Welcome to the Valero Energy Corporation second quarter 2011 earnings release conference call. My name is John, 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 will now turn the call over to Mr. Ashley Smith, Vice President of Investor Relations. Mr. Smith, you may begin.
Hey, thank you, John, and good morning, and welcome to Valero Energy's second quarter 2011 earnings conference call. With me today are Bill Klesse, our Chairman and CEO, Mike Ciskowski, our CFO, Gene Edwards, our Chief Development Officer, Joe Gorder, our Chief Commercial Officer, Kim Bowers, EVP and General Counsel, and Jean Bernier, EVP and President of Ultramar. If you have not received the 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 about reviewing these tables, please feel free to contact me after the call. Before we get started, I would 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 can cause actual results to differ from our expectations, including those we have described in our filings with the SEC. Now, I will turn the call over to Mike.
Thanks, Ashley, and thank you for joining us today. As noted in the release, we reported second quarter 2011 net income attributable to Valero stockholders from continuing operations of $745 million, or $1.30 per share. Our second quarter 2011 operating income was $1.3 billion versus operating income of $904 million in the second quarter of 2010. The second quarter refining throughput margin was $11.41 per barrel, which is an increase of $1.84 per barrel over the second quarter of 2010, and our highest second quarter margin in nearly three years. The increase in throughput margins compared to the second quarter of 2010 was due to higher margins for gasoline and diesel, plus wider discounts for heavy sour crude oils on the Gulf Coast and light sweet crude oils in the midcontinent.
One of the drivers of our year-over-year gain in throughput margin was the increase in gasoline and diesel margins. For example, the Gulf Coast gasoline margin per barrel versus LLS increased to 29%, from $7.97 in the second quarter of 2010 to $10.26 in the second quarter of 2011. Looking at the Gulf Coast ULSD versus LLS, margins per barrel increased 16%, from $9.88 in the second quarter of 2010 to $11.49 in the second quarter of 2011. So far in the third quarter, margins have moved significantly higher to average around $13 per barrel for gasoline and $16.50 per barrel for ULSD. Another driver for our margin gain over last year was crude oil discounts. The Maya heavy sour crude oil discount versus LLS increased 21%, from $12 in the second quarter of 2010 to $14.58 per barrel in the second quarter of 2011.
The Maya discount has narrowed some in the third quarter, with the July average down to around $12 per barrel. An additional benefit for Valero came from WTI type and Eagle Ford crudes pricing at a substantial discount to LLS. The WTI discount to LLS increased more than $13 per barrel, from $2.26 in the second quarter of 2010 to $15.47 in the second quarter of 2011. The discount helped our McKee, Ardmore, and Three Rivers refineries, where their crude oil is priced at or below WTI. In the third quarter, the WTI discount to LLS has continued to widen with the July average of just above $16 per barrel. As noted in the release, we are increasing the use of discounted Eagle Ford crude in our system.
During the second quarter, we processed an average of 37,000 bbl per day of Eagle Ford, an increase of 12,000 bbl per day over the first quarter. This crude replaced expensive waterborne sweet crudes, saving around $16 per barrel in the second quarter. We are continuing to look for additional ways to use more of this discounted crude. We plan to process 25,000 bbl per day of Eagle Ford crude at our Corpus Christi refinery during the third quarter, and our Three Rivers refinery should have the ability to process nearly 60,000 bbl per day of Eagle Ford crude by the end of this year. Continuing with other items, our second quarter 2011 refinery throughput volume averaged 2.3 million barrels per day. That was up 136,000 bbl per day from the second quarter of 2010.
The increase in throughput volumes was primarily due to the restart of operations at the Aruba refinery. Refining cash operating expenses in the second quarter of 2011 were $3.86 per barrel, which was higher than guidance due to the higher-than-expected maintenance, catalyst, and chemical costs. Our retail segment reported a record high for a second quarter, with $135 million of operating income, mainly attributable to stronger retail fuel margins. U.S. retail had $87 million of operating income in the second quarter, and the Canadian retail operation earned $48 million of operating income in the second quarter, which was its highest quarter on record. Our ethanol segment earned $64 million of operating income in the second quarter, which was up $20 million from the first quarter of 2011 and up $29 million from the second quarter of last year on higher gross margins.
Also in the second quarter, we achieved our highest ever quarterly production rate at 3.4 million gallons per day. In the second quarter, general and administrative expenses, excluding corporate depreciation, were $151 million. Depreciation and amortization expense was $386 million. Net interest expense was $107 million, and the effective tax rate on our continuing operations in the second quarter was 37.6%. Regarding cash flows in the second quarter, capital spending was $664 million, which includes $133 million of turnaround and catalyst expenditures, and we paid $29 million in dividends. Also in the second quarter, we repaid $208 million in maturing debt and spent $37 million to acquire a terminal and pipelines in Eastern Kentucky. With respect to our balance sheet at the end of June, total debt was $7.6 billion, cash was $4.1 billion, and our debt-to-capitalization ratio net of cash was 18%.
At the end of the second quarter, we had $4.1 billion of additional liquidity available. We remain focused on our strategic priorities. In addition to making progress on our cost savings goal, we progressed on key investments at our St. Charles and Memphis refineries, and our hydrocracker and hydrogen projects remain on track to complete in 2012. We also look forward to the closing on our acquisition of the Pembroke Refinery and the marketing and logistics assets in the U.K. and Ireland on August 1st. In conclusion, Valero is in great financial position with plenty of liquidity and an investment-grade credit rating. Going forward, we have substantial potential for earnings growth with improved refining margins, the Pembroke acquisition, and the expectation of significant contributions from our economic growth projects. Now, I'll turn it over to Ashley to cover the earnings model assumptions.
Okay. Thanks, Mike. For modeling our third quarter operations, you should expect refinery throughput volumes to fall within the following ranges. The Gulf Coast at 1.42 million- 1.46 million barrels per day, midcontinent at 420,000 bbl- 430,000 bbl per day, West Coast at 270,000 bbl- 280,000 bbl per day, and Northeast with Quebec only at 200,000 bbl- 210,000 bbl per day. After we close on the Pembroke acquisition, our Northeast region will be changed to North Atlantic region, and the Pembroke Refinery will be combined into that region with the Quebec Refinery, and we expect throughputs for the third quarter to average between 370,000 and 380,000 bbl per day. Refining cash operating expenses are expected to be around $3.80 per barrel across our system in the third quarter.
Regarding our ethanol operations in the third quarter, we expect total throughput volumes of 3.3 million gallons per day, and operating expenses should average approximately $0.37 per gallon, which includes $0.03 per gallon 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. Net interest expense should be around $95 million. Total depreciation and amortization expense should be around $390 million, and our effective tax rate should be approximately 37%. 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 touch- tone phone. If you wish to be removed from the queue, please press the pound sign or the hash key. If you are using a speakerphone, you may need to pick up the handset first before pressing the numbers. Once again, if you have a question, please press star then one on your touch- tone phone. Standing by for questions. Our first question comes from Ed Westlake from Credit Suisse. Please go ahead.
Hey, yeah. Good morning, everyone.
Morning, Ed.
Just a quick question. I guess in Q1, there were some one-offs, and there was also the hedge, and you add that back, and our calculation was up to just under $1 of earnings. In Q2, you get to $1.30 in a stronger macro environment. I' m just wondering, were you disappointed with the level of Q2 earnings, or is Q2, do you think, a good expectation as a base to go forward given some of the volatility we have had in Q1 and Q2 in terms of EPS estimates?
I think we were pleased with the results. We'd always like to have higher results, but if you look at our capture rates, given the market environment, we captured right in line with historical averages, or we beat those averages in most regions. Costs were a little higher than expected, but not too much. All in all, I think it's a fair representation of what we can achieve in this market environment.
My second question is more of a question around, as we get closer to the EBITDA increases that should come with the investments that you're making, particularly in some of the hydrocrackers. Can you talk about whether you're going to give some of that cash back to shareholders in terms of as the debt comes down and as the cash flow increases?
This is Klesse, Ed. We'll look at all of that. Right now, we want to have adequate cash to go ahead and finish these projects. We've told you in the past, this year's capital spending will be, as Mike said, in this $3 billion- $3.2 billion, we believe. Next year is probably going to be in the same range as we finish our projects. So for guidance, I'd tell you we're at the $3.1 billion for 2012. That'll let us finish our projects, and then we'll see how our cash position is affected. Obviously, we're going to close on Pembroke in the U.K. and Ireland with cash. Crude oil price is up some, so our intent is to buy all that inventory.
Clearly, we'll pull our cash down here in the next week, but then w e expect to build it back up because we see a very good third quarter, just as you see. Where we miss consensus, which I think is your question, when you actually look at what happened, we had a lightning strike at Port Arthur. We had a couple other things that, in a way, were acts of God. Our mechanical reliability is improving every day, so we had these acts of God. As you go to the third quarter, July is just about done. It's going to be an excellent month for us. So we miss consensus here in the second quarter, but right now we're going to beat consensus in the third quarter.
Just to be clear, in terms of the thought process around returning cash, you just want to make more progress in terms of the hydrocrackers before making such a decision?
That is absolutely correct.
Okay. Thanks very much.
Our next question comes from Doug Terreson from ISI Group. Please go ahead.
Good morning, guys.
Morning, Doug.
Bill, industry-wide, we've obviously had some demand destruction over the past couple of months, and on this point, I wanted to see whether or not you guys were seeing any improvement in demand for gasoline and diesel in your major markets. Is there any bounce anywhere out there?
We have not seen that. I'm going to let Joe. Joe Gorder is going to answer you.
Okay. Hey, Doug. How are you?
Good.
It's been fairly flat. We're off a little bit on gasoline and diesel year to date. We keep looking for those glimmers of hope. I think on the gasoline side, as long as you've got unemployment where it is, it's going to be very tough here in the States anyway for gasoline demand to pick up. Diesel demand, we're getting mixed signals. You've got some of the trucking indicators looking positive and some of them looking negative. The same is true with the rail and the marine cargoes. The Port of Los Angeles data looks a little different than the Port of Long Beach data. So we're not seeing any significant improvement, but we're not seeing things crater either.
Sure. Okay, and on the same topic-
Doug?
Yeah.
Let us tell you a little more, though.
Okay.
We'll give you a little more here on retail. Jean Bernier is going to tell you some about retail for us, which will give you a good indicati on.
Okay.
On retail, our overall demand in the second quarter is soft. It's down about 2% in the U.S., and on a same-store basis, it's down about 3.5%. However, July is looking a bit better than that, so that is an encouraging sign. In Canada, on the retail side, actually, our volumes have been very strong. Overall, growing about 3%, on a same-store basis, between 4% and 5%. We see different trends in different regions and different areas.
Okay, good. Also on the same topic, somewhat, we're starting to see prices approach record levels for end users in some of your important export markets in Latin America. Just wanted to see if Joe or somebody could give us an update on trends in export markets that you guys have exposure to. Are they still pretty strong there as well?
Yeah, Doug. No, things look good there. Our gasoline exports in the quarter were 69,000 bbl per day, and our diesel exports were 143,000 bbl a day. The gasoline is primarily to Mexico, but we moved some to Ecuador and Chile also. On the distillate side, 70% went to Europe in the quarter and 30% to South America.
Okay.
And if we look out to the third quarter, those numbers are generally in that same range. Distillates might be a little higher than the second quarter, but generally in that same range. Doug, the key for me is that we continue to see an open arm to Europe for the EN 590 grade distillates. So when I look at our distillates for the second quarter, they were down a little bit from historical numbers, but it was more related to availability of supply for us to move out than it was demand abroad.
I see.
Then if you look out to the quarter, the third quarter and going forward, we still have Mexico demand exceeding their supply.
Okay.
As imports grow, Mexico is now importing 425,000 bbl a day of gasoline and 130,000 bbl a day of diesel, and both of those are up from last year. We still have supply problems with Venezuela. Petrobras is purchasing gasoline. So, looking out, things look like they are going to continue that way, and so we should see continued strong demand out of the Gulf Coast.
Okay, Joe. Thanks a lot.
You bet.
Our next question comes from Doug Leggate from Bank of America. Please go ahead.
Hi, thanks. Good morning, fellas.
Good morning, Doug.
The project's obviously kicking in next year. If I could just ask you to give us a quick update. I guess this year we were looking at the two FCC revamps. Did they get completed on time? In which case, should we expect some improvement, I guess, on the cost line for the balance of this year? Related, can you just clarify whether or not you will benefit from any tax credits related to the accelerated depreciation of your capital? I guess it's some fairly substantial numbers, in which case, would you accrue lower taxes in 2012? I have a follow-up, please.
Lane Riggs is going to tell you about the stat. Clay Killinger will tell you about the taxes.
Okay. Hi, this is Lane. Our FCC grade job was completed pretty much on time and on budget. It's performing quite well. We're still trying to optimize it, but we've already seen a significant improvement in operations. This is on the St. Charles. In the Memphis FCCs, we have the oxygen supply. Those two projects are complete, so on a go-forward basis, we should certainly see an improvement for our earnings ability with both those two projects.
I would add that the St. Charles, which was a conversion from the millisecond to a conventional cat, we've seen at least an 8 percentage point increase in our conversion or yield, and we're going to get the four to five-year run. At Memphis, hanging the cat cooler because there's no vacuum tower there allows us to go ahead and heavy up our crude slate, and we'll also get a four to five-year run. These are tremendous projects for us when you look at our reliability or mechanical availability going forward, as well as our just general yield, because when you get these conversion yields, when you have $100 oil, you can see that it's worth a lot of money to us, taking that slurry to a clean product. Now on the taxes.
Yep. Doug, this is Clay Killinger, the Corporate Controller, and most of these, if not significantly all of these projects will qualify for the bonus depreciation under the tax law. We've computed at a 6.5% interest rate that for each $100 million of qualified capital expenditures will relate to about $5 million of net present value of benefit to the company.
Your tax guidance for 2012, then you'll start accruing that on January 1? In which case, can you give us an idea of what you expect the impact to be in terms of percentage on the typical tax guidance that you guys have?
We haven't calculated what the number will be, but it will come into effect when those projects get completed. When they get done, we'll update you on that.
Great stuff. My follow-up-
I just want to finish then. On the hydrocrackers, we're still looking for Port Arthur to be completed in the third quarter of 2012 and St. Charles to be completed in the fourth quarter of 2012. They are big. Overall, this is over a $3 billion capital project between both plants. In this environment we have today will be significant profit contributors as the numbers we've given you in the slides demonstrate.
Thanks, Bill. My follow-up is really a broader strategic question. You guys have got a fairly good track record of when you buy one asset, you tend to sell another and overall high grade the portfolio. With Pembroke kicking up here, and I guess with your exit from more or less from the East Coast, at least to the lower 48, how are you feeling about the broader portfolio? I guess specifically, I would ask how you are feeling about the West Coast as a core part of the portfolio on a go-forward basis, and I will leave it at that. Thanks.
Well, Doug, it is a very good question. If you think about us strategically, we continue to work on geographic diversification, execution every single day, keeping our investment-grade rating. These things are important. Then you get to our portfolio, and when we look at the demand in the United States, now the world is growing, the United States is much more sluggish in its growth t hat we will continue to work on our portfolio. We are looking at it again. Obviously, the West Coast has depressed cracks. I think you've noticed in our earnings tables that we actually lost money at the refinery in Quebec in the second quarter. We tend to look at all of these with our whole portfolio. These are long-term decisions. We'll analyze it in a long-term approach, but we are continuing to work on our portfolio so that we are, in fact, more competitive.
All right, Bill, I'll leave it at that. Thanks very much.
Thanks, Doug.
Our next question comes from Blake Fernandez from Howard Weil. Please go ahead.
Morning, guys. Thanks for taking my question. Question for you on Pembroke. I know there was an issue recently, I believe it was a fire of some sort. I just wanted to make sure, as of the August 1st close date, will that facility be up and running, fully operational the way you had projected in your slide pack when you announced the acquisition?
Yeah. This is Gene Edwards. The refinery's running fine today. There really hasn't been a big impact on operations because of this, and there's just going to be some cost in rebuilding the tanks. But this occurred on the seller's watch, and they're taking care of these expenses.
Okay, great. Thanks, Gene. Secondly, Joe, I know you went through the export environment looking fairly robust through the balance of the year. I was just curious if you have any thoughts on next year. Per the IEA, it looks like we've got quite a bit of capacity coming online globally, about 2.5 million barrels a day. Are you expecting any impact on the Gulf Coast ability to export or how that might factor into what you're seeing?
Blake, I really think it's going to be this way for a long time. It's almost getting to be a chorus here instead of a verse that we've got strong exports out of the Gulf Coast. I read an article this morning that Reliance is moving their barrels now to Asia. Asian demand is still strong, and we expected them to come to the States at some point in time. We just haven't seen it. So you've got growth in other parts of the world which are pulling those barrels. The Gulf Coast refiners, as we've said before, are very cost competitive, and you have natural markets for those barrels, and those barrels are into Mexico, Central America, South America, and then over to Europe. I just expect that this is going to be with us for some time.
Okay. Thanks a lot. Appreciate it.
Okay.
Our next question comes from Mark Gilman from Benchmark. Please go ahead.
Guys, good morning. Had a couple things, if I could. Just by way of a clarification on the tax issue mentioned previously. I assume that that bonus DD&A is not going to affect the effective rate, but rather cash tax, and that you'll be providing deferred taxes. Am I correct in that regard or wrong?
Yes, you are. You are correct.
Okay, thanks. Couple of other things, if I could. I noticed a pretty significant increase in high acid crude runs in the quarter and was wondering, is that a permanent shift, and what's giving rise to it?
Well, this is Joe, Mark. It's the economics that are giving rise to it. You're right. We ran much higher volumes of Marlim and Frade in the second quarter. We also ran more volumes of M100, but it was all economically driven.
Okay. With respect to the intent to increase the Eagle Ford volumes, Joe, Gene, or Bill, anything entailed in doing so other than the logistics of getting it there from a hardware catalyst or any other type modification that would have to be made?
Mark, we're running now 40,000 a day down there, and we've got a turnaround scheduled in September, and Lane can speak more to this if he'd like. But there's no major changes in the turnaround as a result of the turnaround that are going to allow us to take those volumes up to 60 a day. In addition to the volume we're going to run there, we're going to try to run the 25 that Mike mentioned at Corpus Christi. The great thing about running more of this Eagle Ford crude is we've got it priced in there at a WTI-type price, and we're backing out CPC and Saharan and more of the expensive foreign suites. Lane, anything on the plan?
During the turnaround, we're going to hang some valves on the top circulating reflux of the pump around to be able to handle it. It is a lighter crude, so it will allow us to, once we get up around 60, we are trying to determine, but we think we will be able to run even more than that. But essentially, we're hanging the valves and have the exchangers allow us to do that after the turnaround.
Mark, we will spend somewhere in the neighborhood of $10 million around Three Rivers to do some of this that the fellas are talking about. To go above, that would cost more money, and of course, we'd probably need a permit. These are longer conversations then. At Corpus, it has all been, to this point, really trucking, pipeline construction, getting the oil to the plants. Some of you may remember I've mentioned to you we have a project at our McKee Refinery, which is the same kind of thing, just not Eagle Ford. But the issue we have at McKee is we need a permit. We would spend about $100 million to have a modest expansion there, which has good economics, but the permit is probably an 18 to 24-month conversation.
Okay, yeah. Guys, I listened very carefully to what Mike said about the crude discounts in the midcontinent. But yeah, I guess from that standpoint, my thought was the capture rate in that region really does not seem to reflect that. Am I missing something?
I think you are, Mark, but we will be glad to walk you through.
Why don't you call Mark because I don't mind telling you guys, our most profitable refineries are McKee, Three Rivers, and Ardmore. So we're capturing it, but I'm not sure. What I'd like you to do maybe is to call Ashley after the call, and he'll walk you through it.
Yeah. I think there's one more item that the broad public should understand is in our midcontinent system includes Memphis. Roughly 40% of our midcontinent region doesn't participate in WTI. Memphis is an LLS-based refinery. So if you assume that all that throughput is capturing a WTI-based margin, you made a very bad assumption.
Okay. Last one from me. Where were you in the quarter, and where might you expect to be in terms of being a buyer of RINs?
Oh, Mark, we're definitely a buyer of RINs. We're now to the point where we're blending probably, it's over 80% of our gasoline volumes with ethanol. So that's not the issue, but it's really the biodiesel RINs that become the challenge for us. There's just not enough biodiesel out there to blend for us to meet it with blending this year. We have plans underway to put in blending facilities for biodiesel at a handful of our racks, and we expect that by the end of 2012, we'll be blending at volume to satisfy that obligation. But it'll be a build-up until that time. So we are short RINs. Yeah.
It's an expense item well over $100 million. Maybe I can just leave it at that. This is a big program, and Joe's telling you things we're doing to mitigate that. But for Valero, it's well over $100 million.
Bill, is that annual or quarterly?
Annual.
Annual.
It's over $100 million.
Okay. Does it go up from here until you get in position to be able to achieve that blending?
No. No, unless the market for the RIN, and frankly, Mark, it's all related to these biodiesel RINs. Those are very expensive. The market form is about $1.34, and you look at that compared to an ethanol RIN, and it is $0.035. So the market for the biodiesel RINs are very high because they're just not available out there. We are going to be blending more, though, as I said, and as a result, that expense should go down as we proceed forward.
Relative then to the price of whatever they are going.
Right. As more biodiesel is blended, the price of the RIN should come down, too.
Okay, guys. Thank you very much.
You bet.
Our next question comes from Jeff Dietert from Simmons. Please go ahead.
Good morning. Thanks for the update on the Eagle Ford volumes. As you think about some of the light sweet crudes coming on Eagle Ford, Permian, Bakken, Cushing area, there are major pipelines coming from the Eagle Ford into Houston, Longhorn reversal into Houston, the Keystone XL, Enterprise, Enbridge lines going into Houston. If production grows as fast as many of the producers believe it will, are you looking for incremental volumes? Could you use incremental light sweet volumes in your Houston area refineries over and above what you've already talked about?
Well, some are going to Houston, some go to Port Arthur, but Joe's going to answer you.
Yeah. Jeff, clearly, the midcontinent refineries are benefiting now, right? We all see that. But to the extent that we do move sweet crudes down into the Gulf, you're going to see pressure on LLS prices. So would we like to see some of this crude end up in the Houston market where we could run it or over at Memphis? Absolutely. I don't think that we are going to see this get resolved, though, anytime soon. I do not know what your view is, but you've got so much production coming on stream up there, as you described, that I think we are going to see significant volumes continue to pour into the market, both from the regions you mentioned, the Bakken area, from the Panhandle area, and then Canadian barrels coming in.
It' s going to be 18 months or better for the pipelines to be put in place to carry it out. So I think you are going to see continued pressure on those discounts in the midcontinent. One thing that is interesting, Jeff, that we saw is that Cushing tank capacity is coming on stream big time. We used to use 40 million barrels as a number of tank capacity. It is up to 62 now, and in the next six months, they are going to add another 13 million barrels, which is going to take it up to 75 million barrels of storage. So clearly, the market is getting ready for a lot more of this midcontinent crude to be available and to be stored.
Joe, are you starting to see some attractive Saudi barrels coming into the U.S. Gulf Coast? They raised production in June. They're talking about further increases in July. You guys seeing some of those barrels? Are they getting priced attractive enough to find their way to the Gulf Coast?
We are. We're running now some Arab Extra Light in the Gulf. We are also going to be bringing in more Kuwaiti barrels. The Kuwaitis have lifted their imposed reduction of contract volume. We're operating for a period there where we had a 10% reduction in our contract volume. They notified us that they were taking that off and that we were able to take more barrels. I do think we're going to see a lot more medium sour barrels coming into the market.
How significant are those volumes?
I understand the Saudis are going up to 10 million barrels a day of production. So that would be, what, another- p ardon? No, not entirely into the Gulf, but they're going to put that into the market. Jeff, I don't know how much you'll see.
Okay. On Pembroke, you've provided some guidance on $0.25 a share of accretion on 2010 outlook. Do you happen to have an updated number based on where the forward curve is today?
I think the forward curve, Jeff, this is Gene again. Forward curve looks pretty similar to our forecast. Although Brent prices obviously are very high right now, so there's some concern on that. But if you look at the 2-1-1 to Brent today, it's around $13 a barrel. It's really not all that bad. I think we haven't really redone our economics since we did the acquisition, but I think it looks more or less in line.
Okay. All right. Do you have any comments on the status or the impact of the ethanol tax credit repeal and how that might influence Valero or the industry as a whole?
Yes, this is Gene again. I'm not sure when it's going to get repealed. The Senate was talking about July 31st. Doesn't look like that's going to happen, but maybe it happens at the end of the year. We're watching it, but in reality, it doesn't really have much impact on us right now. The blender's credit is really being captured by the blender, not the ethanol producer. Just to use an example, ethanol today is right around $3 a gallon. CBOT and RBOB in New York are both $3.05, $3.10 a gallon. So there's margin to blend, even if you don't have the $0.45 credit. So in effect, the blenders have captured it. We captured a little bit of it in our retail and our wholesale. It's passed on to the wholesale customers.
At retail, from our analysis, it's more or less competed away when we have good ethanol blending margins. Our overall margin at retail doesn't seem to be affected much by that blender's credit. So I think it's competed away in the business, whether it be wholesale or retail. So the net effect of Valero really is pretty much nothing.
Thanks, guys.
All right. Thanks, Jeff.
Our next question comes from Paul Cheng from Barclays Capital. Please go ahead.
Hey, guys. Good morning.
Morning, Paul.
A number of questions. In Corpus Christi, Bill, how much that you can run Eagle Ford? Right now you are saying that in the third quarter it is about 25,000 bbl per day. Assume that if there is no major restriction in the logistics side, how much more that you can ramp it up to?
Hey, Paul, this is Lane Riggs. We have two crude units there. We have our west plant crude unit, which can run about 40,000 bbl a day. So that would be pretty much you are able to run about 40,000 bbl a day of Eagle Ford, as long as it is economic. Then our other plant is our east plant, and it is predominantly medium sour, heavy sour, but at the end of the day, it is all about economics. We can run Eagle Ford in that crude unit. It is just a matter of it being available and the economics are right. So that is about a 100,000 bbl a day unit. So we can run quite a bit.
The reason Lane is answering you this way is the east plant has a coker, so you tend to run the coker.
I see.
If you get enough discount, you don't run the coker.
East plant is your original plant, right? With the resid cracker.
The west plant has the resid cracker.
That's the original.
That's the original Valero plant is the west plant. The east plant is the old Coastal plant.
Okay. I see. Very good. Can you give me some bunch of data in terms of working capital, long-term debt, market value of the inventory in excess of the book?
Yeah. On the current assets, it's $14.7 billion. Current liability is $10.2 billion. Total long-term debt, $7.6 billion. Our market value in excess of the LIFO on the inventory is $7.9 billion.
Okay. I suppose that this may be for Ashley. On the Quebec, is there any particular reason why margin realization seems like sequentially, at least from the first quarter, have dropped so much compared to the benchmark indicator?
Where?
Quebec.
Oh, Quebec. Yeah. Typically, if you go back and look at our capture rates versus a typical indicator like a Brent 2-1-1, it falls from first quarter to second quarter. Mostly on the light end, the butane LPGs up there. The market always gets weak because you can't blend them into the gasoline pool. You'll see it fall from 4Q and 1Q are typically a higher capture rate. It falls in second quarter and then holds and builds back up as you can start blending back into gasoline.
That seems like a pretty substantial because the benchmark indicator seems to be flat to slightly down only.
It does look substantial. It has been substantial in the past.
You think that this is still normal on the seasonal pattern?
Yes, absolutely. Go back. We've been posting our Quebec-only performance for that region. We posted that to the website a few months ago, right after the first quarter. You can see historically how Quebec has done over the past five years. In the first quarter to second quarter, it falls anywhere from 20- 30 percentage points on capture rate. This is the key driver.
I see. In Aruba, did you guys make money in the second quarter?
No, we did not.
You did not.
We had margin, but we had many operating issues.
Bill, is it a primarily operating issue or that the configuration, just even in today's market, discount light heavy defense or you still won't be able to make money?
I'm going to take the second part first. The configuration is an issue when you have $100 oil running a coking refinery, you just have to have a big discount. I mean, it's as simple as that.
Right. The current discount is not big enough?
The discount would have been big enough in the second quarter if we had run better.
I see.
We had a lot of problems. This startup, which basically we started a year ago, getting ready to start up, has been very tough for people who've worked very hard. We've had a lot of issues getting back to a good rate. Today we're running very near 200,000 bbl a day, but we've had issues getting there.
Okay. So do you think that now the bulk of the issue is behind you?
I think we have clearly made progress on being able to run reliably. But I would tell you that the second half on the P&L, not necessarily cash flow totally, but P&L will be challenging unless we get a change in the discounts.
I see. Bill, for the or then this is for Mike. For the remaining two spending for the hydrocracker in St. Charles and Port Arthur, how much is the remaining that you have to spend?
It's about $1.3 billion.
Together?
Combined. $600 million, $700 million. Then we have a couple of other projects around it. So I would basically tell you that it's about a 1.5 to finish the two hydrocrackers, some of the crude work that's going on around it.
Bill, do you have a rough number that what's the CapEx look like next year?
The capital spending next year?
Yeah.
Yeah. I'm going to say it's the same as this year, $3 billion- $3.2 billion, and I think I said we'll all go $3.1 billion is where we're sitting at this point. Having said that's like a ballpark number because like most companies you guys will talk to, we're in the middle of starting our budgets for next year and our planning.
Mm-hmm. Two final questions. One, Bill, historically, Valero, the strategy is that you love the large coastal refinery with a high conversion capability to run a lot of discount crude, that kind of flexibility. With the last six or seven months, the drastic change in the midcontinent, TI spread, does it in any shape or form change your view about the criteria or that you think that this is just too short-term of a phenomenon for you to really change your strategic thinking?
It's a very fair question, Paul. Obviously, in today's market, it is all about location. So it's a given. To solve some of these, which Valero's benefiting by it, we've already told you at McKee, Ardmore and Three Rivers. For the industry then to cause the LLS, WTI types to narrow, it's really probably an 18-month to two-year conversation. Because some of the things that I think Doug mentioned earlier, or maybe it was Jeff, they're not all happening yet. So this is 18 months to two years away for pipelines to move this volume out of the midcontinent. So location, it's all about location today. However, I would still say to you that at the end of the day, it's just like we've talked about in the past. It's location, it's complexity, but it's also being able to operate and executing, executing, executing all the time.
That's the piece that you will notice over the next as these projects are getting done. You're going to see our executing is dramatically improving. On our mechanical availability now, we're a borderline first quartile, and a couple of years ago, we were third and fourth quartile. So you will see that as this data keeps coming out. But today, it's all about location, bottom line.
But you do not believe that it really is for the long term, so you are not changing the way how, in terms of M&A and consideration of the criteria?
I'm not going to say not changing. I'm going to say what a few minutes ago I said complexity matters. Where Valero's expertise is running high complexity refineries. And that is our institutional knowledge here. However, we are looking at an expansion at the McKee Refinery. We've already talked about what we are doing in South Texas. Those are projects that we would not have considered two years ago for sure, would not have considered one year ago for sure. So there' s obviously some change in our approach. On the other hand, to give you the whole story, you can see our Quebec numbers, as Ashley said, we have a currency. Currency has gone up in Canada. That makes their conversion to dollars.
You can see when you look at their operating costs, it has moved up dramatically. Obviously, they are buying light sweet crude. So where we have an emphasis on in Quebec is going to be much more on the cost side and the product realization side because they have lost that currency buffer that they had previously, and the advantage crude oil being foreign. Clearly, this market that we're in with these differentials or spreads that we've not seen before are certainly biasing certainly our strategy. But it is still about executing and complexity and being able to take these barrels and make very clean products out of them reliably every day.
Yeah. Finally, can you tell us that, is there any major turnaround from you guys in the second half and the first half of next year?
I think Bill Day just released our turnarounds, but we have them at Corpus Christi in October and Three Rivers in September. The Three Rivers refinery, the entire plant's down, right?
Yes, sir.
It's down for three or four weeks. The Corpus Christi one is-
The east plant crude coker for three weeks.
It's the larger crude unit, the east plant we talked about, down for three weeks, the crude coker. These are turnarounds that are just scheduled turnarounds.
Very good. Thank you.
The heaviest turnarounds we had was in the first quarter.
Our next question comes from Evan Calio from Morgan Stanley. Please go ahead.
Morning, guys. Thanks for taking my call.
Yeah. Hey, Evan.
Yeah, depth of question is amazing versus only five quarters ago. Clearly a better time for refinery if that's an indication.
Yeah.
A couple questions for you.
Got to vote on that.
A question for you on the macro, and it really feeds into the prior response that you had on Arab Light volumes, and frankly, it actually may highlight complexity versus location. If we look into the year-end, ex SPR, you could see over 1.2 million barrels of incremental crude demand with low sulfur Libyan barrels out. It looks as though, ex the SPR, that would be met with primarily sour Arab Light barrels. What are your views in terms of the global market setting up for heavy sour imbalances in the back half of the year and clearly, benefits to your system? Any comments? I have a couple other questions.
Yeah. Hey, Evan, this is Joe. If you think about heavy sour in general, okay? We've got a discount right now, Maya related to LLS that's around this $14 a barrel, which is a decent discount. The SPR release certainly depressed LLS briefly, which compressed that Maya discount, but now it's moved back out. If you look more broader than just Maya, you've got a market right now that sees Pemex production stabilizing at 1 million of exports a day, somewhere in that range. You got Colombia increasing their heavy sour production by 140,000 bbl per day. They're up to 870 now, which is a significant increase year-over-year. You got Brazil increasing their production by about 150,000 bbl per day. We're seeing a lot more Basra in the market today.
As we mentioned earlier, we've got the Saudis putting more barrels into the market, as are the Kuwaitis. Then ultimately, we're going to have Keystone come on, and it's going to allow us to move more of these Canadian barrels into the market. On the medium sour side, you've had somewhat reduced production in the U.S. Gulf Coast because there's been some maintenance been taking place on the Mars platform. Of course, we had the spill which delayed subsequent drilling, but that will pick back up here at some point in time. So when we look at the market for sour crudes, both heavy and medium sours, we're pretty optimistic about these discounts.
Right. No, it looks that way in my opinion. Just a question on Maya. How should we think about the K factors? Do you see that being moved to offset some of the WCS impact in that pricing formula that's being impacted by Cushing inventory levels or pressure at Cushing?
Yeah, clearly, the biggest part of the formula is set. The K factor is what the Mexicans use to try to keep the market, the oil price at what would be a market. Certainly when you get heavy sour Canadian crude coming into the Gulf, anytime you get more supply, you're going to have pressure on these discounts. So we expect that that's probably going to happen. They have been very good. They're very capable. They've been very good at trying to keep the Maya price somewhat similar to a medium sour crude alternative. We expect they're going to try to continue to do that in the future. But again, as you have more crude supply into the market, it should pressure those discounts.
A question on Quebec. I know you mentioned focusing on cost, but is there any potential solution to move Canadian discounted lights that are really getting backed out from the U.S. mid-continent and sands growth that may be able to move to the east and give you a TI-like discount into that market? How do you guys think about that?
No, Evan, there's really not any logistics in place. You can always You can put it, I guess, on a barge or a ship, but the logistics don't flow that way.
Okay. Rail economics don't work, then?
Well, you have to get the cars. I don't know what people are telling you, but cars now are probably almost a year lead time. Certainly you would have to build the facility. We have a rail facility, but it works for products. Our pipeline will not be finished until the end of next year. We' re looking at all of these items, including what Ashley mentioned on the butanes as well, and on the general operating cost side.
Mm-hmm. Okay.
Your specific question is a little It is harder than just putting it on a ship and shipping it in.
Okay. I appreciate that entirely. On Three Rivers, I know you're working with Harvest Pipeline to bring a line from Eagle Ford into the asset. But is there anything magic about 60 in terms of 95 CDU capacity? Is there a potential to increase compression and take that number higher? Or is that, as you think about the asset, the right maximum amount for you?
Yeah, this is Lane. We'll see. Ultimately, we may think we can run up to 80,000 bbl a day of it. It's just a matter of whether it fills out parts of the refinery properly. But you're right, the Harvest Pipeline will be there. We put in a big truck rack. So we will not be logistically limited on Eagle Ford avail than the refinery. It'll all be about the economics of Eagle Ford and the refinery, which today we would run as much of it as we could.
I got you. And just lastly, briefly on the SPR release. I know you're the single largest purchaser, close to 7 million barrels. How did it benefit you guys? Can you explain maybe the process?
Well, we certainly can run the crude, and we were able to pick it up at a $5.11 discount on average to LLS. It is a simple math. You do the 7 million barrels times the $5, and we've had a huge benefit from bringing it in.
We will have some costs moving it around, but what we did is, the oil fits us in many of our locations, so we just decided to bid, and it was a bid process. As Joe said, we got it for a little bit of a discount against the metric. Joe is supposed to get that discount, though, every day.
That is great. Just one other question. I know you guys are running a lot more crudes through your linear program. It has not yet impacted inventory levels. Is there some correlation with running more crudes and having higher inventory levels since you want to blend out so you do not beat up your units as much?
I'm trying to-
I would say no because we typically, and I guess one of you guys correct me, our crude inventory number runs about 20 days, 22 days. So we're turning our inventory over 20, 22 days here in that range. So it just goes through our system, and our supply people are always balancing our system. So it moves a couple million barrels. We have over 100 million barrels of total inventory and moves a couple million barrels, but the system is always trying to get optimized.
Wonderful. Appreciate it, guys.
Thanks, Evan.
Our next question comes from Chi Chow from Macquarie Capital. Please go ahead.
Great. Thank you. We've beaten this topic to death today, but I'm going to ask one more question on running these inland crudes through your system. I guess-
You're sure you want to?
Well, just one more here. Assuming a couple years down the road, this is, I guess, hypothetical, that if all these pipelines and unit trains come in, assuming you can get all the volumes of inland crudes you want down to the Gulf Coast, is there an upper limit of how much of these light sweet inland crudes you can run through your entire Gulf Coast system?
I'm going to answer you and say, because we got into this conversation the other day, it all depends on the price. Today, we run different crude oils at our Houston refinery. You could put a lot of lighter crude in there. You could put lighter crude into all of our refineries. You'll underutilize your coker, then as Lane was explaining earlier, because it's lighter, you'll overload your vapor handling capability, so that's where you'll have to stop. It all depends on price.
You've got 1.6 million, 1.7 million barrels a day, something like that, of capacity. Theoretically, you can run a full dose of that without any sort of impacts on operations?
No, I would say we would not be able to run that much. We would get limited out on being able to handle the vapors. But you might make more money.
Right. Okay.
The way we do it is just like all our competitors do it. We run the LP.
Do you ever see the U.S. as being an exporter of LLS or WTI down the road?
I doubt it. We're still bringing foreign suites in.
I think we would answer this to say our opinion is going to be no better than yours.
Yeah.
I think is the best way to say that. The U.S. is still a big importer. The U.S. imports over 9 million barrels a day of crude oil. There would be some issue with the refining capacity, which you were just asking us, for that to happen. But our knowledge would not be any better than yours here.
Okay, great. I guess one other quick question, Bill. I think last quarter you mentioned that you thought Valero could beat the $3 EPS for the year. You still feel pretty good about that?
Yes, I do.
Okay, great. Thank you.
Our next question comes from Cory Garcia from Raymond James. Please go ahead.
Thanks. Taking my call, fellas. I'll just try to sneak one quick one in here. In regards to your sort of stay in business maintenance capital, seeing that's been around about $1.7 billion, I believe several quarters back, you guys were talking maybe $1.3 billion- $1.4 billion. Bearing in mind that obviously the regulatory environment can change on a dime, I'm looking at sort of how your portfolio has changed. You still think in maintenance cap could get back down toward $1.3 billion, $1.4 billion in the years ahead, or are we looking at more of a $1.7 billion, $1.6 billion type of level?
I think that eventually we can get to that number. What it is basically we spend DD&A. You always have to consider these environmental regs or other type of regulations. Yes, we can get there. What we're doing today is we're spending at a little higher rate in that area, just because we have many things going on to improve our reliability through our system. As we're replacing bad actor pumps, as we're addressing problem exchangers and that in the system, they are causing us to have a little higher capital spending. Our target would clearly be that we ought to be able to do it around DD&A with some subject to inflation there, but basically a DD&A. For Valero, total DD&A is about $1.5 billion. For the refining group, it must be about $1.3 billion.
Yeah. That is perfect, guys. Thank you.
We have no further questions at this time.
Okay. Thanks, John. I just want to thank shareholders for listening to today's call. If you have questions, please contact the investor relations department. Thank you.
Thank you, ladies and gentlemen, this concludes today's conference.