Valero Energy Corporation (VLO) Q1 2012 Earnings Report, Transcript and Summary

Ashley M. Smith - Vice President of Investor Relations Michael S. Ciskowski - Chief Financial Officer, Principal Accounting Officer and Executive Vice President Joseph W. Gorder - Chief Commercial Officer and Executive Vice President of Marketing & Supply William R. Klesse - Executive Chairman, Chief Executive Officer, President and Chairman of Executive Committee Gary Arthur - Senior Vice President of Retail & Specialty Products Marketing Lane Riggs - Senior Vice President of Refining Operations S. Eugene Edwards - Chief Development Officer and Executive Vice President of Corporate Development & Strategic Planning Kimberly S. Bowers - Executive Vice President and General Counsel

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division Paul Y. Cheng - Barclays Capital, Research Division Faisel Khan - Citigroup Inc, Research Division Jeffrey A. Dietert - Simmons & Company International, Research Division Blake Fernandez - Howard Weil Incorporated, Research Division Rakesh Advani - Crédit Suisse AG, Research Division Sam Margolin - Global Hunter Securities, LLC, Research Division Douglas Terreson - ISI Group Inc., Research Division Paul Sankey - Deutsche Bank AG, Research Division Evan Calio - Morgan Stanley, Research Division Arjun N. Murti - Goldman Sachs Group Inc., Research Division Chi Chow - Macquarie Research Harry Mateer - Barclays Capital, Research Division

Welcome to the Valero Energy Corporation reports First Quarter 2012 Earnings Conference Call. My name is John, and I'll be your operator for today's call. [Operator Instructions] 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.

Thank you, John, and good morning, and welcome to Valero Energy Corporation's First Quarter 2012 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, Executive Vice President and Chief Commercial Officer; Kim Bowers, Executive Vice President and General Counsel; and several other members of our senior management team. 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 after 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 could cause actual results to differ from our expectations, including those we’ve described 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 a first quarter 2012 loss from continuing operations of $432 million or $0.78 per share, which includes a non-cash asset impairment loss of $605 million after taxes or $1.09 per share, mainly related to the Aruba Refinery. Additional information about this loss is disclosed in the earnings release financial tables under Note D. Our first quarter 2012 operating loss was $244 million versus operating income of $244 million in the first quarter of 2011. Excluding the items mentioned in our earnings release, first quarter 2012 operating income was $367 million versus operating income of $786 million in the first quarter of 2011. The decline in operating income was primarily due to lower throughput margins in Refining, lower growth margins in Ethanol and lower fuel margins in Retail. Our first quarter Refining throughput margin was $7.71 per barrel, which is a 22% decrease versus the first quarter of 2011 margin of $9.91 per barrel. The decrease in throughput margin was mainly due to lower discounts on crude oils and feedstocks and lower margins for other products such as petrochemical feedstocks and petroleum coke, despite the higher margins for gasoline and diesel. In the first quarter of 2012, Gulf Coast gasoline margins per barrel versus LLS increased 72% to $6.56 from $3.82 in the first quarter of '11. Gulf Coast ULSD margins per barrel versus LLS remained very good and increased slightly from 13.59 in the first quarter of '11 to 13.68 in the first quarter of ‘12. The Maya heavy sour crude oil discounts versus LLS decreased 37% from $15.68 per barrel in the first quarter of 2011 to $9.89 per barrel in the first quarter of 2012. Our first quarter 2012 refinery throughput volume…

Okay, thanks, Mike. For modeling our second quarter operation, you should expect the refinery throughput volumes to fall within the following ranges: Gulf Coast at 1.44 million to 1.48 million barrels per day; Mid-Continent at 380,000 to 400,000 barrels per day; West Coast at 275,000 to 285,000 barrels per day; and North Atlantic at 440,000 to 460,000 barrels per day. Refining cash operating expenses in the second quarter are expected to be around $3.85 per barrel, which is lower than the first quarter due to higher plan throughput volumes and expected lower maintenance costs. Regarding our ethanol operations in the second quarter, we expect total throughput volumes of 3.5 million gallons per day, and operating expenses should average approximately $0.32 per gallon, including $0.03 per gallon for non-cash costs such as depreciation and amortization expense. With respect to some of the other items for the second quarter, we expect G&A expense excluding depreciation to be around $170 million, and net interest expense should be around $70 million. Total depreciation and amortization expense in the second quarter should be around $385 million, with the reduction in Aruba depreciation and amortization expense mostly offset by additional expense from new equipment entering service. Our effective tax rate in the second quarter should be approximately 36%. Okay, John, that concludes our opening remarks. We'll now open the call to questions.

[Operator Instructions] And our first question comes from Doug Leggate from Bank of America.

I got a couple of quick ones hopefully. My first one is really on the crude charge. We've obviously seen another, I guess, extended or relatively extended period of very attractive TI and, I guess, inland discounts relative to waterborne crude. I'm just curious about -- I imagine you’re trying to optimize your runs and if you could just give us an idea just to how, if any, changes that you're making or have made in terms of trying to gain greater exposure to those spreads? And I've got a couple of quick follow-ups, please.

Okay, Doug, this is Joe. Listen, obviously, we are. We're trying to run as much of the light-sweet domestic crudes that we can. If I look at our crude slate in general, from last quarter, we did run more light-sweet crude, and we also ran more medium-sour crude, and we basically backed out resid. So we continue to look for opportunities to optimize the overall slate. Now when we think in terms of what are we doing in the Gulf Coast here and what do we think the market's going to look like, I mean, the Brent to LLS spread -- or LLS to WTI spread could be anywhere from $5 to $25 over the next year. We just -- none of us really have any idea as to what that's going to be. We do believe, though, however, that longer-term, that's going to come in to $3 to $4. And I think this view would be supported by the fact that Seaway's pipeline tariff is in that range or slightly below that. Now we know that domestic production of light-sweet crude is continuing to grow and is going to continue to do so over the next several years, and a lot of these crudes are making their way to the Gulf Coast via the pipelines, whether it be Seaway or Longhorn reversal, the Seaway expansion, the Keystone southern leg and so on. So these crude prices, the discounts are going to continue to come in. And in this system, what we're doing is looking for every opportunity to run more light-sweet domestic crude. We currently run about 200 a day, and we think that we can take that up by perhaps another 200, based on some projects that we're looking at. So that's our plan, and that's what I got for you.

My follow-up is kind of related, actually, because you guys periodically have dabbled with hedging, and I'm just curious if you have that view of that spreads are potentially coming in over time. I'm just curious if you're tempted to try and walk in some of those spreads currently in order to make whatever adjustments you would plan to do near-term?

Doug, I guess this isn't directly the answer to your question, but we have -- and I think everybody knows that we've shifted our hedging. The parity point of crude pricing has shifted away from the Mid-Continent to the U.S. Gulf Coast, and so we’ve shifted our feedstock hedging from a WTI-related basis to a Brent-related basis. And the true WTI barrels that we run in McKee and Ardmore, we're hedging with WTI. Everything else has been shifted to a Brent basis. That had a negative impact on us in the first quarter. But as we head into the second quarter, we're getting it back, and with our long-term view that these spreads are going to come in, we believe that we're properly positioned. Plus just philosophically, it makes sense to use the paper, that the crude that you're running is pricing off of is the risk management tool. And so -- and then your question goes broader to our hedging program. I mean, we do -- or our trading program. We do things from time to time, Doug, but nothing material.

Our next question comes from Paul Cheng from Barclays.

Mike, can you give me a number of the balance sheet item in terms of working capital, long-term debt, market value of your inventory in excess of LIFO [ph]?

Okay. Paul, the total current assets are $15.8 billion. Total current liabilities, $13.1 billion. Our cash is $1.6 billion as I'd mentioned in my notes, and then our current maturities are $1.1 billion.

The cash is already included in the $15.8 billion you gave, right?

That's correct. Okay, market value of our inventory is $14.2 billion, and value in excess of LIFO is $8.7 billion. Total debt, which includes...

Long-term debt?

Yes. $7.6 billion, and stockholders equity, $16 billion.

$16 billion, your stockholders equity, perfect. Bill, wondering, did we -- looking in Pembroke, did you make money in the first quarter?

What I'm going to do going forward here is because we don't break out these refineries, we deal by system, so we're not going to give you any, going forward, how we're doing on the particular plant. So this would be kind of the last time. So at Meraux, we've had a very tough start; however, we've had a turnaround, several turnarounds. We had high crude costs come through, and so now as we get started here into the second quarter, we think Meraux is going to fit very well. You ask about Pembroke. Pembroke has largely been breakeven at the refinery. Marketing has been a little better, but basically, I'd just say to you, it's been a breakeven. Where we're working there is on cost and structure. Their costs are much higher than the way Valero will run these businesses going forward. And just to give you an idea, in April, Pembroke is very profitable. But -- so basically, we haven't made any money on either of these plants or the acquisitions, but we still think they fit very nicely for us, and we've made a lot of changes in 6 months.

Bill, in Pembroke, or that I mean, your overall experience in Europe, does it in any shape or form that have changed your view whether you want to further expand into the European market?

Well, it wouldn't be related to our experience at Pembroke. We look at assets that come on the market because we’re very -- I guess I should add, we’re very satisfied with the Chevron acquisition. We just had to make some changes in the way Valero does business. And we had Joe Gorder over there, and he's made a lot of changes, and now, we're sending Eric Fisher over to run the business, and we'll be implementing these changes over the next year. So our experience and how it fits into our system, overall, and for the long term, we’re very satisfied. Now you ask about expansion in Europe, well, we’re very concerned about the financial crisis in the sense that's going on in Europe. We're concerned about, frankly, the very, very large refining overhang in Europe. And so, as we see these plants coming on the market, we're just going to be very, very cautious. It really has to fit into our system going forward.

Bill, do you have the number you can share in terms of the same-store sales in the first quarter and also so far in April in your network?

Yes. So now we're to the U.S. Retail, we'll give you the Canada as well, and Gary Arthur is here who runs our Retail, so...

So, yes. The same-store gasoline was up 2.5% for the first quarter versus a year ago. We continue to benefit from the strength of the Texas market where we have about 600 of our 1,000 company-operated stores. So Texas continues to be very, very strong. We're a little bit weaker in the West, and I think that's a reflection of both the economic climate not being quite as strong and competitive pressures that we see in that market.

How about in April so far?

April so far, we're about where we were in March, about even with March, and on a same-store basis on gasoline, we're down about 7/10 of 1%. When you adjust for the fact that we have 5 Sundays in the month of April this year versus last year, Sundays being our slowest day of sales, so when we adjust for that, to get a true comparison, we're down slightly.

And then when you say in the first quarter up 2.5% in benefit, correct me, from the Texas strong market. If we would strip out Texas, then what does your overall same-store sales look like?

If we stripped out Texas, I would tell you, we would be down slightly.

So less than 1%?

Yes, I would say less than 1%.

But that reflects California, Colorado…

Arizona.

And Arizona, which…

Wyoming. Those 4 markets.

But Arizona is down significantly, and so has been Colorado, right?

That's right.

Bill, final question. It looked like that in many of the shale oil plays, the liquid production coming out of your NGL and condensate, and black oil may be actually less than 50%?

Paul, I missed a couple of words. Oh, shale…

I'm saying that in many of the new shale oil plays, whether it's in Eagle Ford or even in the Permian Basin and all that, the new liquid production increase looks like it's going to be NGL and condensate, and maybe less than half is black oil. So do you see that as an opportunity for you to bring more of the condensate in your system or that you build some condensate splitters to take advantage of, potentially, an oversupply of condensate?

So you have a lot of questions there. In the Eagle Ford, the quality of the oil has actually been better than what was originally expected, that being it's a little heavier. So it's better quality oil. So we are running -- Joe told you, but we're running 100,000 barrels a day, and another month or 2, we’ll be even higher between Three Rivers, Corpus Christi and Houston. We are actually taking some to Houston. So that's been the higher quality. Some of the other basins, we're not really connected to, so it's been kind of an academic question so far. And obviously, the stuff in the Panhandle, Ardmore, has all been good quality oil. So now to condensate, yes, we would agree with all the chemical companies, from NGLs to condensates, that we see this -- and how you divide them sometimes gets a little hazy there. But we see a significant increase in ethanes, propanes, butanes, all these, geez even the C6's. So, yes, we see that coming to market. That's why I think somebody told me the other day, there is 9 ethylene plants announced, and this is the resurgence of the petrochemical industry in the United States. And we at Valero are looking for ways that we can participate where we bring real value to the conversation. So we continue to look at our options. But yes, your general statement is absolutely true. There is a significant increase in NGLs and condensates.

Our next question comes from Faisel Khan from Citigroup.

It’s Faisel from Citi. On the Memphis refinery, I know you guys have access to the Capline pipeline system. What's your ability as a major customer on that pipeline to influence its reversal?

We would probably have no influence at all. We're not an owner. It's Plains and Marathon and BP. Is that right?

Yes.

Plains, Marathon, BP. And they're the owners of the pipeline, and they own the pipeline.

Okay. Understood. Can you give us an idea how your Eagle Ford crude is pricing into your refinery systems today?

Yes. It’s pricing off of LLS minus the discount.

And we have a posting, and it's posted there, which you could look up, but I think it's LLS minus $6. But it's a posting, so it's readily available to anybody.

And our next question comes from Jeff Dietert from Simmons. Jeffrey A. Dietert - Simmons & Company International, Research Division: I was hoping you could talk a little bit about the hydrocracker integrations at Port Arthur and St. Charles. And what's required with those plants, how does that impact the operations, the facility as you tie those hydrocrackers in?

So Lane Riggs that runs Refining is with us, and Lane is going to answer you.

So in terms of -- we anticipate starting up Port Arthur as mentioned earlier, in the second half, and then we'll finish mechanical completion on St. Charles right at year-end. We have start-up teams on the ground already, working to get these things started up over the licensors and our own internal refinery experts, and we have a pretty good strategy in terms of trying to acquire feed -- getting the feedstock for them, and so we're working through all that.

And then I guess on the product side, we've got, Jeff, we’ve got this stuff in place to move the barrels out. I mean, we're -- at Port Arthur, we’re looking forward to having the high-quality, high-cetane diesels that we've put out in the market and export. And then at St. Charles, we’ve got the export capabilities, plus we're doing Parkway Pipeline project, which will allow us to move barrels out of that market up to Collins and then into Plantation or Colonial.

So Jeff let me go back and add a little more to Lane. So -- but the process we're checking, so it's mechanically complete, and then we have to check out these -- check it out here, and that's going to take us 3, 4 weeks. Then we have to do some pre-treating. Then you have to load the catalysts. So when you actually look at this thing, even though we've been training our people here for a year, actually, from mechanical completion to the point of starting up here is really going to take us between 60 and 90 days. So that if you actually look at this, where I've told some of you guys we could get this done in 6 weeks to 8 weeks, it's really going to take us a little longer than that because of some of the catalysts. Remember, these are high-pressure units running at 2,200 pounds. So we really won't see the benefit of the unit at Port Arthur until the fourth quarter in the P&L, and the same would be true at St. Charles. It'll probably spill to very late in the first quarter or actually see the full benefit in the second quarter. Jeffrey A. Dietert - Simmons & Company International, Research Division: Gotcha. Very helpful. And does the integration impact the throughput into the crude unit?

Jeff, this is Lane again. No, we did all the tie-ins and all that tie-in work on previous turnarounds, so we don't anticipate a throughput on the rest of the refinery to start these up.

Our next question comes from Blake Fernandez from Howard Weil.

I hopped on a tad late, so I apologize if you covered this, but I had a question regarding the opportunity cost of the downtime in the first quarter. Obviously, a very heavy turnaround period, and that weighs on your efficiency and capture rates. I'm curious if you can give us an idea of what your kind of normalized earnings may have looked like had you not had that downtime.

Blake, our estimate for first quarter impact was about $170 million.

$170 million. And that's pre- or post-tax, Ashley?

That's pretax.

Okay. And then I guess, I get somewhat related to that, obviously, as we move to kind of a more normalized run rate and, hopefully, cash flow improves, the buyback run rate in the first quarter is about $100 million. Should we think that, that run rate kind of improves heading into 2Q with, hopefully, improved cash flow?

I would not make that assumption. It is tied to the free cash flow. I have said that we will look at our dividend again in July as we completed the Port Arthur hydrocracker. We also have $750 million of debt that matures here in April.

We've already paid.

We already paid. We also actually called $107 million of tax exempt debt that was economic to call, and that gets paid, right here, first of May.

Right, it's later this week.

Later this week. So we are also working the interest rate arbitrage that you have on our debt. So there's things that we're doing with our cash. But our intent, Blake, is to return cash to the shareholders as we’ve said and have one of the highest yields among our peer group, and we continue to do that, and we think our equity is still very inexpensive.

Our next question comes from Rakesh Advani from Crédit Suisse. Rakesh Advani - Crédit Suisse AG, Research Division: I know you guys had highlighted that you're seeing a pretty strong export environment. I just kind of wanted your views on how long do you think that would -- is going to last for and what the impact of Motiva will be on it.

Well, I'll tell you, you said it, and it's true. I mean, the export markets are very strong right now. I mean, diesel growth and demand abroad is very high. We’re seeing diesel exports, not perhaps at the highest levels they've ever been, but certainly, very near that. And for the quarter, we exported 170,000 barrels a day of diesel. The bulk of that went to Europe. The rest of it went to Latin America. On the gasoline side, we're also seeing strong demand there. And again, gasoline exports are at very high levels historically. And for the quarter, we exported 80,000 barrels a day of gasoline, most of which went to Mexico and Latin America. If you look at the factors that are affecting the export market going forward, I mean, they're not factors that can readily change. I mean, Chile is importing as much, if not more, distillates as they ever have, and their demand continues to grow. So far this year, they're importing 83,000 barrels a day. Mexico's diesel imports were 105,000 barrels a day, and their Refining capacity just doesn't meet their internal demand for products. If you look at what's happening on the gasoline side, you've got Venezuela with capacity off-line. We've got Hovensa shut down, so that production is out of the market, Mexico gasoline imports have averaged 392,000 barrels per day. That's up 5% over the previous year, and Petrobras is importing significant volumes of gasoline and diesel. So all of these are based on solid economic activity and lack of supply. And so these aren't things that readily get addressed. Now how will Motiva affect this? Well, obviously, anytime you're going to put more product into the market, you're going to offset other product unless there's growth in the market. And so, who would be at risk in this case? It would be the marginal caps [ph]. It would be the marginal refiners, and that's not us.

I think I would add to this that Joe mentioned Hovensa is down. We've shut Aruba down. Aruba made distillate. It did not make gasoline. Marcus Hook is down. Trainer is down, but I guess it's coming back. So if you look at just the basics in the U.S. supply, even though some is East Coast, some is Gulf Coast, really Motiva is just kind of filling in a void that these refineries have left. So I think, initially, there'll be some logistics as people try to jockey things around. Some will go in the pipelines because Colonial has done an expansion. Plantation has some room. And some will get exported, but on the other hand, there's been refineries taken off-line, and just remember that Curaçao is limping along. And obviously, the Venezuelans are really no longer in the export market. Rakesh Advani - Crédit Suisse AG, Research Division: Okay. And just one final one. I know on your slides that you put on your presentation you've talked about the Brent to LLS inversion. You've kind of given the range, I guess, maybe between 2014 and '15 where you could see an inversion based on 2011 imports of light to medium sweet crude. I guess the recent data from the EIA is showing that imports of that kind of crude is only averaging about 510,000 a day. Do you think this would kind of alter your view on maybe it happening even sooner than expected?

Well, I think it's a very fair question. Remember on our slide, there is a little bit of a dilemma of where you make the cut between some of the lights and the mediums. So if you're looking at our slide, let's just stick with our numbers and -- because we probably have some medium crude in there. But basically, the U.S. is going to push out of the Gulf Coast the light-sweet crude. Now it is happening quickly. Eagle Ford production is increasing dramatically, and that is getting to the Coast. Some of the other crudes, Enterprise says they're going to start up -- Enterprise, Enbridge will start up Seaway here in May, right? In May, don't forget you have Magellan on Longhorn, so you have all these things that are going to happen in the next year. So all that crude is coming. The big piece of that, though, I will remind you and our assumptions is that BP at Whiting where BP’s heavy-up [ph] project, and so that's a big, sort of like 200,000 barrels a day of the volume that basically gets pushed back into Cushing. So we still think it's a '14, '15, but your question is correct. It makes a little difference where you're cutting the lights and the mediums.

Our next question comes from Sam Margolin from Dahlman Rose.

You mentioned Seaway. I was curious if you have any guidance for Seaway barrels that you might be buying for 2Q or later than that? I guess it’s starting up, as you mentioned, within the next couple of weeks here.

Well, we're not a shipper on Seaway. It will just be availability of barrels on the Gulf Coast.

Okay. And for those, that would be, they'd already be repriced at LLS once they get there?

Well, I guess. It just depends on how many of them there are.

All right. Lastly, this is more of a macro question. There's been a lot of sort of outside-of-industry interest in refining assets. Presumably, it's just a reaction to simple coastal cracks expanding. It seems like the benefits of this capacity rationalization that we saw lead to events that sort of offset those benefits down the road when you get restarts. Are you concerned about the levels of light-sweet cracks here on the coast as we get restarts and sort of private equity or outside buyers chasing the market?

Well, we believe there's still too much refining capacity in the U.S., as well as certainly, Western Europe. So the Atlantic Basin has too much refining capacity. So how does the industry balance it? It balances by reducing operating rate. And so, as these plants, certainly as Trainer appears that it's going to come back into the market, it's going to put some refined product back in there, and that will affect the operating rates. But the industry is slowly rationalizing capacity. It just does. Some things die hard.

Our next question comes from Doug Terreson from ISI Group.

Can we just summarize your comments on U.S. gasoline and diesel demand to say that it appears from your -- and I know this isn’t perfect -- functional and geographical perspective that we may be gravitating towards maybe minus 1% to 0% growth year-to-date? Is that kind of consistent with what you were saying earlier?

Well, certainly, it's down. Gene is going to give you his comments.

This is Gene. If you look at the monthly data or the weekly data that’s come out, it looks like gasoline demand has been off about 4% year to date. But something interesting, the DOE just published the February monthlies, which is all the revised data. And I think they we're missing exports last year on gasoline. They were understating them. This year, they've been overstating them. Also some discrepancies on naphtha, whether it's a blend stock or a chemical feedstock and how that gets categorized. So when they published the February data, they actually revised gasoline demand up by 300,000 barrels a day, which put it basically flat to last year. So this was February. In January, we had a similar thing going on. We won't really have the March data until a month from now, but it looks like gasoline demand is a lot flatter than last year than what the all the other data has been showing so far. [indiscernible] distillate, it got revised up. The month -- the weekly data showed it's about flat to last year. The monthly data says it's up about 2% versus last year.

Okay. And Gene, that's consistent with what you guys are seeing in your markets?

Exactly.

And also Bill, you mentioned a minute ago about the resurgence in the petrochemical industry, something along those lines, and so you mentioned you might be interested in participating in the value chain. And so to the degree you're interested, could you comment on what you mean by that? And does that include grassroots petrochemicals?

Well, I don't know if it includes grassroots in the sense of businesses where we don't participate. I mean, you need to bring some value to this conversation. But we make benzene, toluene, xylene and we make a lot of propylene today. I'm sure we do something else. Is there anything else we make? But we're big in propylene here. So we've looked at mixed xylenes. Obviously, these condensates, actually I think, will replace some oil long-term into gasoline. So there's a lot of that type of thing, and we're looking at how do we take advantage of this because if you think strategically about Valero, we largely make fuel, and 80% of our output is fuel, and it doesn't necessarily all have to come from oil.

And our next question comes from Paul Sankey from Deutsche Bank.

Just a follow-up to an earlier comment that you are running about 200,000 a day of I think it was WTI-linked is perhaps how you described it, and you had several projects underway to double that. Firstly, what's the timeframe on those projects? And I guess the big question here is how much more light-sweet U.S. crude you believe you can run on a longer-term basis and how much that would cost?

Well, let me answer you then, and Joe can add to this. What -- at Three Rivers, Corpus Christi, we’re approaching about all we can run without getting some -- without a permit option and a project. And that number is going to be a hundred and do you guys have [indiscernible] Ashley?

About 140,000, yes. 130,000.

Including Houston or no?

No. That would not…

110,000 at Corpus and at Three Rivers, and then we're doing 30,000 or so at Houston. Then we have numerous pre flash options and things that allow us 30,000 here, 40,000 there, at some of our other plants, which we can do because it loads up our light engine. Beyond that, we are still basically a heavy complex coking refiner. And we still believe, strategically, that the Keystone Pipeline is going to be built. It's going to be built on Obama's time scale, which is first quarter of '13. We think that there will be approval if he wins election and that the pipeline will get done here by the end of '14 or early '15 and that heavy crude oil will come to the U.S. Gulf Coast. So -- but Valero still brings value in being able to operate these coking-type refineries. And it'll all be driven economically with our LPs, which will squeeze in as much of the light crude if it's priced properly.

Bill, that list got me 200,000 of existing. Where's the extra 200,000 coming from?

If we take a look at what we can do, you can swing Houston to run 100% light-sweet. Now this is all assuming that the economics makes sense for us to do this. You can run more light-sweet crude in Texas City, and we could run light-sweet crude in Port Arthur.

Okay. So I'll give you some numbers because obviously we do all this work. We could run about 85,000 at Houston, 40,000 at Texas City, 40,000 at Port Arthur, 20,000 at St. Charles and 50,000 or so at Meraux and so, we can do those kind of things so...

Is that with no extra spending that you could get there?

There is some spending but minor, very minor.

And then if there was -- sorry to just press the subject a bit, but it's very interesting and a very big story as far as we're concerned...

Well, it's because every company you will talk to is going to try to do what I'm speaking.

Yes. And what do you think -- what would be the next leg if you wanted to -- let's say, for example, Keystone was not approved or it was uncertain for another 3 years, 4 years, whatever? Would you -- what would you do then?

Well, what we would be forced to do is look at being able to run more light-sweet -- light and medium crudes in some our refineries, because it would all be dependent on what the diff is for the heavy sour.

Yes. What -- so to take the second part of that first, what is the discount? I mean, does -- I think there's an approximate number to think about for how much discount or premium of heavy oil, whatever it is that would cause you just to say, okay, all light-sweet from here?

Well, we think that between in a SUN coker, between 10% to 12% of the price, you can run a SUN coker and make money. And if you would drop down, if you get down to 8%, 7%, if you still have $100 oil here, you're running out of economics on the coker. You think so, Gene?

Probably so. A lot of it depends on where the medium sours are too. Today, medium sours are running between $5.50, $6 discounts to LLS, so we are still seeing good margins to run the medium sours in those sort of refineries versus sweet. And then they'd look at the medium sours, it's going to be a switch between that and the heavy sours so that’s about a $6 spread as well between those 2.

And so this is what Gene's getting into more detail is this is what happens every single day here. We have a whole department that runs these models for us, and it would just be -- if we don't have the discounts out there for heavy sour, we're optimizing the system all the time. Remember, we're buying our oil every day.

But what I'm wondering, Bill, is at what point would you actually start investing to up your light. I mean, obviously, I guess you wouldn't do that until you were sure Keystone was not going to happen.

Well, we would -- we might do some pre flashing. But the issue you went into, quite frankly, is you load up your gas plant and your light end capability. And so those projects certainly become bigger. And then we have to be honest. In the world where we live in today, it is extremely difficult to get these permits as long as we have to do CO2. In Texas, it's terrible, and Kim's here, and she's telling that even in Louisiana and other states, it's extremely difficult now.

And that's because you get more CO2 with a light-sweet crude?

Well, because we may have more heaters, you got more process, so if we trip -- yes, go ahead, speak

Right, so if we trip them into the tailor [ph] and roll the CO2, now we have to cover CO2 in our permits, whether you're in Texas or any place else for -- if we hit that major level so...

Okay. Is there any sense of what level is? Sorry to keep pressing on this, but it's kind of crucial.

No. I think it's 75,000 or 100,000. I mean, if the tailoring rolls, it's a threshold that's higher than it would normally be to trip it, but still, almost any significant project will trip it.

That's really interesting...

But that now makes -- us and everybody else has to get a permit that addresses the CO2.

But I think, as just a final point, you don't expect the crude export ban to be lifted, right?

We do not.

Is there a specific reason for that, Bill, or is it a general kind of opposition to raise -- what would effectively raise crude price in the U.S, I guess?

It's just we just have felt that, that's going to be very difficult to have happen. But I wouldn't say we're giving you a scientific or any better answer here than you would have yourself.

Our next question comes from Evan Calio from Morgan Stanley.

Just maybe some follow-up on this broader Gulf Coast impact from U.S. production growth. I mean, just beyond maxing out light runs in your system, which clearly isn’t optimal -- at current differentials isn’t optimal for many of your refineries you just detailed. But before any major Canadian solution is available, as a next step, I mean, can you talk through the -- an increased kind of blending opportunity here with the overload of lights to kind of blend into some of these medium crudes to press those discounts or re-create those. Is that -- I mean do you -- how do you see blending playing out when you have, essentially, a system in the Gulf of Mexico and you could debate the time based upon what you think production growth date is, where you're going to back out at least one type of crude at some point that you can debate the timeframe. But over the next couple of years, how does blending kind of play into that?

Well, it's a very good question. Now we aren't blending or anything at a terminal, so this is all at refineries. Now we are, at St. Charles and at Corpus Christi, putting in facilities that will let us run a broader selection of crudes, and then we will blend them for the process unit, because we'd like to show the process unit a relatively steady diet here of crude. So we actually have -- 2 of our plants have projects underway right now. One is tankage. One is a lot of pipe, to allow us to blend crudes for the unit, which would let us run a broader spectrum of crude. And we're looking at the same type of projects for the other plants as well. So we're doing it at the refineries, and it lets us then optimize that crude cost.

Does the blending raise the potential ceiling of a light-sweet diet that's ultimately kind of blended into something else before it's run versus what you stated?

Yes. We would optimize -- this is a little bit of -- you're asking something here, so we're going to give you -- this is how we view it, all right?

This is Lane Riggs. So the numbers you heard from Bill earlier in terms of the amount of light sweet crudes into each one of the refineries is pretty much the number on a blended basis into these refineries up to sort of a light ends constraint or a crude tower shell capacity constraint making -- backing out medium sour or light-sweet in that refinery.

Okay. So there’s not an incremental back-out of any kind of medium barrel -- if the price allowed it without a front-end investment?

We would. We look at the relative value of these domestic sweets or any sweets for that matter versus the medium sour, and we increment up to a constraint on the refinery, and that's so -- the numbers that Bill had given you earlier is roughly our constraint to a light end constraint or a shell capacity. Probably backing out depending on the refinery whether it could be medium sour or sweet.

Okay. Understood. A different question on Keystone South. I didn't know if you've had this in your comments, but then would you have to nominate in that line to maintain a position in the Keystone XL, the transnational line?

No. They're reserving the space in the South segment for those that nominated space on the -- as part of the bullet line.

Right. But if you ultimately wanted -- if you didn't take Keystone South capacity, would that negatively impact your ability for your nominations when the line is ultimately...

From Hardisty. No, it would not affect our commitments from Hardisty South. We have our space. The committed shippers on the northern segment will have their space all the way down. Now when I ship from Cushing South, then we need to nominate incremental space. In other words, we've got our space all the way from Hardisty to the Gulf. But if we just say we want to move Mid-Continent barrels from Cushing South in addition, we would need to nominate.

Understood. And then maybe lastly, do you have any closure cost estimate on the Aruba Refinery, what that...

As of today, we've just suspended operations. So we are working all our options and still continue to work our options. And so, it's a different situation than some of the other numbers that you've seen in the marketplace. But ours would be less than $100 million, but the facts are that's not what -- we're working really some options here that will be good for our shareholders.

Okay. Wow. Maybe you could sell to Delta.

Our next question comes from Arjun Murti from Goldman Sachs.

Sorry to go back to this, but just so I'm understanding the light sweet ability in the Gulf Coast, you can do 200,000 today. To do another 200,000 requires some modest amount of investment and then to go beyond that, you have the issues with the permits and more meaningful CapEx? Am I understanding that correctly?

That's correct.

Any quantification on how much minimal investment is and the timeframe to do it?

Not much. Like Bill said, we would -- to do more than we have the capacity today, we'll have to put some pre flash towers in some of our heavy sour locations because the shell capacity of those towers really were designed to run a heavier diet. So it'd be tough...

No, I don't think we have a good number for you.

Okay. And then separately, you talked about ongoing portfolio optimization. You've obviously taken the action at Aruba and the East Coast plants. Where does the California fit in terms of how you see it as part of your system? Clearly -- or presumably not as bleak of an outlook as the East Coast. Do you see any light at the end of the tunnel there or any other actions you can take to improve your California outlook?

Well, Arjun, we are taking action. Our costs at Benicia are too high, and we've been addressing that to get our per barrel cost down and we continue to work that. But the California market is a big market, and we still have 11% unemployment in California, so they have many, many economic issues in the state. The thing that is struggling to us is that their policies, primarily from CARB, are extremely anti-business, and the consumer really does not understand how much his prices are going to go up, which is what CARB wants so that they get the conservation. So you asked a proper question. We’re trying to optimize our portfolio so that we can compete long-term, and we're trying to evaluate all of these issues and what our real potential is on the West Coast.

Would separating it from Valero make sense? And is that a consideration for you?

I hadn't thought of -- you mean like separate it into a freestanding business?

Yes, Valero California, whatever you want to call it. Separate company, spun out from Valero Corp.

We have not looked at that.

Our next question comes from Chi Chow from Macquarie Capital.

Sorry to circle back on the light sweet issue one more time. So if you put in these flash towers with minimal CapEx, does that change your crude flexibility at all going forward? In other words, can you swing back to the heavier barrel, if need be, if prices are correct?

Yes, we can. You guys are asking us things that we have not engineered here. So we're off in a thing here -- the conversation is probably 4 years out. But yes, if we -- if that's what happens. But I want to emphasize what we do every day and, frankly, what all our competitors do every day is they're running their LPs, and they play -- they go to a crude mix that they believe is optimal for that facility. And what we're doing right now is we're building some tankage at St. Charles, we're doing work at Corpus Christi, that allows us to blend crudes, give us more flexibility here so that we can run and buy some other crudes that are priced economically.

When they're available?

When they're available. But as this volume continues to increase, we, as everybody, will wind up being able to run more of this light and medium crude oils. Because we will do things around our plants to let us do it, because we do believe that LLS is going to sell at a discount to Brent, and that's the main point that will drive you that way.

Right. Mike, a couple of quick items. What's the remaining CapEx on the hydrocrackers as of the end of the first quarter? And did I hear you right that the debt maturity in April, you paid that off?

Yes, we paid off the debt maturity, the $750 million. The remaining capital on the hydrocrackers, it's about -- Port Arthur, we look like we have about $300 million left and on St. Charles about $500 million left.

Just so you know, there's a couple other little projects around there that are finishing as well.

Our next question comes from Faisel Khan from Citigroup.

Just a follow-up. In our discussion around the incremental amount of light-sweet crude you could run in the Gulf Coast, where does Memphis fit into all this? I mean, clearly, I think that's consuming LLS benchmark crudes. So what kind of crude slate is that consuming? And how would that benefit from an LLS discount versus Brent?

Well, it will benefit in the sense that -- what product prices are. But your observation is correct. Memphis runs an LLS plus because Capline flows north. So this goes all the way back to a question earlier that someone asked about Capline going south. Also, some crudes can come into the refinery by water as well, but the plant runs LLS plus. It does have a very strong local market though. It has -- I guess it's -- the largest rack in our system are very close, and we have a big customer for turbine fuel, and so we operate in more of a regional capacity at the Memphis plant.

Okay. And on the hydrogen plant investments that came online I believe you said in the first quarter here, you gave us some guidance in your slide presentations of around $100 million in EBITDA was your base case, and I think using 2011 prices, you said about $176 million using LLS, but I assume that was based on last year's natural gas prices. So I was trying to figure out what the lower gas price for this year means in terms of potential uplift for that investment.

The guys are looking it up. Remember, at McKee, we had the catcracker down. We're still running some oil there, but we have a big turnaround going on. So the McKee hydrogen plant has not run to capacity yet. We’ve got the numbers here.

Faisel, this is Ashley. For every dollar change in the price of natural gas per MMBtu, it adds about $6.5 million a year in EBITDA, and based on the '11 pricing, we're effectively using $4 natural gas. So you could easily -- on your call, whatever your call on natural gas is, it looks like at least $1 lower, could be more.

Our last question comes from Harry Mateer from Barclays.

A quick one from me. Mike, can you just confirm the April maturity? Did you pay that down with cash on hand? Or did you use the bank facility or the AR line?

We have dipped into our AR line a little bit while we paid off this maturity. But we started the quarter with $1.6 billion of cash.

Okay. So what -- it would help maybe you can -- what's the pro forma debt number, I guess, we should be using?

I guess...

We're probably going to go ahead and issue some tax exempt bonds that we have the ability to do. So if you want a good number, I'm going to say to you 7 1 or 7 2.

We have no further questions at this time.

Okay, thank you, John. And I just wanted to thank the investors for listening to this call. If you have any questions, please contact the Investor Relations department. Thank you.

Thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect.