Welcome to the Valero Energy Corporation report's first quarter 2012 earnings conference call. My name is John, and I'll 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.
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 is 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 gross 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 2011. Gulf Coast ULSD margins per barrel versus LLS remained very good and increased slightly from $13.59 in the first quarter of 2011 to $13.68 in the first quarter of 2012. 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 averaged 2.6 MMbpd . That was up 449,000 bpd from the first quarter of 2011. The increase in throughput volumes was mainly due to the addition of capacity from the acquisition of the Pembroke and Meraux refineries. Refining cash operating expenses in the first quarter of 2012 were $4.15 per barrel, which was higher than our fourth quarter 2011 due to lower throughput volumes and higher maintenance expense. It was lower than our guidance of $4.50 per barrel, mainly due to higher throughput volumes and lower energy costs than we expected. Our ethanol segment reported $9 million of operating income, which was down $35 million from the first quarter of 2011, mainly due to lower gross margins as ethanol prices were pressured by excess industry supply.
Even with lower margins, the ethanol segment operated well and achieved two quarterly records: the highest average production rate at 3.48 million gallons per day, and the lowest cash operating expense per gallon at $0.28. Our retail segment reported first quarter 2012 operating income of $40 million, consisting of $11 million in the U.S. and $29 million in Canada, which was down from the first quarter of 2011, mainly due to lower fuel margins. In the first quarter, general and administrative expenses, excluding corporate depreciation, were $164 million, which was in line with guidance, but above fourth quarter 2011, mainly due to legal settlements that favorably impacted the fourth quarter of 2011 results.
Depreciation and amortization expense was $384 million, net interest expense $99 million, and the effective tax rate in the first quarter was a negative 28%, but adjusting for the Aruba impairment, the effective tax rate was 37%. Regarding cash flows in the first quarter, capital spending was $884 million, which includes $158 million of turnaround and catalyst expenditures. Our expected capital spending for the full year 2012 is consistent with our previous guidance at around $3.5 billion. Also in the first quarter, we returned $189 million in cash to our shareholders as we paid $83 million in dividends and spent $106 million to purchase 4.5 million shares of our common stock. With respect to our balance sheet at the end of March, total debt was $7.6 billion, cash was $1.6 billion, and our debt to cap ratio net of cash was 27.4%.
At the end of the first quarter, we also had over $4.6 billion of additional liquidity available. We made several notable improvements to our refinery system in the first quarter. We started our hydrogen plants at Memphis and McKee, which benefit from high oil and low natural gas prices and were two of our key economic projects. In addition, we completed large turnarounds at our Wilmington and Memphis refineries, and we began a very large turnaround at our St. Charles refinery, which we just completed last week. Included in St. Charles work was a project that replaced coke drums to improve reliability. Regarding key capital projects in progress, our two hydrocracker projects at Port Arthur and St. Charles remain on budget and on time for completion in the second half of this year.
These projects were designed to capitalize on high crude oil and low natural gas prices while producing diesel and gasoline to meet the growing global demand. We look forward to completing these projects and enjoying the expected benefits to cash flow. Now I'll turn it over to Ashley to cover the earnings model assumptions.
Okay. Thanks, Mike. For modeling our second quarter operations, you should expect the refinery throughput volumes to fall within the following ranges: Gulf Coast at 1.44 MMbpd - 1.48 MMbpd , Mid-Continent at 380,000 bpd- 400,000 bpd , West Coast at 275,000 bpd- 285,000 bpd , and North Atlantic at 440,000 bpd- 460,000 bpd . 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 planned 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 a 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, and now I'll open the call to 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 Doug Leggate from Bank of America. Please go ahead.
Thanks. Good morning, everybody. I have a couple of quick ones, hopefully. My first one is really on the crude charge. We have obviously seen another
I guess, extend a relatively extended period of very attractive WTI and I guess inland discounts relative to waterborne crude. I am just curious about, I imagine you are trying to optimize your runs, if you could just give us an idea as to how, if any, changes that you are making or have made in terms of trying to gain greater exposure to those spreads. I have a couple of quick follow-ups for you.
Okay, Doug, this is Joe. Listen, obviously we are. We are 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. We also ran more medium sour crude, and we basically backed out resid. We continue to look for opportunities to optimize the overall slate. When we think in terms of what are we doing in the Gulf Coast here and what do we think the market is going to look like, the Brent to LLS spread or LLS to WTI spread could be anywhere from $5-$25 over the next year. None of us really have any idea as to what that is going to be. We do believe, though, however, that longer term, that is going to come into $3-$4.
I think this view would be supported by the fact that Seaway pipeline tariff is in that range or slightly below that. We know that domestic production of light sweet crudes is continuing to grow, and it's going to continue to do so over the next several years. 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. These crude prices, the discounts are going to continue to come in. In the 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.
That's our plan, and that's what I got for you.
Thanks, Joe. My follow-up is related actually, because you guys periodically have dabbled with hedging, and I'm just curious if you have that view that the spreads are potentially coming in over time. I'm just curious if you're tempted to try and lock 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-Continents to the U.S. Gulf Coast. We shifted our feedstock hedging from a WTI-related basis to a Brent-related basis. 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. 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.
Then your question goes broader to our hedging program. We do or our training program. We do things from time to time, Doug, but nothing material.
All right. I'll leave it there. Thank you.
Our next question comes from Paul Cheng from Barclays. Please go ahead.
Hey, good morning, guys. Mike, can you give me a number of the balance sheet item in terms of working capital, long-term debt, the market value of your inventory in excess of both?
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.
Right. The cash is already included in the $15.8 billion that you gave, right?
That's correct.
Okay.
Okay. Market value of our inventory is $14.2 billion, and value in excess of LIFO is $8.7 billion. Total debt, which includes—
No, long-term debt.
Yeah. $7.6 billion. Stockholders' equity, $16 billion.
$16 billion in stockholder equity. Perfect. Bill, I'm wondering, if we're 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 systems, that we're not going to give you any going forward how we're doing on the particular plant.
This would be the last time.
Okay.
At Meraux, we've had a very tough start. However, we've had a turnaround. We've several turnarounds. We had high crude costs come through. Now as we get starting here into the second quarter, we think Meraux is going to fit very well. You ask about Pembroke. Pembroke has largely been break even at the refinery. Marketing's done a little better, but basically, I'd just say to you, it's been a break even. 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. Just to give you an idea, in April, Pembroke is very profitable.
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 six months.
Still in Pembroke or your overall experience in Europe, does it in any shape or form 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've just had to make some changes in the way Valero does business. We had Joe Gorder over there, and he's made a lot of changes. 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 large refining overhang in Europe.
As we see these plants coming on the market, we're just going to be 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. Now we're to the U.S. retail, and we'll get you to Canada as well, and Gary Arthur's here, who runs our retail.
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. Texas continues to be 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. On a same-store basis on gasoline, we're down about seven-tenths of 1% when you adjust for the fact that we have five Sundays in the month of April this year versus last year, Sundays being our slowest day of sales. When we adjust for that to get a true comparison, we're down slightly.
Oh. Then when you say in the first quarter, up 2.5% and benefit greatly from the Texas strong market. If we strip out Texas, then what does your overall same-store sale look like?
If we stripped out Texas, I would tell you we would be down slightly.
Less than 1%?
Yeah, I would say less than 1%.
Okay.
That reflects California, Colorado—
Arizona.
—and Arizona with Wyoming, those four markets. Arizona's down significantly, and so has been Colorado, right?
That's right.
Bill, final question. It looked like that in many of the shale oil play the liquid production coming out as NGL and condensate and black oil may actually be less than 50%.
Hold on. I missed a couple words.
Okay. Sorry.
Okay, go ahead.
I am saying that in many of the new shale oil play, whether it is in Eagle Ford or even in the Permian Basin and all that, the new liquid production increase looks like it is going to be NGL and condensate, and maybe less than half is black oil. Do you see there is an opportunity for you to blend more of the condensate in your system or to build some condensate splitter to take advantage of potentially an oversupply of condensate?
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 is a little heavier, so it is a better quality oil. We are running, as Joe told you, but we are running 100,000 bpd . In another month or two, we will be even higher between Three Rivers, Corpus Christi, and Houston. We are actually taking some to Houston.
That has been a higher quality. Some of the other basins we are not really connected to, so it has been kind of an academic question so far. And obviously the stuff in the Panhandle, Ardmore has all been good quality oil. 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, even the C6s. Yes, we see that coming to market. That is why I think somebody told me the other day, there are nine ethylene plants announced, and this is the resurgence of the petrochemical industry in the U.S. And we at Valero are looking for ways that we can participate, where we bring real value to the conversation. We continue to look at our options. But yes, your general statement is absolutely true. There is a significant increase in NGLs and condensates.
Thank you.
Our next question comes from Faisel Khan from Citigroup. Please go ahead.
Hi. Good morning. It is Faisel from Citi. On the Memphis refinery, I know you guys have access to the Capline pipeline system. What is your ability, as a major customer on that pipeline to influence its reversal?
We would probably have no influence at all.
Okay. Understood.
We're not an owner. It's Plains and Marathon and BP.
Yep.
Is that right? Plains, Marathon, BP?
Yes.
They are the owners of the pipeline, and they own the pipeline.
Understood. Can you give us an idea of how your Eagle Ford crude is pricing into your refinery systems today?
Yeah. It is pricing off of LLS minus a discount.
Okay.
We are posting, and it is a posted deal, which you could look up, but I think it is LLS - $6. Yeah.
Okay, great. Thanks. I'll get back in the queue.
It's a posting, so it's readily available to anybody.
Okay. Thank you.
Our next question comes from Jeff Dietert from Simmons. Please go ahead.
Good morning. I was hoping you could talk a little bit about the hydrocracker integrations at Port Arthur and St. Charles and what is required with those plants. How does that impact the operations of the facility as you tie those hydrocrackers in?
Lane Riggs, who runs refining, is with us, and Lane is going to answer you.
In terms of, we anticipate starting up Port Arthur, as we mentioned earlier, in the second half, and we will finish mechanical completion on St. Charles right at year-end. We have startup teams on the ground already working to get these things started up with the licensors and our own internal refinery experts. We have a pretty good strategy in terms of trying to acquire getting the feedstock for them. We are working through all that.
Then I guess on the product side, Jeff, we got the stuff in place to move the barrels out. At Port Arthur, we are looking forward to having the high quality, high octane diesels that we put on the market and export. At St. Charles, we have got the export capabilities, plus we are doing the Parkway Pipeline project, which will allow us to move barrels out of that market up to Collins and then into Plantation or Colonial.
Jeff, let me go back and add a little more to Lane. The process we are checking, so he is mechanically complete, and then we have to check it out here, and that is going to take us three, four weeks. Then we have to do some pre-treating, then you have to load the catalyst. When you actually look at this thing, even though we have been training our people here for a year, to actually from mechanical completion to the point of starting up here is really going to take us between 60 and 90 days.
If you actually look at this, where I have told some of you guys we could get this done in six weeks to eight weeks, it is really going to take us a little longer than that because of some of the catalysts. Remember, these are high pressure units run at 2,200 lbs .
We really will not see the benefit of the unit at Port Arthur until the fourth quarter in the P&L. The same would be true at St. Charles. It will probably spill to very late in the first quarter or actually see the full benefit in the second quarter.
Got you. Very helpful. Does the integration impact the throughput into the crude unit?
Okay. Hey, Jeff, it is Lane again. No, we did all the tie-ins and all that tie-in work on previous turnaround, so we do not anticipate a throughput on the rest of the refinery to start these up.
Very helpful. Thank you, guys.
Sure.
Our next question comes from Blake Fernandez from Howard Weil. Please go ahead.
Good morning, guys. 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 am curious if you can give us an idea of what your normalized earnings may have looked like had you not had that downtime.
Yeah. Hey, Blake. It is our estimate for first quarter impact was about $170 million.
$170 million. That is pre or post-tax, actually?
That is pre-tax.
Pre-tax. Okay. I guess somewhat related to that, obviously as we move to 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 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 pay in—
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, 1st of May?
Right. Later this week.
Later this week. We are also working the interest rate arbitrage that you have on our debt. There's things that we're doing with our cash. But our intent, Blake, is to return cash to the shareholder, as we've said, and have one of the highest yields among our peer group. We continue to do that, and we think our equity is still very inexpensive.
Got it. Thank you, Bill.
Our next question comes from Rakesh Advani from Credit Suisse. Please go ahead.
Thanks for taking my question. I know you guys had highlighted that you are seeing a pretty strong export environment. Just wanted your views on how long do you think that it is going to last for and what the impact of Motiva will be on it?
Joe?
Well, I will tell you said it and it is true. The export markets are very strong right now. Diesel growth and demand abroad is very high. We are seeing diesel exports, not perhaps at the highest levels they have ever been, but certainly very near that. For the quarter, we exported 170,000 bpd of diesel. The bulk of that went to Europe, the rest of it went to Latin America. On the gasoline side, we are also seeing strong demand there. Again, gasoline exports are at very high levels historically. For the quarter, we exported 80,000 bpd 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, they are not factors that can readily change. Chile is importing as much, if not more, distillate as they ever have.
Their demand continues to grow. So far this year, they are importing 83,000 bpd . Mexico's diesel imports were 105,000 bpd , and their refining capacity just does not meet their internal demand for products. If you look at what is happening on the gasoline side, you have Venezuela with capacity offline. We have Hovensa shut down, so that production is out of the market. Mexico gasoline imports have averaged 392,000 bpd . That is up 5% over the previous year. Petrobras is importing significant volumes of gasoline and diesel. So all of these are based on solid economic activity and lack of supply. These are not things that readily get addressed. Now, how will Motiva affect this? Well, obviously, anytime you are going to put more product into the market, you are going to offset other product unless there is growth in the market.
So who would be at risk in this case? Well, it would be the marginal CASS. It would be the marginal refiners, and that is not us.
I think I would add to this that Joe mentioned Hovensa is down. We have shut Aruba down. Aruba made distillate, it did not make gasoline. Marcus Hook is down. Trainer is down, but I guess is 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 filling in a void that these refineries have left. So I think initially there will be some logistics as people try to jockey things around. Some will go in the pipeline because Colonial has done an expansion, Plantation has some room, and some will get exported. But on the other hand, there has been refineries taken offline. Just remember that Curacao is limping along, and obviously the Venezuelans are really no longer in the export market.
Okay, thanks. Just one final one. I know on your slides that you have put on your presentations, you have talked about the Brent-LLS inversion. You have given the range, I guess maybe between 2014 and 2015, where you could see an inversion based on 2011 imports of light medium sweet crude. I guess the recent data from the EIA showing that imports of that kind of crude is only averaging about 510,000 bpd . Do you think this would 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 delay of where you make the cut between some of the lights and the mediums. If you're looking at our slide, let's just stick with our numbers 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?
Yeah.
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 in our assumptions is that BP at Whiting, with BP's Heavy Up project. So that's a big, like 200,000 bpd 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.
Thank you.
Our next question comes from Sam Margolin from Dahlman Rose. Please go ahead.
Good morning. 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 would just be availability of barrels on the Gulf Coast.
Okay. For those, they'd already be repriced at LLS once they get there?
Well, I guess. It just depends—
Okay.
—on how many of them there are.
All right. Lastly, this is more of a macro question. There has been a lot of outside-of-industry interest in refining assets. Presumably, it is 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?
Am I concerned? Well, we believe there is still too much refining capacity in the U.S. as well as certainly Western Europe. The Atlantic Basin has too much refining capacity. How does the industry balance? It balances by reducing operating rate. As these plants, certainly as Trainer appears that it is going to come back into the market, it is going to put some refined product back in there, and that will affect operating rates. But the industry is slowly rationalizing capacity. It just some things die hard.
Okay. Thanks very much.
Our next question comes from Doug Terreson from ISI Group. Please go ahead.
Good morning, guys.
Good morning, Doug.
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 -1% to 0% growth year-to-date. Is that kind of consistent with what you were saying earlier?
Well, certainly it's down. Gene's going to give you, I guess, our comments.
Okay.
This is Gene.
Hi, Gene.
If you look at the monthly data or the weekly data that has come out, it looks like gasoline demand has been off about 4% year-to-date.
Yep.
Something that is in the U.S. Department of Energy just published the February monthlies, which is all the revised data.
I think they were missing exports last year on gasoline. They were understating them. This year, they have been overstating them.
Right.
Also, some discrepancies on Naphtha, whether it is a blend stock or a chemical feed stock and how that gets categorized. So when they published the February data, they actually revised gasoline demand up by 300,000 bpd .
Right.
Which put it basically flat to last year. This is February. 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 was a lot flatter than last year than what all the other data has been showing so far.
Okay.
Similarly on diesel, I think I revised it up. The weekly data showed it's about flat to last year. The monthly data says it's up about 2% versus last year.
Okay. Gene, that's consistent with what you guys are seeing in your markets?
Exactly.
Okay. Also, Bill, you mentioned a minute ago about the resurgence in the petrochemical industry or something along those lines. You mentioned you might be interested in participating in the value chain. To the degree you're interested, could you comment on what you mean by that? Does that include grassroots petrochemicals?
Well, I don't know if it includes grassroots in the sense of businesses where we don't participate.
Right.
You need to bring some value to this conversation. We make benzene, toluene, xylenes. We make a lot of propylene today.
Sure.
I'm sure we do something else. Is there anything else we make? We're big in propylene here.
Yeah.
We've looked at mid xylenes. Obviously, these condensates, actually, I think will replace some oil long term into gasoline.
Yeah.
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 fuels.
Sure.
80% of our output is fuels, and it doesn't necessarily all have to come from oil.
That's correct. Thanks a lot.
Our next question comes from Paul Sankey from Deutsche Bank. Please go ahead.
Hi, guys.
Good morning, Paul.
Morning. Just a follow-up to an earlier comment that you are running about 200,000 bpd .
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? 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? Thanks.
Well, let me answer you then, and Joe can add to this. At Three Rivers, Corpus Christi, we are approaching about all we can run without a permit option on a project. That number is going to be 100,000 bpd and you got the sheet, actually?
About 140,000 bpd.
Yeah, 130,000 bpd.
Including Houston or no?
No, that would not include Corpus.
110,000 bpd at Corpus and at Three Rivers. Then we are doing 30,000 bpd or so—
At Houston.
At Houston. Then we have numerous pre-flash options and things that allow us 30,000 bpd here, 40,000 bpd 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. We still believe strategically that the Keystone Pipeline is going to be built. It is going to be built on Obama's timescale, which is Q1 2013. We think that there will be approval if he wins election, and that the pipeline will get done here by the end of 2014, early 2015. That heavy crude oil will come to the U.S. Gulf Coast. So Valero still brings value in being able to operate these coking-type refineries. It will all be driven economically with our LPs, which we will squeeze in as much of the light crude if it is priced properly.
Bill, that list got me to 200 of existing. Where is the extra 200 coming from?
If we take a look at what we can do, you can swing Houston to run 100% light sweet. This is all assuming that the economics make 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. I'll give you some numbers because obviously we do all this work. We could run about 85,000 bpd at Houston, 40,000 bpd at Texas City, 40,000 bpd at Port Arthur, 20,000 bpd at St. Charles, and 50,000 bpd or so at Meraux. We can do those kind of things.
Is that with no extra spending that you could get that number?
There is some spending, but minor. Very minor.
If there was Sorry to just press the subject a bit, but it is very interesting and a very big story as far as we are concerned going forward.
Well, it is because every company you will talk to is going to try to do what I am speaking.
Yeah. What would be the next leg if you wanted to Let's say, for example, Keystone was not approved or was uncertain for another three years, four years, whatever. What would you do then?
What we would be forced to do is look at being able to run more light sweet, light to medium crudes in some of our refineries, because it would all be dependent on what the diff is for the heavy sour.
Yeah. To take the second part of that first, what is the discount? I think there is an approximate number to think about for how much discount or premium of heavy or whatever it is that would cause you just to say, "Okay, all light sweet from here.
Well, we think that on a sunk coker, between 10%-12% of the price, you can run a sunk coker and make money. Then if you would drop down, you get down to 8%, 7%, if you still have $100 oil here, you are running out of economics on a coker. You think so, Gene?
Probably. A lot of it depends on where the medium sours are, too. Today, medium sours are running between $5.50, $6 discount to LLS, so we are still seeing good margins to run the medium sours in those sort of refineries versus sweet. Then they look at the medium sour. There is going to be a switch between that and the heavy sour, so that is about $6 spread as well between those two.
This is what Gene is getting in 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 do not have the discounts out there for heavy sour, we are optimizing the system all the time. Remember, we are buying our oil every day.
But what I am wondering, Bill, is at what point would you actually start investing to up your light? Obviously, I guess you wouldn't do that until you were sure Keystone was not going to happen.
Well, we might do some pre-flashing.
The issue you run into, quite frankly, is you load up your gas plant.
Yeah
Your light ends capability. So those projects certainly become bigger. Then we have to be honest, in the world 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. Kim's here, and she's telling us, 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.
Okay.
If we trip the Go ahead, sweetie.
If we trip the Tailoring Rule with CO2, now we have to cover CO2 in our permits, whether you're in Texas or anyplace else, if we hit that major level.
Okay. Is there any sense of what that level is? Sorry to keep pressing on this, but it's kind of crucial.
No, I think it's 75,000 or 100,000.
75,000 or 100,000.
Yeah. It's the Tailoring Rule. It's a threshold that's higher than it would normally be to trip it. But still, almost any significant project will trip it.
Okay. That's really interesting. Got it.
That makes us and everybody else have to get a permit that addresses the CO2.
I think this is just the 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 just a general opposition to what would effectively raise crude prices in the U.S., I guess?
We just have felt that that's going to be very difficult to have happen. I wouldn't say we're giving you a scientific or any better answer here than you would have yourself.
Okay. That's extremely helpful. Thank you very much, guys.
Sure.
Our next question comes from Evan Calio from Morgan Stanley. Please go ahead.
Morning, guys.
Morning.
Just some follow-up on this broader Gulf Coast impact from U.S. production growth. Just beyond maxing out light runs in your system, which clearly is an optimal or at current differentials is an optimal for many of your refineries you just detailed. Before any major Canadian solution is available as a next step, can you talk through an increased blending opportunity or with the overload of lights to blend into some of these medium crudes to press those discounts or recreate those? 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 data is, where you are going to back out at least one type of crude at some point, and you can debate the timeframe, but over the next couple of years. How does blending play into that?
It is a very good question. We are not blending or anything at a terminal, so this is all at refineries.
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 would like to show the process unit a relatively steady diet here of a crude.
We actually have two 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. We are looking at the same type of projects for the other plants as well. We are doing it at the refineries. It lets us then optimize that crude cost.
Does the blending raise the potential ceiling of a light sweet diet that is ultimately blended into something else before it is run versus what you stated?
Yeah, we would optimize.
Yeah.
You are asking something here, so we are going to give you, this is how we view it, all right?
Hey, this is Lane Riggs. 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 a light ends constraint or a crude tower shell capacity constraint, backing out medium sour or light sweet in that refinery.
Okay.
So.
Okay, so there is not an incremental back out of any medium barrel if the price allowed it without a front-end investment?
No, we would.
We look at the relative values of these domestic suites or any suite for that matter versus a medium sour and we increment up to a constraint on the refinery. The numbers that Bill had given you earlier is roughly our constraint to a light ends 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, and I did not know if you had this in your comments, but do you have to nominate in that line to maintain a position in the Keystone XL, the transnational line?
No.
Okay.
No. They are reserving the space in the south segment for those that nominated space as part of the bullet line.
Right. If you did not take Keystone South capacity, would that negatively impact your ability for your nominations when the line is ultimately—
From Hardisty.
Yes. Right.
No, it would not affect our commitments from Hardisty South.
Okay.
We have our space. The committed shippers on the northern segment will have their space all the way down.
Understood.
Now, if we want to 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 maybe lastly, do you have any closure cost estimate on the Aruba refinery with that?
As of today, we've just suspended operations. We are working all our options and still continue to work our options. It's a different situation than some of the other numbers that you've seen in the marketplace. Ours would be less than $100 million. The facts are that's not what we're working, really some options here that'll be good for our shareholders.
Okay. Well, maybe you could sell to Delta. Good. Great. Thanks. Taking my calls, guys.
Our next question comes from Arjun Murti from Goldman Sachs. Please go ahead.
Thank you. Sorry to go back to this, but just so I'm understanding the light suitability in the Gulf Coast, you can do 200 today. To do another 200 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, to do more than we have the capacity today, we will have to put some pre-flash towers in some of our heavy tower locations because the shell capacity of those towers are limited. Really were designed to run a heavier diet. It would be tough to
No, I don't think we have a good number for you.
Okay. Separately, you talked about ongoing portfolio optimization. You are obviously taking the action at Aruba and the East Coast plants. Where does 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? Thank you.
Well, Arjun, we are taking action. Our costs at Benicia are too high, and we have been addressing that to get our per barrel costs 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 economic issues in the state. The thing that is troubling 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 ask a proper question. We are trying to optimize our portfolio so that we can compete long term, and we are 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 haven't thought of You mean like separate it into a freestanding business?
Yeah. Valero, California, whatever you want to call it. Separate company spun out from Valero Corp.
We have not looked at that.
Okay. Thank you so much.
Our next question comes from Chi Chow from Macquarie Capital. Please go ahead.
Great. Thanks. Sorry to circle back on the light sweet issue one more time. 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?
Well, I guess the answer—
Yeah, we can.
Yeah. Now, you guys are asking us things that we have not engineered here. So we are off in a thing here. Conversation is probably four years out.
Okay.
But yes, if that would happen. I want to emphasize what we do every day, and frankly, what all our competitors do every day is they are running their LPs, and they go to a crude mix that they believe is the optimal for that facility. What we are doing right now is we are building some tankage at St. Charles. We are doing work at Corpus Christi that will allow 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 are available.
When they're available.
Right.
But as this volume continues to increase, we, as everybody, will wind up being able to run more of this light and medium crudes 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'll drive you that way.
Right. Okay, thanks. 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.
Okay, great. Thanks a lot.
Just so you know, there is a couple other little projects around there that are finishing as well.
Our next question comes from Faisel Khan from Citigroup. Please go ahead.
Thanks. Just to follow up. In all discussion around the incremental amount of light sweet crude you could run the Gulf Coast, where does Memphis fit into all this? I mean, clearly, I think that is consuming LLS benchmark crude. 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 the product prices are. Your observation is correct. Memphis runs an LLS plus because Capline flows north. 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. The plant runs LLS plus. It does have a very strong local market, though. I guess it is the largest rack in our system or very close. We have a big customer for jet turbine fuel, and so we operate in more of a regional capacity at the Memphis plant.
Okay. 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. I think using 2011 prices, you said about $176 million using LLS. I assume that was based on last year's natural gas prices. Just 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 cat cracker down. We are still running some oil there, but we have a big turnaround going on. The McKee hydrogen plant has not run to capacity yet. Go ahead, Ashley. The numbers here.
Yeah. Hey, 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. Based on the 2011 pricing, we are effectively using $4 natural gas. You could easily—
Yep.
—on your call, whatever your call on natural gas is. It looks like at least a buck lower, could be more.
Okay, gotcha. Thanks, appreciate it.
Our last question comes from Harry Mateer from Barclays. Please go ahead.
Hey, guys. 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 it would help maybe. What's the pro forma debt number, I guess, we should be using?
I guess we're consolidated.
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 71 or 72. Huh?
Okay.
Okay? Okay.
Thanks very much.
That is the end.
We have no further questions at this time.
Okay. Thank you, John. I just want to thank investors for listening to the 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.