Welcome to the Valero Energy Corporation Report Second Quarter 2012 Earnings Conference Call. My name is Trish, and I will be your operator for today's call. At this time, all participants are in a listen-only mode. Later, we will conduct a question and answer session. Please note that this conference is being recorded. I would now like to turn the call over to Ashley Smith. Ashley, please go ahead.
Hey, thank you, Trish, and good morning and welcome to our earnings call. With me today are Bill Klesse, our Chairman and CEO, Mike Ciskowski, our CFO, Joe Gorder, Chief Operating Officer, Kim Bowers, our Executive Vice President and General Counsel, and several other members of our senior management team. If you have not received an earnings release and would like a copy, you can find one on our website at valero.com. Also, attached to the earnings release are tables that provide additional financial information on our business segments. If you have any questions after reviewing these tables, please feel free to contact me after the call.
Before we get started, I'd like to direct your attention to the forward-looking statement disclaimer contained in the press release. In summary, it says that statements in the press release and on this conference call that state the company's or management's expectations or predictions of the future are forward-looking statements intended to be covered by the safe harbor provisions under federal securities laws. There are many factors that could cause actual results to differ from our expectations, including those we describe in our filings with the SEC. Now I'll turn the call over to Mike.
Thanks, Ashley, and thank you for joining us today. As noted in the release, we reported the second quarter 2012 earnings of $831 million or $1.50 per share. In addition, our board of directors has authorized company management to pursue a separation of our retail business from the remainder of the company. We believe a separation of our retail business by way of a tax-efficient distribution to our shareholders will create operational flexibility within the businesses and unlock value for our shareholders. As independent companies, both retail and the remaining business will be better positioned to focus on their industry-specific strategies. We expect to have more details in the coming months. I should also note that our board of directors recently approved an increase in our quarterly dividend from $0.15 per share to $0.175 per share, the highest level in company history.
Returning to our second quarter results, operating income was $1.4 billion versus operating income of $1.3 billion in the second quarter of 2011. The increase in operating income was primarily due to higher throughput margins in the U.S. Mid-Continent, U.S. West Coast, and the North Atlantic refining regions, combined with higher throughput at our refineries and higher margins in our U.S. retail business. These improvements were somewhat offset by lower refinery margins on the Gulf Coast and lower ethanol margins. Our second quarter refining throughput margin was $10.63 per bbl, which is a slight decrease versus the second quarter of 2011, the margin being $11.41 per bbl.
The decrease in refining throughput margin was mainly due to lower discounts on crude oils and feedstocks, lower margins for gasoline in the Gulf Coast, and lower margins for other products such as petrochemical feedstocks. However, we did see higher margins for diesel in all of our regions except the West Coast, and higher gasoline margins in the Mid-Continent, the West Coast, and the North Atlantic regions. Our second quarter 2012 refining throughput volume averaged 2.7 MMbpd , up 342,000 bbl per day from the second quarter of 2011. The increase in throughput volumes was mainly due to the addition of capacity from the acquisition of the Pembroke and Meraux refineries.
Refining cash operating expenses in the second quarter of 2012 were $3.59 per bbl, which was lower than our first quarter 2012 and our guidance due to higher throughput volumes and lower maintenance expense. Our Pembroke and Meraux refineries showed significant improvement during the second quarter, combining to contribute over $130 million in operating income. The increase in performance at these refineries is a result of operational improvements we have been diligently implementing since the acquisitions. For example, at Pembroke, we have improved feedstock selection, reformulated the FCC catalyst, and optimized the product slate and blending. Examples at Meraux include improvements in the ROSE unit operations and in refining optimization.
Subsequent to the second quarter, we had an unfortunate event in late July at the Meraux refinery when a power outage during storms brought the plant down. A fire occurred when [audio distortion]a unit. No one was injured, but all units at the refinery are currently shut down. Repairs are in progress, and we estimate the refinery will resume operations at normal rates by the end of August. In the meantime, certain units may be restarted while repairs continue. The impact on throughputs for the third quarter will be reflected in guidance that Ashley will provide in a few minutes.
The export market remains solid as our Gulf Coast refineries continue to benefit from low cost natural gas and increasing access to discounted domestic crude oil. We believe these competitive advantages enable Valero and other U.S. Gulf Coast refiners to profitably take market share from less competitive Atlantic Basin refiners, particularly in Europe and the U.S. East Coast. Our retail business had a great second quarter and reported its highest-ever quarterly operating income of $172 million, consisting of $134 million in the U.S. and $38 million in Canada. Our retail business continued to perform exceptionally well.
The ethanol segment reported $5 million of operating income, which was down $59 million from the second quarter of 2011, mainly due to lower gross margins as ethanol prices were pressured by excess industry supplies. With ethanol margins under further pressure in the third quarter due to rising corn prices, we recently stopped production at the Albion and Linden plants and have trimmed utilization at the other plants.
In the second quarter, general and administrative expenses, excluding corporate depreciation, were $171 million, which was in line with our guidance. Depreciation and amortization expense was $386 million. Net interest expense was $74 million, and the effective tax rate in the second quarter was 35%.
Regarding cash flows in the second quarter, capital spending was $800 million, which includes $106 million of turnaround in catalyst expenditures. Our expected capital spending for the full year 2012 is around $3.6 billion, an increase from prior guidance, mainly due to acceleration of certain projects originally scheduled to be completed in 2013. We expect 2013 capital spending will be in the range of $2 billion-$2.5 billion.
Also, in the second quarter, we returned $124 million in cash to shareholders as we paid $83 million in dividends and we spent $41 million to purchase 1.8 million shares of our common stock. In addition, we used $862 million to pay down debt and received $300 million from the reissuance of tax-exempt bonds. With respect to our balance sheet at the end of June, total debt was $7 billion, cash was $1.3 billion, and our debt to cap ratio net of cash was 25.7%. At the end of the second quarter, we also had nearly $4.7 billion of additional liquidity available. In July, we renewed and increased the size of our accounts receivable sales facility to $1.5 billion, providing an additional liquidity of $500 million.
We continue to make progress on our key growth projects. Our Port Arthur hydrocracker project is on track to be mechanically complete during the third quarter of 2012 and is expected to achieve full operation during the fourth quarter of 2012. The St. Charles hydrocracker project is expected to reach mechanical completion by the end of the year with full operation in the second quarter of 2013.
Through our recent actions to increase the dividend and the potential separation of our retail business, it is clear that we are working to maximize shareholder value. We look forward to the improvement in our free cash flow from the planned decline in our capital spending, the expected contribution from our growth projects, and the favorable industry trends that continue to accrue to our assets. Now I'm going to turn it over to Ashley to cover the earnings model assumptions.
Great. Thanks, Mike. For modeling our third quarter operations, you should expect the refinery throughput volumes to fall within the following ranges: Gulf Coast at 1.43 million- 1.47 million bbl per day, Mid-Continent at 430,000- 440,000 bbl per day, West Coast at 265,000- 275,000 bbl per day, and the North Atlantic at 430,000- 450,000 bbl per day. Refining cash operating expenses in the third quarter are expected to be around $3.85 per bbl. Regarding our ethanol operations in the third quarter, we expect total throughput volumes of 3 million gal per day. Operating expenses should average approximately $0.36 per gal, including $0.04 per gal for non-cash costs such as depreciation and amortization.
With respect to some of the other items for the third quarter, we expect G&A expense, excluding depreciation, to be around $175 million, and net interest expense should be around $70 million. Total depreciation and amortization expense in the third quarter should be around $395 million. Our effective tax rate in the third quarter should be approximately 37%. Trish, that concludes our opening remarks. We will now open the call for questions.
Thank you. We will now begin the question and answer session. If you have a question, please press star then one on your touchtone phone. If you wish to be removed from the queue, please press the pound sign or the hash key. If you're using a speakerphone, you may need to pick the handset up first before pressing the numbers. Once again, if you have a question, please press star then one on your touchtone phone. Our first question comes from Doug Leggate from Bank of America. Please go ahead.
Thank you. Good morning, everybody. Excuse me.
Doug .
Fellas, my question, I guess, is on the step-up that you're expecting on free cash flow. Your dividend, even with the increases, if I'm not mistaken, is somewhere around $400 million a year. It's still fairly small. I guess I'm trying to understand what is the priorities for the use of cash? In answering that, you give us an idea of what you think the right debt-to-cap level is for this portfolio at this point.
Doug, this is Klesse. Our use of cash as we're generating more cash, and next year we clearly expect to be generating more cash, is first, we're going to maintain our investment-grade credit rating. Second, we're going to hold a little more cash than historically as we have it, just because of the volatility in our business. You watch the screen, you see how much things move. We just think we need to hold some more cash. Then, we've been very clear. We're going to return additional cash to the shareholder. Having said that, in the last year and a half, we've paid off about $1.5 billion of debt, and next year we have $460 million or so of debt that becomes due, and our plan will be to pay that off as well.
I think we're demonstrating returning cash to the shareholder with the previous things I just said. You asked, what is the proper or target debt to cap? I'm just going to tell you, we're going to maintain the investment-grade credit rating, and maybe our debt to cap just goes a little [audio distortion] Today it's 25%, I think.
Yeah.
Thank you. Our next question comes from Paul Cheng from Barclays. Please go ahead.
Hey, guys. Several quick questions. Mike, can you tell me what is the working capital and also the inventory in excess of the book?
Yeah. The working capital total current assets are $14 billion. Total current liabilities is $10.8 billion. Then our inventory above the book value is $6.5 billion.
Thank you. Do you have a number you can share what is your retail business taxable base?
Yes, we do. The tax basis in our retail at June 30th was approximately $900 million-$950 million.
So that means that from a tax efficiency standpoint, the offer, if anyone wants to buy it, they need to be really high in order for you to feel comfortable because it's going to be a huge tax bite?
Well, I think you have. This is Klesse. First off, we need to establish, we have about $500 million of EBITDA from this business, and Mike can walk you through that. You have to consider some overheads. We have the split between Canada and the U.S., so we have certain tax issues in each jurisdiction. That's why we're very carefully saying we're going to work a tax-efficient distribution. However, I know on this phone call, we have the refining analysts, but if you look at the freestanding retail companies, certainly Couche-Tard and Casey's, you'll see that their multiple's up around 10xx, and today our EBITDA multiple is around 3.7 or a little less than 4x.
Let's stop and look at our retail business. We're very well run. We're excellent financial performers. They've had very good returns. We're extremely well located with nearly two-thirds of the units in Texas, in the U.S. and in Canada. We have an excellent market share in Quebec. We own a lot of units. They're not leased. If you look at our data, which we'll provide, you'll see that m any of our units are owned. The whole business is an extremely solid business. Then if you jump to, what is the correct EBITDA ratio for this business? I will tell you, we are up there with the very best, if we are not the best. The number becomes large. That is why we have been very clear about a tax-efficient spin. However, all options are on the table.
Sure. Bill, is ethanol going to stay with Valero, or is it going to go to the retail?
Ethanol stays with Valero.
And-
It is a fuel. We are really a wholesale provider, a plant operator producing ethanol.
Okay. Two final.
Retail is a marketing business.
Sure.
Hey, Paul.
Yep.
Hey, it's Ashley. Hey, just two things. First of all, if you want any more balance sheet items, that's now on page five of our earnings release tables.
Mm-hmm. Okay, great. And two final one.
Yeah.
One, there's an interesting development. Someone put a refinery into a variable MLP. Don't know if you guys have looked at that and whether this is something fundamentally you think that you're really against it, or that you think that it could be interesting. Then finally, that acquisition, how important is as a part of your strategy for the next one or two year? Thank you.
Okay. So on the variable MLP, of course, we've looked at it. We watched what happened to one of the other refining companies. We're open to increasing long-term shareholder value. On the other hand, having said that, we saw how this traded, and we don't really think, and I don't know what it is today, that a 19% yield is really providing the value to the shareholders. So in the sense of values all around, what the asset's worth and then the return. So, I think it remains to be seen whether that's really something that's in our shareholders' interest. Then on acquisition, we look at the assets that are in the market, but today, there's really nothing happening. We have confidentiality agreements, obviously.
Thank you. Our next question comes from Robert Kessler from Tudor Pickering. Please go ahead.
Good morning, gentlemen. A couple of questions. One is just quick, and that is, do you have an estimated repair cost for Meraux? Then a more conceptual question, and forgive me for this being of a conceptual nature, but Bill, if we entered into a scenario where the Gulf Coast coking margins came under pressure, that is the spread between, say, LLS and Maya came down to a minimum level, how low could that go and still have cokers operate on the Gulf Coast, whether in your own portfolio or others? Really where I'm going with that is trying to reconcile a view that LLS comes under pressure, which I think you all may subscribe to, and also a view that I think you have that coking margins are maintained at a level that continue to support continued coking utilization rates.
Robert, on the repair cost of Meraux, about $10 million.
Okay.
We're going to start some of the units up here in the next week or so, but the full plant won't be up, like Mike said, till probably the end of the month. Coking margins. I've given in the sense into a sunk coker, I believe that you can get somewhere down in 8%-9%, somewhere not much lower than 8%, I think. You agree?
Yeah.
Into a sunk coker. But then what we've done in the past, and some of the people on the call will remember, as other companies did, when coking margins came under pressure several years ago, we started to produce more fuel oil. It was more economical to make fuel oil and cut back on coking. I'm sure that if such a situation happened, you would see us start to spare cokers, just like our competitors would. Putting as much light into the units as we can and optimizing it daily. But a sunk coker. I've been very clear, in my opinion, that after Motiva's plant, you're not going to see grassroots coking built on the U.S. Gulf Coast. Something's going to have to dramatically change.
Makes sense.
Yes, we do subscribe to the fact that we do believe LLS is going to sell less than Brent.
Sure.
We are saying, I guess, that pretty well next year, you are going to push out all the light sweet crude out of the U.S. Gulf Coast.
It seems like as long as you are still pulling in some imports, it gets that Brent support for relative parity and maybe you have sort of a gap down once you push out that last barrel. Is that the right way to think of it, as sort of binomial rather than a ratable price degradation?
Well, I see your point. You still have some light sweet imports into the East Coast. But on the Gulf Coast, I think it will just be mediums and heavies, and it's where you draw the line. I think you're still going to see the freight advantage at least of $2 or $3 versus Brent. But that's why this whole conversation is the reason that Valero is very supportive of bringing Canadian heavy sour crude oil to the U.S. Gulf Coast. Then, I think it'll price where you can still put it into a sunk coker.
Just so I understand your numbers, you said 8%. I'm assuming that's a rate of return on a sunk cost in a coker. What spread do you assume to get that return?
Oh, it would be 8% of the price of oil.
Oh, okay. Got you.
I was trying to put it in terms, because it moves around on us, and it is dependent because of the liquid volume loss as to the absolute price of oil. So yeah, 8%, I am saying, of the price. $100, it would be at least then $92, I guess, in that range. Now that is into a sunk coker, and you are not making much money there.
Okay. Thanks for that.
Our next question comes from Roger Read from Wells Fargo. Please go ahead.
Hi. Good morning.
Morning, Roger.
I guess, just to hit on the retail a little bit. It seems like as an industry overall, the thought always seems to be vertically integrated. Can you address maybe a little of how this spinoff would affect that aspect of the business for you?
Well, this is the company-operated retail that we're talking about in the U.S. And in Canada, it's our company-operated retail, but we have a little different business model in Canada. We actually manage the street price even where we have our agents. It also, in this segment, includes our home heat business that's in Canada and our card lock business. But we have on top of that, a wholesale marketing business. If you add this up, it's 1,027 units in the States and 775 units in Canada. But in addition to that, we have 4,000 branded Valero outlets, and we will still run a branded wholesale business.
If you think of Valero then after the spin of our retail company or separation, whatever transpires, Valero's really going to be a refining and wholesale marketing company with some petrochemical feedstock production, ethanol production, power generation, hydrogen, and associated logistics. We're just a manufacturing company with a wholesale marketing business. We're still vertically integrated. We just don't have, in the States, about 120,000 bbl a day of our production that's actually going through the hose.
Okay.
And then we are not going to be selling Twinkies and beer and cigarettes. We are going to leave that to the retail group.
Well, there is a lot to be said for Twinkies, beer, and cigarettes, I am sure.
There is, quite frankly.
All right. Thank you.
Thanks, Roger.
Our next question comes from Ed Westlake from Credit Suisse. Please go ahead.
Good morning, and congratulations on the move or discussion of the move this morning. A separate question, I guess. If you get some proceeds from the EBITDA of the retail spinoff and also as your free cash expands from your CapEx reduction and also the EPS uplifts. Is there any debt that it makes sense that you should bring in early? I'm thinking about restrictive covenants or just debt that you feel you could reprice it at a low rate?
No, there's not really any debt that we have that would make sense to try to prepay it or bring it in early or call it.
Right.
We actually did a little of this last year.
Right.
We took the stuff that was, some of the debt that was economic for us to take off the market, we did.
Right. The Gulf Coast margins, obviously, globally, you make the point that product inventories are low. It is just surprising given the weak economy that the margins are so strong. Any thoughts as to the sustainability of the margins?
Well, we do think they are sustainable in the sense. They move seasonally and every other factor that I spoke about and volatility in our business. Our business, whether it is Valero or any of our competitor, anybody in the refining business, exports are a key part of the future for the U.S. refining industry from the U.S. Gulf Coast. We are very competitive. You have personnel that has terrific skill sets and very productive. Then we have low-cost natural gas, and we are going to have a crude advantage that is beginning to materialize significantly.
There is no question if you are a mid-continent refiner, you are making a lot of money, and that is good, and we benefit from that at a couple of our plants. But we believe that you can compete in the world market and certainly in the Atlantic Basin even, by coming out of the U.S. Gulf Coast. But exports are a key part of it, and they're allowing our whole industry to operate at a higher operating rate. Domestic demand, as you properly stated, is not very strong, and that reflects a very slow economy, even though it's growing and very high unemployment. Companies like Valero, over 80% of our output is fuels. If people aren't working, you just aren't consuming the fuels.
Then, a final question. My impression is that you have a high degree of turnaround costs and activity in the first half of this year. Do you expect that 2013 will be a sort of a lighter turnaround schedule as a result as you look forward in your plans?
We did have a high turnaround this year. This is Lane Riggs who' s going to answer you.
Yeah, I would say next year. We have a big refinery turn. We have a large refinery-wide turnaround at Quebec in the first quarter of next year. But with that end, we have a big turn. We have a reasonably large turnaround at Corpus Christi and Texas City also in the first quarter. So I would say it's roughly about the same size in the first quarter of next year versus this past first quarter.
For us in turnaround in Catalyst, it seems to be running about $500 million a year.
That's right.
It moves up and down a little bit around there, but around $500 million a year.
Thanks very much, everyone.
Catalyst costs have come down some this year.
Our next question comes from Faisal Khan from Citigroup. Please go ahead.
Good morning. It is Faisal from Citi.
Hey, Faisal.
Hey. Can you guys give us an update on Aruba? I believe you guys have an offer there and any associated inventory levels you have there that you've either liquidated or are holding on to for the sale of the asset?
Well, in Aruba, the only inventory we really have there now is for our other businesses where we're taking advantage of the terminals, right? So we don't have any inventory per se associated with the refinery except that we do provide fuel oil to the utility, and we also provide gasoline and diesel to the island, which is part of our marketing distribution effort there. But basically, we have no inventory there that's in support of refining per se.
And then, as far as Aruba, we're still working the transaction. We did disclose most of the information in, I guess it was last quarter's 10-Q.
The 10-Q, yes.
We're still working the transaction, and the government of Aruba is extremely supportive, and we'll see how it turns out.
Okay. Then on St. Charles, with the hydrocracker I believe that the hydrocracker was supposed to be up and running in the fourth quarter, if I remember from some of your previous presentations, but looks like now it is going to be in the second quarter of 2013. Am I reading that wrong?
Well, you are not reading anything wrong. I have said the St. Charles hydrocracker would be finished by the end of the year, and we would get it up in the first quarter, but now we are going to say it is the second quarter we will get it up. This would be my schedule, and to be honest, some of my people will say that this was my schedule, not theirs. But I would tell you, we have slipped a month or two on both projects.
However, these are big projects for Valero, each $1.5 billion, plus there is some other stuff around it. Our people are doing a terrific job. If you can imagine the miles of cabling, this is what we are really finishing up at Port Arthur is miles of cabling. Our people are doing terrific, and we just are going to be a month or two later.
Fair enough. Thank you.
Our next question comes from Blake Fernandez from Howard Weil. Please go ahead.
Guys, good morning. Just a few quick ones for you on the retail spin. Bill, you mentioned your intention to maintain investment-grade credit rating. I am just wondering if the credit rating agencies have opined on the spin yet. Secondly, on the retail, is it a strategic situation where the retail was being starved of capital and as a standalone maybe they undertake some additional capital projects or higher growth? Then finally from a CapEx standpoint, the $2 billion-$2.5 billion next year, could you tell us what the breakout is associated with retail on that? Thanks.
Okay. On the debt, I will just answer you. No, we have not talked to the rating agencies, but we will because our investment-grade rating, as I said, is very important to us. We think we are a very large player in this business, buying today over 2 MMbpd of crude. We think that is important for our suppliers to know that we are investment grade. On the second question. I am sorry.
What was it, Blake?
What was your second question?
Credit rating opinion on that.
Blake?
Can you hear me, Bill?
Now I can. Go ahead. I'm sorry.
Okay. Sorry. Just to remind you, the second question was basically from a strategic standpoint as a standalone, I guess, with the retail somewhat being starved of capital, are they now allowed to maybe pursue higher growth options?
There is no question that we had a capital budget raise really in the U.S. of about $80 million, and in Canada, it was around $30 million. We have all the detail that both of those businesses have thrown off cash to the parent. Clearly, as standalone businesses, they will be able to execute a strategy that the management feels is appropriate.
Okay, great. The third was on the CapEx. If you could just provide the breakout of next year $2 billion-$2.5 billion, what portion was associated with retail, please?
You got it?
Yeah. Typically, retail spends about $130 in capital for the whole segment, so that would be U.S. and Canada.
Okay. Thanks, guys.
Our next question comes from Jeff Dietert from Simmons & Company. Please go ahead.
Good morning.
Morning, Jeff.
My question is associated with product exports. I was hoping you could talk about what you exported on gasoline and diesel in the second quarter, and really what your capability of exporting is. Is there substantial ability to export more than what you're already exporting, and potential for any capital projects that might expand that capability?
Sure, Jeff. Good morning. It's Joe.
Hey, Joe, how are you?
I am well. You?
Good.
Well, Jeff, in the second quarter, we exported about 165,000 bbl a day of diesel, primarily to Latin America and Europe, with the bulk of it going to Europe. The reason that number moves around from month to month has more to do with the economics of the moves than our ability to do it. We saw diesel strengthen here domestically. We kept it at home. When the arbs opened to Europe or to Latin America, we go ahead and put it on the water and move it out. Gasoline exports in the quarter were 75,000 bbl a day. The bulk of that goes to Mexico, and then also into Latin America.
We are seeing continued strong demand for both as we go forward. There is a host of reasons not much has changed in the market, which would lead us to believe that those exports were not going to be there going forward. As far as capacity, we would estimate that our capacities for gasoline are 250,000 bbl a day, give or take, and on the diesel, 275,000- 300,000 bbl a day. We continue to look at logistics projects. The team has been very active in assuring that we were going to have continued access to export markets and the logistics would not be an issue. There are some projects that have been identified, but nothing significant.
It is a global market business, and what happens is the exports tend to pull from domestic supply. It is only when pricing is actually better than the domestic market do we tend to export. It is all driven on economics. Then the fellows here are telling me that to Roger's question earlier, where I said 120,000 bbl a day in the U.S., but remember, our plan is that this will be a branded jobber for us, and we will still supply from the refining group to the retail group. I thought it was obvious, but the guys here say it is not. So we will still sell from refining to a freestanding retail business.
Joe, is Valero participating in West Coast product exports as well?
No, we're not. Jeff, the barrels that we move on. [Audio distortion] No, we're not.
Okay. If I could slide in another question, I was curious about the Port Arthur and St. Charles startups. Is there an impact on existing operations at Port Arthur and St. Charles? What's exactly involved in this eight-week startup process? Could you help me with that?
Hi, Jeff, this is Lane. Once our project group hands it over, it's a six to eight-week project that's sort of started up. It really doesn't, besides just staffing up and have all the technical people we need to oversee the startup, it doesn't really affect the rest of our operations. But the breakdown of the six to eight weeks, the first part of it, a leak check and do some other things just to get the unit ready, and that could be two to four weeks. Then we've got to load the catalyst. There's 2 million pounds of catalyst we got to load in this thing. After that, we have to prepare and condition the catalyst, which can take about two weeks. That's really all the things that we have to do to get ready to put oil in.
Thank you.
Our next question comes from Cory Garcia from Raymond James. Please go ahead.
Morning, fellas. Just had, I guess, a quick question with regard to Meraux. Obviously recognizing that the current focus is going to be bringing that back online safely following the incident. But just wanted to maybe get a little better understanding on the potential integration between that plant and St. Charles. I know that was sort of a talking point when you guys purchased the refinery. Aside from any sort of feedstock and product optimization between the two, are there any other sort of hardware or larger integration efforts that you guys are currently working on?
Yes, there is. At Meraux, what we intend to do is install another reactor, and we will convert some of the process units so that we can make more distillate. If you look at Valero's system, today, we make 33%-34% distillate. Obviously, the margins are in distillate. Distillate is growing in the world much more rapidly than gasoline. With our two big hydrocrackers to get finished this year, we'll be up to 39%-40% distillate yield, actually one of the highest in the industry in the U.S. Then we have this project we're working on, Meraux, which will take us another year and a half to two years to complete. Installing this reactor that will allow us there to make a much higher distillate yield.
You will see that refinery produce distillates as opposed to gasoline in the long run. Then we'll integrate the gas oils between the two facilities. We have an alky plant there that we might have some integration opportunities with all the butanes we're seeing coming into the market. So there's a lot of opportunity on the U.S. Gulf Coast for all of our plants to work together, and we optimize it as a system as best we can.
Our next question comes from Sam Margolin from Dahlman Rose. Please go ahead.
Good morning. Thanks for taking the question. Could you give us a quick update on Eagle Ford volumes into Three Rivers and maybe even elsewhere now that some infrastructure gets built out down there?
Sure. In the second quarter, we ran just over 140,000 bbl a day of Eagle Ford crude. Of course, the bulk of that was at Three Rivers and then down at Corpus Christi. One of the interesting things is that we're running a lot more Bakken now. We're running about 130,000 bbl a day of Bakken, and a lot of that is going up into the Memphis refinery.
Okay, great. I did notice that Midwest margins were higher year-over-year. I assumed there was something going on in Memphis with the crude slate, so that's helpful. Secondly, this is a bit of a longer question, but there's been some acceleration of discussion of RFS mandates in the media. Assuming that the government is going to be pretty slow on this or resistant, is it your understanding, maybe from intelligence that you have on the ethanol distribution side, that the industry is in possession of a surplus of credits and the gasoline market can effectively tighten as blending reduces even without changes in the mandates in the near term here?
Okay, I'm trying.
I'm not so sure we're going to know that. RINs are $0.04?
Yeah.
RINs are $0.04, so that doesn't necessarily imply that there's an excess of RINs.
Okay.
I am going to say, but I know this is an issue for everybody on the call. We are in the ethanol business, but there is 800,000 bbl a day of ethanol going into the gasoline pool. By the mandate, you took market share from refiners and gave it to farmers. But to eliminate that is extremely difficult. We have had almost $8 corn, I think, a couple of years ago. But remember, ethanol has high octane. Under the EPA rules, we get a one-pound waiver. So we have tankage, system limitations, CARBOB, RBOB, CBOB. This is a far more complicated conversation than having the hog farmers in Washington asking for relief.
Okay. Thanks so much.
Our next question comes from Evan Calio. Please go ahead.
Sorry about that. Morning, afternoon.
Evan.
Yeah. Good morning, afternoon. Congrats on the announcement. I apologize if I missed it. I jumped on a little late. Any timing estimate on the retail spin-off, and how do you think about appropriate leverage on that asset coming out? Thanks.
Yeah. We are still evaluating the leverage and how much leverage to place on that. It will be comparable to the other C store companies in that segment. As far as timing, around six months, we could probably do the spin-off. We have got a lot of work to do yet with our SEC filing, and we need a private letter ruling. So let us just say around six months.
That is great. Another question. I know you have had an additional quarter to think about it and even witness a temporary widening on your Brent LLS spread. Any new thoughts as your engineers have spent maybe another quarter analyzing an ability to either run or make any investment to shift your slate a little bit to the lighter side? Thanks.
On the U.S. Gulf Coast, where we tend to be a heavier refiner. Three Rivers is relatively light. Houston is light. Memphis runs basically Gulf Coast light bbl. Really for us, Texas City, Port Arthur, St. Charles, and even Meraux, we are looking at obviously being able or having the capability to run a higher percentage of lighter oils. Our people are working on these. But the issue in our business is if it is deemed that we need a permit. Permitting is very long now. If it has to have a CO2 permit, it is even longer. But we are working on all this, I am sure, just like every one of our competitors.
Our next question comes from Paul Sankey from Deutsche Bank. Please go ahead.
Hi, everyone. I think you have covered a lot of the questions I had, particularly on ethanol I was going to ask, but obviously just slightly covered that. I am still not quite clear how you see the market playing out here if we do not have enough RINs and there is a shortage of ethanol. Can I simplify the answer on that one?
Well, right now there is not a shortage of ethanol, but plants are cutting back. We, as Mike said, have shut down two plants. We have cut back the others. We are probably running at 50%. If you look at the numbers, it was about 19 million bbl of ethanol. It is dropping rapidly. You want to know how I think it plays out? This is how I think it plays out. I think ethanol price is going to go higher here relative to gasoline. Because obviously, today we are losing money in ethanol.
Sure. You have to meet the mandate. I guess the question is, are you going to meet the mandate? Not you, but I mean the industry.
That is a valid question. About 93% or so of all the gasoline sold in the country has ethanol in it, and we're going to hit the blind wall here. Gasoline volume is down. RINs are $0.04. I don't know if I can answer.
Well, Paul, there's one thing to take into consideration. We can carry forward 20% of the RINs from last year to this year. I don't think that we're looking at an issue this year. But in the out years, as the obligations continue to go up, it is going to be a challenge and RINs are going to be more expensive.
Yeah. Thanks. That's helpful because I know that if you guys say you don't know, at least it's okay for me to say I don't know either. That's great.
No, it is not.
Forgive me if you feel like you have covered this, but on M&A, particularly, I am thinking about BP saying Texas City and Carson are available for sale and people are interested. Do you have anything to add on that? Thanks.
I really do not. I have said in the past that we have looked at it and we have a confidentiality agreement. But the thing is still on the market.
Our next question comes from Chi Chow from Macquarie Capital. Please go ahead.
Great. Thank you. Hey, Bill, I want to go back to this topic on the global distillate export market. I know there's been outright refinery downs in the Atlantic Basin on the less competitive plants. But on our analysis, looks like there's potentially eight new hydrocrackers, including your two, set to come online in the Atlantic Basin over the next 12 months. By the way, that's about 400,000 bbl a day capacity from what we see. Can you comment on what you see the potential impact on supply-demand balance on the distillate market in the basin going forward here?
Well, I think there are hydrocrackers coming on, as you say, so there's no disagreement there. Some of those are in the Med. I think the Med is different than Northwest Europe. So I do think this is a difference. I look long term, and I see a lot of pressure in the Mediterranean for making money in refining. But in the Atlantic Basin, we still have growth. Mexico, Colombia, Brazil. I know you know, Chi, that the sugarcane harvest is bad in Brazil, so they're going to wind up importing more gasoline. I know you asked about distillate. But we believe that we'll still competitively be able to go into these markets. Whether Mexico builds the Tula refinery, I think is a very open question, especially with the new government. In numbers, they're talking now about $10 billion or $12 billion for this refinery.
You've also seen, and we're not participating today, but we have in the past, actually shipped some ULSD to Australia, and you've seen where the Australians are shutting down quite a few refineries. So I think it all comes down to the arbs, as Joe mentioned earlier, and the economics and the U.S.-produced stuff is going to be, on a cost basis, very competitive. Whether we can squeeze it into the market, we think we'll be able to. But you're clearly right that there are hydrocrackers being built. Everybody sees the distillate growth. We just happen to be in a good spot here. I wish I had the hydrocrackers today, right?
Right. Can you expand a little bit on the difference between the Northwest Europe market and Med? What is the critical difference there between the two?
Because I think longer term, you're going to see supply come from the Middle East into the Med.
Okay. Got it.
Demand, obviously, I know you look at all this stuff. Look at the Italian demand and some of the Greek demand numbers are. They're just very long refining. You have a very long refining situation on top of some competition coming from the Middle East.
Yeah. It just seems a bit concerning with Europe, the situation there with demand, China slowing down. Does it really get down to Latin America, South America to stand strong for this export market to keep going here?
I would like to hope that Europe does eventually recover, but I can't argue with you tonight.
Right.
I would say it does come down. When Joe spoke, our gasoline exports go to Latin America and about half of our distillate exports go to Latin America.
In Australia, are you sending out of the Gulf Coast?
That was a couple of years ago, and we did send some out of the Gulf Coast.
Got it. Thanks for that. One final question. It looks like looking at your stats, your Gulf Coast light sweet crude runs actually got up to 240,000 bbl a day this quarter. I think last quarter you said your capacity was around 200 a day. Are you finding ways, obviously, to get more of that crude in to your system?
No, we're finding ways. Our capacity, we said that's what we were running. The 200 was not our capacity last quarter. That's actually what we were running.
Okay.
We're going to continue to close that gap, and this is based on availability and then economics. If the discount's large enough and you can get enough of it'll make sense versus some marginal medium sour. These are the economics that we're working with, and we're just continuing to increase that.
What is your capacity, then, in the Gulf Coast right now on the light suites?
Half.
15.
Yeah, 500,000 bbl a day.
That includes Memphis, though, right?
That would include Memphis.
Yep.
Got it. Okay, great. Thanks a lot.
Thanks.
Our next question comes from Harry Mateer from Barclays. Please go ahead.
Hi, guys. Two questions. First, you answered a few questions on the investment-grade ratings. I was just wondering if you could put a slightly finer point on it, and specifically whether your current ratings are what is important to you, mid-triple B, or is it just investment grade, so you guys might be willing to go down to low triple B as part of this retail separation. Second question, what is the priority for you in terms of considering retail separation? Is it maximizing the amount of cash you take out of the business? Or is that less of a focus given Valero's liquidity position?
Okay, so on the first question, we do not see any reason at all why there would be any concern about our rating. We want to be investment grade, and I am just going to leave it at that. We will work with the rating agencies if they have any issue. I gave some other data points on how much we paid off here. Our coverage ratios and everything look very, very good. On the second question, it was-
Cash priorities. Yeah.
Yeah. Priorities are in this spin sale, we want to do a tax-efficient spin. We are working on shareholder value, as you would expect us, so we want to maximize our shareholder value. It is a point of being tax efficient and generating shareholder value.
Okay. Thank you.
Our next question is a follow-up from Doug Leggate from Bank of America. Please go ahead.
Hey, Doug.
Thanks. I actually got cut off earlier, Bill. I apologize for that. I was talking to myself there for a couple of minutes.
Good.
Nothing unusual there.
Well, did you want a conversation?
Yes. Exactly. It was that stimulating. My couple follow-ups were basically, can you walk us through the timing of how you would expect to take the cash tax benefit of the mechanical completion credit that you will get for the two projects? I do have a follow-up before I get cut off again.
Okay. On the timing of those benefits, we are estimating the benefit is $650 million-$700 million. The timing would be spread out over the next four to five quarters, and a lot of that depends on obviously the profitability of the company over the next year and a half. I am just going to say probably over the next four quarters, we will receive all that benefit.
Starting in third of 2012, yeah?
That is correct.
Okay, great. My final one then is, I wanted to go back to Robert's question about LLS discounts potentially versus Brent. In terms of your optionality of being able to run medium and heavy sour crude on the Gulf, how would you expect if you, let's say, you did increase your LLS runs or your light sweet crude runs domestically more than perhaps your coker limitations would dictate? How would you expect the pricing of medium and heavy sour to move? What I am getting at is that our thinking is if LLS moves, it probably benefits your medium and heavy feedstock as well. I am just trying to get some colors whether that is the right way to think about this or not.
No, Doug, I do think that is the right way to look at it. Certainly, the medium sours will be tightly linked to the light sweet prices. Heavy sours, I think, are going to be competing with medium sours for space in the refinery. As we get more supply into the Gulf, I think what we are going to see is a downward pressure on the entire complex. Bill mentioned what the discounts needed to be on heavy sour crudes relative to light sweet crudes. You need at least 8%. You are going to see those have to price in if they want to move into the system.
I would add that. What happens then is LLS is discounting to Brent. Then you are going to have these other crudes discounting, and that discount is on the world market, which is pricing against Brent. The freight becomes the factor. We know that some Venezuelan crude and Mexican crudes have been moving to China and other places, and Venezuelan crudes moved to China. You wind up with a freight being the flywheel in there and, of course, available tankers. There will be a limit of how wide that spread goes then relative to freight. That is why I think we see LLS at a couple of bucks, which is really the freight that tends to be the driver here.
Relative to Brent. Yeah.
Bill, theoretically, that couple of bucks would translate, and I am not trying to be too simplistic here, but to your entire Gulf Coast slate. Is that the right way to think about it?
Yeah, I think that is right. That is why we say the U.S. refining industry, it is not necessarily Valero, is in a very competitive situation in the world. That is why going back to some of the other questions, we believe that the U.S. refining industry can be competitive in the export markets when we face a domestic demand that is challenging.
Terrific. Thank you. I will leave it there.
Right. It applies to Valero, but it is applying to our industry.
Thank you.
Our next question comes from Paul Cheng from Barclays. Please go ahead.
Hey, guys. Just two quick follow-up. One, Bill, when you are looking at your retail network in July month to date, what is your same store gasoline sales? Secondly, what is your total WTI linked crude that you run in the second quarter?
Okay, so let's do the crude one first. Ashley, WTI linked crude.
How much we running the-
The second quarter.
In the second quarter.
Well, it's in McKee and Ardmore, I guess.
Yeah. It is still right around $250.
Okay.
But, you are also running Bakken in Memphis, right? So it seems like you say you run about $140. So should that now be more like in the $350- $400 then?
No, because the Bakken crude that we run at Memphis actually comes from St. James.
Oh.
It is priced like LLS.
Oh, okay.
It is at a discount to LLS in the deals that Joe's people have done. We don't have the receipt facility, so it tends to go to St. James and come back up Capline.
Interesting.
That's the answer to that. Gary Arthur is here, and your question was in July, same store volume?
That's correct.
Do you have it?
Yeah. We're down just a little bit under 3% same store on gasoline.
That's in the U.S.
Okay. Thank you.
And we have no further questions. Thank you. At this time, I'll turn it back to you.
Okay. Thanks, Trish. Thank you, investors and analysts for listening. If you have any questions, just contact Valero's investor relations department.
Thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect.