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Executives

Stacey Hudson

Paul Eisman - Chief Executive Officer and President

Shai Even - Chief Financial Officer, Chief Accounting Officer and Senior Vice President

Kyle C. McKeen - Chief Executive Officer of Alon Brands and President of Alon Brands

Analysts

Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Roger D. Read - Wells Fargo Securities, LLC, Research Division

Paul Y. Cheng - Barclays Capital, Research Division

Rakesh Advani - Crédit Suisse AG, Research Division

Matthew Blair - Macquarie Research

Matthew Blair

Alon USA Energy (ALJ) Q3 2013 Earnings Call November 8, 2013 11:30 AM ET

Operator

Good day, ladies and gentlemen, thank you for standing by. Welcome to the Alon USA Energy Third Quarter Earnings Conference Call. [Operator Instructions] This conference is being recorded today, November 8, 2013. I would now like to turn the conference over to Ms. Stacey Hudson, Investor Relations Manager. Please go ahead, ma'am.

Stacey Hudson

Thank you, Camille. Good morning, everyone, and welcome to Alon USA Energy Third Quarter 2013 Earnings Conference Call. With me are Paul Eisman, President and Chief Executive Officer; Shai Even, Chief Financial Officer; along with other members of our senior management team.

During the course of this call, we may make forward-looking statements based on our current expectation. These forward-looking statements are subject to a number of significant risks and uncertainties and our actual results may differ materially. For a discussion of factors that could affect our future financial results and businesses, please refer to the disclosure and risk factors disclosed by the company from time to time in its filings with the SEC. Furthermore, please also refer to the statement regarding forward-looking statements incorporated in our news release issued yesterday. And note that the contents of our conference call today are covered by these statements.

On this call, we will discuss non-GAAP financial measures. You can find the reconciliation of these non-GAAP financial measures to GAAP in our financial release, which is posted on our website. Finally, please be aware that all our statements are made as of today, November 8, 2013, based on information available to us as of today. And except as required by law, we assume no obligation to update any such statement. With that, I'll turn the call over to Paul.

Paul Eisman

Thank you, Stacey, and good morning, everyone. The third quarter was obviously a tough one for the industry as it was for Alon USA. Crude oil differentials contracted significantly. The crude market was in backwardation, and we saw seasonal pressure on gasoline margins.

In addition, our results were impacted by unscheduled downtime in Big Spring. As a result, we recorded a net loss in the third quarter of $28.7 million or $0.47 per share as compared to a profit of $0.76 per share in the same quarter last year. The FCC outage that occurred late in the quarter impacted earnings in the quarter by approximately $0.10 per share. For the first 9 months, we reported net income available to stockholders of $0.56 per share compared to $1.01 per share in the same period last year.

We believe that margins reached a bottom late in the third quarter, and we've seen improvement as we enter the fourth. With continuing increases in U.S. light oil production, domestic light oil refiners will continue to have significant crude and operating cost advantages over offshore light crude refiners. The recent widening of the brand differentials at both LLS and WTI provides evidence that the benefit of increasing domestic light oil production is also expanding to the Gulf Coast light oil refiners. And we will benefit this -- benefit from this at both Big Spring and Krotz Springs.

Finally, we believe the crack spreads experienced during the third quarter are unsustainable. European and other refiners running Brent-priced crudes are suffering with exceptionally poor margins. We would expect margins to improve if worldwide product demand necessitates current capacities, or these refiners will eventually curtail or shut down their operations. In either case, this bodes well for margins at our refineries.

Our West Texas refining and marketing system faced operating issues this quarter as we had unplanned outages in our FCC unit. As a result, our throughput during the quarter was about 6,000 barrels per day below our plan. We estimate that these unplanned outages impacted earnings by $12 million during the third quarter. As we have already announced, we are planning to take Big Spring into its full plant turnaround during the first quarter of next year.

Third quarter results were impacted by the contraction in crude oil differentials. The LLS, WTI Cushing differential dropped from $15.07 per barrel in the second quarter, $6.60 per barrel in the third. In addition, West Texas Sour priced in Midland traded its parity with WTI Cushing. Given transportation cost to Cushing and the product value difference between sweet and sour crudes, this is unsustainable. Fortunately, this differential has returned to healthy levels, thus far, in the fourth quarter.

A slightly different way to look at the WTS-WTI differential is that sweet crudes were discounted during the third quarter beyond their yield value. That being the case, we took advantage of the situation by using our crude slate flexibility to process record levels of sweet crude during the quarter. Either way, Big Spring is ideally situated to benefit from ongoing crude production increases in the Permian Basin.

Margin captured Big Spring during the quarter was impacted by the yield impact of the FCC outage, backwardation in the crude oil market, unusually poor discounts for West Texas Sour crude relative to the WTI benchmark. And weak pricing for secondary products, specifically, LPG and asphalt. In addition, our reported margin in the quarter includes approximately $1.2 million of costs associated with our RINs obligation.

Direct operating expenses during the quarter was $4.53 per barrel, which was higher than our expectation. This was due to higher costs associated with repairs completed during the quarter along with the impact of lower throughput. This compares to $3.92 per barrel in the same quarter last year. We continue to work on self-help initiatives that Big Spring Refinery focused on improving the gross margin at the facility. We are planning to make investments during the upcoming turnaround to improve additional recovery at the plant by about 2,000 barrels per day while also improving the energy efficiency of the refinery. The cost of this project is estimated at $23 million and generate $11 million to $12 million per year of increased EBITDA.

We are focused primarily on projects to improve our gross margin or reduce our expenses that these benefits are largely independent under refining margin environment. We've also identified additional low-cost projects, improve LPG recovery, increased aromatics recovery and produce chemical-grade propylene. All of these projects have paid back in less than 2 years, are focused on increasing margin capture and can be completed over the next couple years. However, given our strategically long-term advantaged access to West Texas crude oil, we are also looking at options to expand Big Spring.

In our wholesale marketing business, we continue to enjoy significant increases in branded sales. Year-to-date, branded sales are up by 14% over the same period last year, and we accomplished this despite having 25 pure branded sites at the end of the quarter versus the same time last year. By upgrading the quality of our branded sites, replacing lower volume sites with higher volume sites, we achieved a 22% increase in per store fuel sales versus the same period last year.

Our retail marketing business continues to perform well with record fuel sales during the quarter that were up 12% over the same period last year. Fuel margins were good at $0.19 per gallon. Merchandise sales were up 2% versus the same quarter last year with improved merchandise margins up 32.5%. These improved results come despite 2 peers stores operating this year as compared to last. We are continuing our remodel program and are looking at expanding our store count through both new builds and acquisition. We are pleased with the results we've gotten from this business and are looking for opportunities to expand.

The Krotz Springs refinery had a very good operating quarter, averaging just over 69,000 barrels per day at total charge. Of this amount, almost 33,000 barrels per day of this was Midland-priced WTI. The profitability of these barrels was impacted by the drop in the LLS WTI differential from the previously mentioned $15.07 to $6.60 per barrel in the third quarter. While WTI, Krotz Springs is still profitable at these levels, the economic benefit of processing WTI was greatly reduced during the quarter. Direct operating expenses averaged $3.91 per barrel, which was in line with our expectations.

As I mentioned earlier, we are encouraged by the developing Gulf Coast discount for light crude oil, the large differentials that we've seen in October are partially driven by turnaround activity in the region. However, we believe that the evidence points to continuing excess supply of light crude oil in the Gulf Coast, which will be -- Gulf Coast which will be supportive of Krotz Springs profitability.

As at Big Spring, we are developing opportunities to make moderate investments focused on improving the gross margin at the facility. We can improve additional recovery, improve LPG price realization and increase gasoline values by producing CARBOB gasoline to projects to generate excellent returns.

In California, we continue to work to get our permit to install a rail and roading facility and make modifications at Bakersfield to run light crude. Currently, we estimate getting these permits by the end of the first quarter next year. As we assess our development alternatives for refining at Bakersfield, we're also very optimistic about opportunities to develop a significant logistics business in California. We've already developed commercial arrangements for terminaling services out of our Long Beach and Willbridge terminals and are in discussions regarding terminaling services at Paramount and Bakersfield.

The Bakersfield unit train facilities, especially exciting as this location is currently advantaged versus other options. And we are providing for the capability to handle heavy oils at this facility. With the difficulty in getting approval for pipelines to move heavy Canadian crude, we feel that the rail option in California makes sense. We see a path forward to develop a West Coast Logistics business within the next few years that generate $40 million to $60 million per year of EBITDA, which would allow us to eventually drop this down into logistics MLP.

In our ethanol business, sales were significantly higher than the second quarter, but still 16% lower than the same quarter last year. One of the case of this business is sales volume, and market demand for asphalt is still negatively impacted by local and state budget shortfalls. Our terminaling cost are mostly independent in sales volume, and incremental gross margin tends to go directly to the bottom line. As the demand for asphalt picks up, this should translate very quickly to improved profitability in this business. On positive side, we're encouraged as margins on a cash basis in this business improved to almost $55 per ton as compared to $37 per ton in the third quarter of 2012.

Throughput guidance for the fourth quarter is 72,000 barrels per day at both Big Spring and Krotz Springs. As mentioned, we continue to prepare for the plant-wide turnaround in Big Spring in the first quarter of 2014. Our current estimate of throughput for the first quarter at Big Spring is 55,000 barrels per day.

Finally, during the third quarter, we closed on a very successful offering of $150 million of 3% senior unsecured convertible notes due in 2018 and also entered into a call overlay transaction, which effectively increases the conversion price to $20.09 a share.

Alon USA Energy, at its sole discretion, can settle conversions in cash, shares or any combination of cash and shares. In October, we redeemed $140 million of the 13.5% outstanding senior secured notes due in 2014 issued by Alon Refining Krotz Springs, a wholly owned subsidiary of Alon USA Energy. The estimated annual savings of cash interest expense is approximately $14.4 million.

With that, we are glad to answer your questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question is from the line of Robert Kessler with Tudor, Pickering and Holt.

Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

I've got a question about your -- well the ALDW financing or funding and debt level sort of thresholds. When I look at the MLB financials, distributable cash flow was a negative $18 million for the quarter. Debt increased by 1/3. Net debt to cap is now basically 2/3. And when I look at debt-to-EBITDA, it's at 1x trailing 12 months, that's at the high end of your guidance. In the last 6 months, it would be about 2.2x, which is seemingly at the upper limits. So now you've got full plant turnaround in the first quarter, you've got more CapEx, it sounds like, coming. So can you walk me through your financing options and borrowing capacity at the MLB level and possibility that the parent provides some kind of additional funding into the MLB?

Shai Even

Yes, I think that we have -- the end of the quarter, we still have about $60 million of availability under the state partners' revolver. We have other financing alternatives, opportunities that we are not ready to discuss today, but we're also looking at a time to support its [indiscernible] some of the profit improvement project that we discussed -- before we discuss the data recovery project, which is kind of the project that we're looking for the parent to potentially to support the project.

Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Can you explain to me a little bit more about how the parent would support the project, assuming you're to increase your net equity holdings in the MLP, is that how that would happen, or is some kind drop-down in the future date, you'd hold back somehow that portion of the plant? Just a little bit more in the logistics of how that parent financing and the growth would work.

Shai Even

We have not finalized yet the way that will be done, but it could be down as a drop-down. It could be down as some kind of a long-term arrangement. There's nothing to lose -- existing. But we're looking at all option.

Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

And how big is the total capital you'd be considering funding by the parent on behalf of the MLP?

Shai Even

It would be through a late arrangement or through a drop-down.

Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

I'm sorry, the total dollar amount potentially under consideration.

Shai Even

No. When we talked about the data recovery project, for example, the cost is about $23 million.

Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

All right. And then, I guess, just a quick question on the California permits. It looks like it slipped a little bit into the fourth quarter as opposed to year end. Any incremental color on that?

Paul Eisman

Yes, it did slip a little bit, and we're continuing to work the permit and what we are confident we're going to get it. I mean it's -- California's a challenge, it always is a challenge. In Kern County where we're at, we feel like we've got the best environment to get a permit of any project out there, and it's still a challenge. So we are working hard to accelerate this. As I mentioned, we have -- our projections are that it slipped 2 or 3 months into the end of the first quarter.

Operator

Our next question is from the line of Roger Read with Wells Fargo.

Roger D. Read - Wells Fargo Securities, LLC, Research Division

Just on a -- maybe a little bit on Krotz Springs. Your opening comments about being able to get consistent crude discounts there. What are you looking for, what do you want to see happen, what do you need to see happen? I mean is it something like the oversupply along the Texas Coast? Is it the opening of the -- I'd say the opening -- but the full service of the Ho-Ho [ph] line? Is there something we should be looking for as catalyst that would help us understand when Krotz Springs should be able to get a consistent discount there?

Paul Eisman

Yes, I mean, we think this market is developing. And what we've seen is, obviously, over the last few years, we've had a significant line of crude oil in the Mid-Continent. And the pipelines have come into service. And so we -- if you looked at inventory of light crude in the Gulf Coast, you've seen it come up consistently. Eagle Ford continues to increase production. West Texas continues to increase production. You see -- you have crude oil from the Bakken coming down. And we think that, that's leading to a significant blood [ph] of light crude oil in the Gulf Coast. And as you totally eliminate the import of light crudes into the Mid-Continent, we think that eventually you start getting to the point where this light crude oil supply is looking for places to go. Well, as others have said, I'm sure, we look at the future where this crude oil makes it either to Eastern Canada or to the Eastern Seaboard of the U.S. at a cost that leads to a discount on the Gulf Coast. We think that, that just started. We had significant -- at the end October, we saw differentials of $10 a barrel LLS versus WTI Cushing. Obviously, that was bigger than we'd expect at this point given the amount of turnaround -- and caused by the amount of turnaround activity in the Louisiana area. Brent to LLS -- and I'm sorry, I mean [indiscernible] LLS to WTI as Brent to LLS. And so that discount is going to benefit us, we think, in the fourth quarter. We just have to see how it turns out for the remaining time, but we are optimistic that when we look at the balances that you're going to see this -- develop and continue to exist on the Gulf Coast.

Roger D. Read - Wells Fargo Securities, LLC, Research Division

Okay. And along those lines, in the third quarter maybe as things are transitioning here in the fourth quarter and into the first of the year, rail deliveries, barge deliveries into Krotz Springs, I mean, what is the way you're getting some of the discounted crudes in there at this point? And what are some -- what's kind of the right volume to think about as opposed to more of a local pipeline delivery?

Shai Even

We do barge crude in the Krotz Springs. We bring crude from West Texas as part of that operation, so we're bringing over 30,000 barrels a day of crude in the Upper [ph} West Texas to Krotz Springs. That is throughout -- the barge barrels we buy on the Texas Gulf Coast have both quality and price advantages to them. And additionally, we do have the ability to bring a certain amount of rail crude into the refinery as these differential transitioned a lot in the third quarter. We did not do a lot of that in the third quarter. It looked to be more of that as this stabilizes again.

Paul Eisman

And this kind of LLS that comes up is delivered by pipeline.

Roger D. Read - Wells Fargo Securities, LLC, Research Division

Okay. And then your rail delivery, is that of a unit train variety, or is it still mostly a manifest?

Paul Eisman

No, it's today is a manifest facility. We received about 1,000 barrels per day in the third quarter. As these differentials contracted, it became less attractive to do this in the third quarter. It kind of blown back out, so that's why we're looking at that. The capacity of this, of this facility is easily 3,000 barrels per day today. And if we can work with the railroad, we think it easily gets up to 6,000 barrels per day. What we're pushing to have is flexibility in our crude oil system. We can get LLS, we can get locally produced discounted crudes. We can get rail crude, we can get barge crude. So we like the flexibility that we've developed at Krotz Springs to try to take advantage of any dislocation in the crude market.

Roger D. Read - Wells Fargo Securities, LLC, Research Division

Okay. And the last question I had, reactivating California, if you can get discounted crudes out there, what's -- any thoughts on the timing of something like that?

Paul Eisman

No, we're looking at that, and we've not established timing to do that. We -- if we get the permits at the end of the first quarter, we could do that. We could potentially start as early 2015, but we've not made the decision to do that at this point.

Operator

Our next question is from the line of Paul Cheng with Barclays.

Paul Y. Cheng - Barclays Capital, Research Division

A number of quick questions. California, can you tell us that what is the timing -- what is the cost? I think, historically, you talk about $10 million, but it does look like the -- there's some unidentified cost is higher. So you said the California cost is higher or the terminal revenue you received there is much lower this quarter?

Paul Eisman

Yes. Our costs were higher in the third quarter relative to other quarters. There's a number of reasons for that. There is in the numbers you see, there is a LIFO.

Shai Even

Yes, we have about $3 million LIFO effect. We have some other also -- what we delivered in nonrecurring, we didn't identify them as nonrecurring in the report because some of them are individual basis, they are small. But they're not going to get the additional $3 million of nonrecurring cost during the quarter on top of the $3 million LIFO [indiscernible].

Paul Eisman

Yes, in addition to that, we're having to invest to lower our cost. I'll give an example of that is we have some flare systems there that kind of breathe in and out on the tank inventory. So what happens is the tanks heat up during the day, we -- their blanketed by fuel gas. And that fuel gas goes to flare, and then we've got to replenish that at night. What we're doing is cleaning some of those tanks, taking the inventory out, we can remove the blanketing and reduce our cost. Well, obviously -- in those cases like that, it takes -- you've got to invest some money to reduce your cost. And so we're focused on that, and we expect our cost to be -- our shutdown cost to be significantly lower in 2014 versus what it is in 2013.

Paul Y. Cheng - Barclays Capital, Research Division

But Paul, should we assume this higher level of expense continue in the fourth quarter and then in next year? Then we drop off, or that you already spend the money, so fourth quarter will return back more to normal?

Paul Eisman

Yes, I think fourth quarter will be in the same range as the third quarter, maybe a little bit lower. Again, we've got to continue to make those investments to lower our cost, but we do think that we'll see lower-cost operation beginning first quarter of 2014.

Paul Y. Cheng - Barclays Capital, Research Division

And what is your terminal fee that you received in the fourth -- in the third quarter?

Shai Even

During the third quarter, we received about $2 million of terminaling fee included in refining, an additional $5 million that's included in that. But just like to add that we had about $6 million of total cost in the first quarter from the West Coast operation that we don't believe we will carry again in the fourth quarter.

Paul Y. Cheng - Barclays Capital, Research Division

I see. Paul, let's assume that you get the permit to well the Permian oil or that the Bakken oil into Bakersfield. I think this is still the assumption that you're going to run [indiscernible] oil. What is the land ties discount versus ANS you need in order for that trend to work?

Paul Eisman

I'm not sure at this point I have that number for you. I mean we can follow-up, but we always kind of model this assuming that we could deliver at sort of an ANS price or maybe a little bit below an ANS price. And a lot of the benefit here is generated, not by discounted crude, but by yield improvements. What we saw in the past is running the crudes we were running in California, we were producing a lot of asphalt. And we were competing with that asphalt with refiners in Mid-Continent that did have discounted crude. Well, so we were producing 40% asphalt. With the light crude, obviously, we produced a whole lot less. So it was really driven as much by yield improvement as it was driven by any sort of significant crude discounts.

Paul Y. Cheng - Barclays Capital, Research Division

And then when we're looking at your Krotz Springs, when you bring in the Midland crew, what is the differential between the Midland WTI? And I think that you're running primarily on, at least, there's some years, HLS; and some years, LLS. What's the price differential between Midland, and let's say, LLS? At what point that it is no longer economic for you to bring in the Midland crew?

Shai Even

I think our variable costs are -- we look at this at the $5 per barrel level, the total cost of bringing it in. And that's -- at that level, we cover all of the cost for doing that, fixed and variable.

Paul Y. Cheng - Barclays Capital, Research Division

So in the third quarter, it's actually quite marginal in terms of the economic that you'll do anything -- because in the third quarter between the midline crew and LLS, it's probably not much better than $4, $5.

Shai Even

It was somewhat better, but you're right. It was certainly less than a contribution than in prior quarters.

Paul Y. Cheng - Barclays Capital, Research Division

Okay. Shai, do you have a market [indiscernible] in your inventory in excess of both that you can share?

Shai Even

Yes, that was about $70 million market [indiscernible] book inventory....

Paul Y. Cheng - Barclays Capital, Research Division

$17 million?

Shai Even

$78 million, 7 8 million.

Paul Y. Cheng - Barclays Capital, Research Division

And in the part, if you don't mind, you can put it into your press release, at least, I will appreciate. On the crude purchase, Paul, when you purchase, let's say LLS or HLS or WTI Midland or WTS, are they -- those that is being conducted in spot basis, or that is a 1-month lack? And also, I'm guessing 100% is under CMA also.

Paul Eisman

We purchased the bulk of our crude under what I think you would characterize as a normal CMA basis. So our differentials for November were really established September 25 to October 25. Does that help? [indiscernible] November current WTI pricing.

Paul Y. Cheng - Barclays Capital, Research Division

And that is a price for both the LLS, WTI and WTS both? So essentially everything that you buy is under the CMA [indiscernible].

Paul Eisman

.

Virtually all of it.

Paul Y. Cheng - Barclays Capital, Research Division

And then the $12 million on the FCC outage cost you estimate, do have a split between what's the actual expense and what is the estimate opportunity cost?

Shai Even

We have about $4 million of opportunity cost and $8 million of actual cost.

Paul Y. Cheng - Barclays Capital, Research Division

And the actual cost side where did you show that in your P&L statement, is it under the operating costs or under what?

Shai Even

About -- out of the $8 million, about 50% of that is out of the gross margin, so it's increased the cost of goods sold by selling access code and telling VGO. And half of that is increased in direct operating expense.

Paul Y. Cheng - Barclays Capital, Research Division

And then in Big Spring, when Paul, you're talking about a potential expansion. I think in the past, that's always talking about to expand potentially to 70,000, 75,000 -- to 75,000 barrel per day from currently 70,000. Are you talking about that, or are talking even beyond that?

Paul Eisman

Well, we're looking at all options, Paul. I mean, We are -- obviously, what we'll do is we'll look at different tiers of expansion depending on what's the next investments are required to get there. So you might imagine you're picking your numbers at 75,000. That may not take a whole lot of investment. It might make a heck of a lot of sense. But then the next investment depending on what you have to do to get there, you may or may not have a good return. So we're looking at both relatively minor incremental expansions like the one you mentioned. But we're also looking at perhaps going farther than that. Understanding that, that's still required, not only investments at the refinery, but investments in our distribution system to make sure we can get incremental product into our margin.

Paul Y. Cheng - Barclays Capital, Research Division

Just a final one for me. Do you have a rough preliminary estimate for your budget for next year? And also, you're going to expand to 75,000 barrels per day. What does the CapEx maybe look like?

Paul Eisman

Yes, Paul, we haven't been through our board meetings yet. I haven't got a budget approved for next year and also are working on the capital cost for the expansion projects. So I really don't have those numbers for you right now.

Operator

Our next question is from the line of Rakesh Advani with Credit Suisse.

Rakesh Advani - Crédit Suisse AG, Research Division

Just had a quick follow-up from the aromatics questions I'd asked earlier. I think I'm just looking at your bar cap slides, you had mentioned that you were in the implementation phase of that project. So I'm just wondering you'd said that you didn't have approvals from the board regarding that. So I was just wondering if this is sort of confused over there?

Paul Eisman

Sorry, which project are you talking about?

Rakesh Advani - Crédit Suisse AG, Research Division

When I asked earlier regarding the aromatics, you were looking for annually EBITDA contribution around $14 million, right? And...

Paul Eisman

That's different. What that is, is that's not really a capital project. That's a project that -- we have the capacity today to produce additional aromatic solvents and additional tie wing that we feel that we can move into the market. And we've estimated the value of that at about $14 million on an EBITDA basis. And so we are working in that direction and moving it up. Our aromatics production and sales in the third quarter were somewhat impacted by the average that we have in lower crude rates, but we continue to be optimistic that we can achieve the more $14 million increase in EBITDA through the increased marketing of these aromatic solvents. So that's not really a capital project, and I'll differentiate that from my comments in the -- earlier. Because we talked about the aromatic expansion projects, that's a project to do more of that. And that's not yet been approved by the Board of Directors.

Rakesh Advani - Crédit Suisse AG, Research Division

So then the $14 million, that's going to -- what is the timeframe on that?

Paul Eisman

What's happened it's a matter of gearing up, so I think that as you get through 2014, you'll see that year up. I don't know how quickly, but during the year, we expect to get that next year.

Rakesh Advani - Crédit Suisse AG, Research Division

And the split uplift [ph] that you get of 2,000 barrels a day, I think previously you had mentioned that it could possibly [ph] be tying in as well with the 3,000 barrel a day CDU expansion. So there's no impact over there then, right, if you're not doing the CDU expansion along with the turnaround?

Paul Eisman

Yes, we're -- when we talked earlier, we talked about this project, including impacting both additional recoveries, energy efficiency. And we talked about the crude expansion. We are -- we ran into some equipment delivery issues. We're still expecting that this project will support increased throughput at the refinery, but that may occur later in 2014 rather than early in the year.

Rakesh Advani - Crédit Suisse AG, Research Division

And just on Krotz Springs, does that serve like a local market, or do you export products from there or...

Paul Eisman

No, barely, we don't. We do not export. Most of the products that we make or a lot of the product we make goes directly to the [indiscernible] pipeline. We do ship the splits out. We've shipped some product out by barge. Typically though, we don't export.

Operator

Our next question is from the line of Matthew Blair with Macquarie.

Matthew Blair - Macquarie Research

Just wanted to follow-up on these record sweet crude runs at the Big Spring Refinery. It looks like it was 40% of your crude slate in the quarter. Depending on where differentials are, is that a good number to use going forward, or did the FCC outage maybe help you run a higher percentage of sweet?

Paul Eisman

No, I think we're working on increasing this irrespective of the outage. I think in October, we ran a pretty good race. We ran about 40,000 barrels per day of sweet crude oil in the month. So it's not just the fact we ran fewer barrels. It's a fact that we're optimizing the facility. I would tell you a big part of that, frankly, has been a good story in terms of the increased production of crude oil in the local area and our ability to pick crude oils that don't have a lot of light ends to them. I mean our limit to running WTI at that refinery is the amount of light ends that are produced,it tends to bottleneck at the top of the crude tower when the crude's too light. But by being able to take advantage of the local production and pick which fields we want to purchase from, we've been able to take -- to increase in that WTI we can run. I would tell you that in the -- today, our optimization has changed because you had the differential between WTI and WTS expand and so today, we're probably moving the other way a little bit. But the key, I think, to refining profitability, in general, is the ability to be flexible. And so what I've been very happy with is that we demonstrated increased flexibility on the crude Slate at Big Spring.

Matthew Blair - Macquarie Research

Okay. And then with Bakersfield, it might be too early for this, but could you talk about what that refinery would look like once you brought it up? I think there's a coker there. So would you run a mix of heavy and light crude, or would this really just be a Bakken-like crude refinery? And also, what's the condition of the crude unit? Could you run it at the 70,000 barrel per day capacity? Any comments there would be helpful.

Paul Eisman

Yes, we've obviously looked at the condition of the crude unit. We do feel we can run between 60,000 and 70,000 barrels of light crude in that crude tower and in that refinery. It does have a coker, but what it doesn't have is sufficient treating to treat many of the products that come out of the coker. That's one of the problems the previous owner had with that facility. And ended up putting a lot of low value products into the market. So our plan is to run light crudes and not run the coker. But we're also in the asphalt market, so we've got a market for the heavy ends rather than put it into the coker. And if we don't run the coker, we've got sufficient hydro-processing capacity, so that essentially, we can move everything into finished product.

Matthew Blair - Macquarie Research

Great. And then with your retail system, it looks like you guys have done a really good job of increasing the volumes per station. They've been marching up pretty steadily over the past couple of years. Could you talk about, I guess, how are you doing this? Are you adding pumps to existing stores, or is this just from a better economic growth in your region? What's going on here?

Paul Eisman

I'll let Kyle answer that. He was happy to hear you say that.

Kyle C. McKeen

Yes, it's really been a Operational Excellence Program that we put in place called Clean Team. And it's just focusing on execution and customer service. So we have added dispensers, and we have added some modifications to the fuel items. But it's mostly been just operational changes.

Matthew Blair

Great, great. And then finally, are there any product crack hedges for 2014?

Shai Even

Yes, we do have right now in place. We have 16,000 barrels a day of total distillate fracs against LLS. 10 of that is [indiscernible] and 6 of that is [indiscernible].

Matthew Blair

Okay. And what's the strike?

Shai Even

Strike is about on average, $12 to $20.

Matthew Blair

$20?

Shai Even

About $20, yes.

Operator

Ladies and gentlemen, that does conclude the question-and-answer session for today. I'd now like to turn the call back over to Mr. Eisman for closing remarks.

Paul Eisman

Okay. Well, thank you very much, all of you for sitting in. Thanks for your interest in the company. We look forward to talking to you about a better quarter next time. Thank you very much.

Operator

Ladies and gentlemen, that does conclude our conference call for today. Thank you for your participation. You may now disconnect.

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