage leads that would allow us to do that during those periods of seasonality and low demand. And we also have ability to make our RBOB now and move it up Explorer to the Chicago, if that RBOBs open. Those are 2 outlets we didn't have in the past. The Southwest is, obviously, Mexico is there and then the rest of it is just kind of don't make it if the economics aren't there. And in the Rockies, we've got the Las Vegas outlet, which we're taking advantage of, and that's an attractive move for us right now from Salt Lake. In fact, we're expanding that rack in Vegas.

Got it. Okay. And lastly for me, I know you were flattish cash in the quarter, was the buyback in any way calibrated to minimize cash use? Or is that just a coincident outcome in this quarter?

No, that's just coincident. Our buyback is value-oriented, and we've stepped it up during the quarter as the share price trade weaker -- traded weaker. And we're not managing to a $2 billion cash balance by any measure.

Your next question comes from Ed Westlake of Credit Suisse.

A good discussion so far. Just some small questions first. WCS, you mentioned hedge losses. Can you just talk a little bit through about your hedging program on WCS? I mean, we were expecting a little bit of a hedge gain, overall, from your product cracks and that caught us a bit by surprise.

Yes, Ed, we did have a gain from hedging our product crack spreads. What got us in this quarter was basically the mark-to-market at the end of the quarter on WCS. I think -- I'm not sure that I have the total volume in front of me. We've got a little better than $20 a day of WCS heads for this year at the -- on a paper basis that would had been mark-to-market. And that was done in the low $20s, call it, $22 or so a barrel. And as Dave mentioned, as we got to the end of September, we started to see that in the low 30s. So you've got to take a mark-to-market of $10-or-so a barrel. Obviously, we'll see most of that flow back through in the fourth quarter. We'll see more hedging loss in the fourth quarter with that now at $40, but running $90 and hedging $20, that's -- we like that direction.

Yes, no, just in terms of delta as against the actual quarter for Q3. That's helpful. And then on the other gross margin, which we simply calculate as your refining gross margin times the refining side, and then your overall group margin. It seemed to compress it a little bit, the delta between those 2 this quarter. I mean anything behind that? It may just be the way we look at things.

No comment. I can't comment on it.

Right, okay. And then, I guess, coming back to the secondary products. It feels like -- I mean, obviously, you've got a, I guess, about a 3% yield of asphalt, 6% LPG, 2% fuel, if I got these numbers right, corporate. And it varies by the different areas. But it feels like those sort of margins could remain under pressure, given we've got loads of LPG coming, crude oil, although, obviously, it got compressed by the change. But crude oil prices are generally high. Can you talk a bit about what -- how quickly you think it takes for the, particularly the asphalt market, maybe fuel oil to get back to a more normal relationship, maybe historically?

Well, Ed, the -- certainly, the fuel oil is affected by the Brent-WTI spread. Historically in our markets, we've benefited from that heavily. As Mike mentioned, the LLS is more pertinent now, and that we've seen that advantage disappear. As far as asphalt, it's really government spending that drives a lot of that demand. That price has been fairly flat for the whole year in terms of whether it's PG-grade or what's the other grades we sell. And just demand is weak. So I don't know that I see a lot of bright stars in either one of those that are going to change.

Right. So that could be a drag on capture and then obviously, the crude changes will be a positive.

Right.

I mean, I think what you'll see is you're going to see asphalt margins weaken, but the heavy barrel, at least in the northern tier, has to accommodate that because refineries are running past their cokers in many instances and producing asphalt. So I think as much as we lose it on the asphalt margin side, we should be making it up on the crude side.

Okay. And then a bigger picture question. You're not the first refiner this reporting season to just flag, with TILLs being relatively narrow these days, that the Gulf Coast refiners were a little bit more advantaged than they've been, say, over the last couple of years, and that's why they're a little bit more competitive, particularly in, to say, the southern Mid-Con, maybe Cushing, maybe even into the Southwest. How -- can you talk about the structural competitive advantages that you still feel those particular refineries have if there's sort of a scenario with the Gulf being more competitive than it's been persist, so given the fact we've got a lot of steel down there to produce product?

Yes. First off, there's a lot of very confident refining capacity on the U.S. Gulf Coast. You guys know that. But they have available to them increasing numbers and they're taking advantage of it, export alternatives. And I think that, that is the big fundamental driver. They also have the alternative, as you're suggesting, of sending product north. And there's a cost associated with that. That might be $0.04, $0.05 a gallon to get up into our markets. They have incrementally higher crude costs because the cost of transporting these barrels down to the Gulf Coast, particularly the heavy barrels, is higher. So effectively, it's the crude transportation cost products back into our markets and measuring that against the relative advantage of exporting product to the obvious candidates of Mexico, South America, West Africa and ultimately, Europe. And I think when we try to paint a picture of how this market is going to evolve through time, you really have to be looking at greater exports because while we're competing on a more equal footing with the Gulf Coast refiners now, they have a little better yield, little lower cost structure. We have the transportation advantage, the entire complex of Mid-Con plus Gulf Coast refiners are probably $5, maybe $7 advantaged versus Northwest Europe. And I think that's the major fundamental that's going to drive changes in the industry structure over the next couple of years.

And you got plenty of cash on the balance sheet to survive if there's any sort of value of debt as those changes occur.

Your next question comes from Roger Read of Wells Fargo.

Well, I guess, most of it has been hit. But I'll kind of flip back to one of our, I want to call it, an old friend, but certainly, as nemesis of some sort, the RINs market. Can you give us an idea of maybe some of the impact that had in terms of your capture rates in the third quarter and then maybe how we should think about it here in the fourth quarter, with the cost down fairly significantly. And then any thoughts you might be willing to share about what the government, through the EPA next year, may or may not do?

Oh, you're trying to get our blood pressure up, and it's still pretty early in the morning. I think the RINs cost is what, $0.20 a share to quarterly earnings. So that's of a 61% potential result, we gave 20% away on account of this. Quarter-over-quarter, the situation will improve. Certainly, on a spot basis, that's the case. In order to anticipate the RIN obligation and make sure that we were compliant, I think we got a little ahead of our required volumes in the third quarter, and so we have some higher average cost RINs that will flow through the P&L than the spot market indicates. But the greater issue is just probably not fourth quarter capture as it relates to RINs, but rather, what's going to unfold going forward, is this a $1 a RIN, $1.50 a RIN, or $0.10 a RIN type of market? And I think the answer to that is -- frankly, I thought I had it fairly well dialed in a quarter ago, and then the government went on leave and the urgency hasn't been picked up since they came back into session. It's very hard to say. The EPA made a strong signal of putting ethanol RIN compliance or ethanol volume blending into the E10 range, recognizing the blend wall and that had a very immediate impact of taking, what, 75% of the value away from the RIN. Ultimately, if the EPA honors that physical limit, which we believe is a physical limit, the RIN should trade roughly in -- compliant in a transaction cost mode. It may be a $0.05 or $0.10 because that's what's really involved in blending one's tracking. There's typically a blended center for the ethanol, which might be $0.10 a gallon, $0.05 a gallon, something like that, with ethanol pricing cheaper than unleaded regular. So the blender still has an incentive beyond this capture of the RIN. And pointing forward, I guess, I have to think that the government is going to do not so much the right thing, but the practical thing because to do otherwise would really distort the gasoline markets. And I don't think that's good for the country or good for their elections.

Okay. And then following up on one earlier question about repurchasing shares, and obviously, a tougher cash flow quarter here, this last one. What is the basic way you approach, or the board likes to approach, looking at share repurchases versus dividend? I mean, you've maintained a fairly significant special dividend here. Obviously, special is special. And I'm just trying to think about if you're laying this out, which is more important? How do you think about special dividend versus share repurchases?

Roger, I think we've said that the regular dividend is one that we would plan to grow steadily over time. It's been a couple of quarters since we've seen any growth, and I'm not sure this current environment is one that you would expect much growth on a regular dividend. We still got, certainly, a special dividend out there that we said is sustainable, we believe, through the cycle. And we've still got a $2 billion cash balance. And in terms of share repurchase, that's one that we've said we'll use opportunistically. We've done that some. We've seen incredible volatility in our share price, with maybe a low $39 for a day or 2 in the third quarter. Now back to sort of mid-$46s. That's not terribly down off of the very highs that we saw at the peak of the Brent-TI spreads. So without giving you too much indication of where we see necessary value and we would step on the gas in buying back shares, more aggressive in the low or low 40s, high 30s, less aggressive in the high 40s.

Your next question comes from Matthew Blair of Macquarie.

I don't know if I missed this, but is there any update on the potential rail terminal in the Permian? We've seen some competing projects move in and just curious where you stand here.

We're still looking at it, but we're not planning to do anything at this point. I mean, the spreads are all over the place. And it's very difficult unless you can do unit trains, in which we could do. But we're having a hard time finding customers that are really interested in it.

That Permian barrel is substantially less stranded than it was, say, 6 to 9 months ago. And the delta being newly completed and newly announced, pipeline transportation capacity to the Gulf Coast. I think until the Gulf Coast starts pushing back on sweet crude, you're not going to have rail economics to take that barrel to the West Coast. And rail will serve, at least in my opinion, to clear the Bakken and clear the Hardisty excess. In each case, we're interested in looking those to us seem more profitable and more likely than rail out of the Permian, specifically to the West Coast.

Okay, wasn't that also going to be an unloading facility for potentially heavy Canadian barrels at your Navajo refinery?

Yes, potentially, yes. We're still evaluating that.

So the internal question there is simply, how much value do you put on that piece of project versus the other? And can you justify it based on bringing bitumen or dry bitumen into that Navajo refinery? Without perspective volumes, at least in the near-term, out in terms of light crude to the West Coast, it makes it tougher.

And if you were going to do it just that, you might do it in a different location.

Right, right. Okay. Then on UNEV, any indication of UNEV volumes in the fourth quarter? In October, we saw Las Vegas gasoline traded a pretty substantial premium to Salt Lake City. So just curious if your Woods Cross refinery was able to send some more products down to Las Vegas.

I don't have those volumes with us, but we did move quite a bit of barrel. I mean we're contracted up to about 5,000 barrels a day there, pretty routinely. But we can swing that to 10,000 fairly, fairly easily. And we have done that. I don't have those volumes with me.

Recently, we've been at the higher end of that range. I don't have today's volumes.

I think I remember hearing as we move towards winter, there was certainly an arbitrage that was open and we were shipping our sort of max volume.

Okay. And then, finally, so I think you've said in the past that your RIN exposure is approximately 50% of your total production. And thinking about this level a few years down the road, I think you have some pretty large offtake agreements expiring in 2014 at each of your Mid-Con refineries. How should we think about your overall exposure? Would you expect to renew these offtake agreements on pretty much the same terms? Or would you think there would be a material reduction in your overall RIN exposure if you were to renew these agreements?

The RIN is part of the conversation with any bulk sale. And so we're not going to broadcast our conversations with our major customers. But I'll promise you that, that is, at least in the first or second bullet point of any term sheet, because it's material and it's important.

Your next question comes from Doug Leggate of Bank of America.

Okay, [indiscernible] [Technical Difficulty] Do you have a preliminary 2014 budget? Hello?

[Operator Instructions] And Paul, go ahead with your questions.

2014, Doug, do you have a preliminary budget number? And also, you gave the gasoline diesel in new margins for October. Do you have the number for the third quarter?

Paul, what budget number were you looking for, for 2014, just capital?

Yes.

What Dave said was $500 million, that includes tanks and turnarounds.

And turnaround is what, $100 million?

That's about $100 million for that piece, yes. And crack spreads by region for the third quarter, Paul, we're -- okay, here we go Rockies gasoline, $17; Rockies diesel, $26; Mid-Con gasoline, $15; Mid-Con diesel $23; Mid-Con lubes was $58; Southwest gasoline, $13.50; Southwest diesel, $22.

[Operator Instructions] And we have no further questions at this time. I will hand the floor back over to management for any closing remarks.

Okay, Christie, thank you. Thanks for bearing with us, everybody. These conference calls are like magic until they're not. But we appreciate your participation this morning and look forward to talking with you either on telephone or at the next call. Thanks a lot.

Thank you. This does conclude today's conference call. You may now disconnect.