Welcome to the Valero Energy Corporation reports 2012 fourth quarter and annual earnings conference call. My name is Trish, and I will be your operator for today's call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. Please note that this conference is being recorded. I would now like to turn the call over to Ashley Smith. Please go ahead.
Thank you, Trish, and good morning, and welcome to our earnings conference call today. With me are Bill Klesse, our Chairman and CEO; Mike Ciskowski, our CFO; Joe Gorder, President and COO; Gene Edwards, our Chief Development Officer; Kim Bowers, President of Retail; 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'd like to direct your attention to the forward-looking statement disclaimer contained in the press release.
In summary, it says that statements in the press release, and on this conference call that state the company's or management's expectations or predictions of the future are forward-looking statements intended to be covered by the safe harbor provisions under federal securities laws. There are many factors that could cause actual results to differ from our expectations, including those we described in our filings with the SEC. As noted in the release, we reported fourth quarter 2012 earnings of $1 billion, or $1.82 per share. This includes a non-cash asset impairment loss of $37 million after taxes or $0.06 per share, which is primarily related to permanently canceled capital projects at certain of our refineries. This is our highest fourth quarter earnings per share since 2005. For the full year 2012, net income attributable to Valero stockholders was $2.1 billion, or $3.75 per share.
Included in these results were non-cash asset impairment losses of $983 million after taxes, or $1.77 per share, and severance expense of $41 million after taxes or $0.07 per share, mainly related to the shutdown and impairment of the Aruba Refinery. Operating income was $1.6 billion versus operating income of $167 million in the fourth quarter of 2011. The increase in operating income was mainly due to higher refining margins in each of our refining regions. Partially offsetting the operating income was a significant decline in ethanol margins. Our fourth quarter refining throughput margin was $12.27 per barrel, which is a large increase versus a fourth quarter of 2011 margin, which was $5.46 per barrel. The increase in refining throughput margin was mainly due to wider discounts on medium sour, heavy sour, and domestic light crude oils.
For example, comparing the fourth quarter of 2011 to the fourth quarter of 2012, the Brent less Mars medium sour discount improved by nearly $3 per barrel. The Brent less Maya heavy sour discount improved by over $11 per barrel, and the Brent less WTI domestic light discount improved by nearly $7 per barrel. Our fourth quarter 2012 refining throughput volume averaged 2.64 million barrels per day, down 73,000 b p d from the fourth quarter of 2011, mainly due to the lack of throughput volume at the Aruba Refinery, which was shut down in the first quarter of 2012. Refining cash operating expenses in the fourth quarter of 2012 were $3.73 per barrel, which was in line with the third quarter of 2012, but it was slightly below our guidance due mainly to lower than expected energy costs.
Before I cover retail and ethanol, I would like to highlight several other items in our refining operations. First, we had a smooth and successful startup in December of our new hydrocracker at Port Arthur, which was our largest project in company history. Since mid-December, the unit has been operating at approximately 50,000 b p d and has performed well. Last week, we conducted performance tests with the technology provider, and we have begun rate tests that should enable us to operate the unit at or near the permitted maximum rate of approximately 57,000 b p d. We are continuing to work on the new hydrocracker project at our St. Charles Refinery. We expect to complete that unit and begin operations in the second quarter of 2013. Both of these hydrocrackers were designed to take advantage of the current environment of strong diesel margins and cheap natural gas.
Also, in the fourth quarter, we completed and started up our products pipeline that runs from the Quebec Refinery to Montreal. Our retail business reported fourth quarter 2012 operating income of $95 million, consisting of $78 million in the U.S. and $17 million in Canada, where we took a $9 million non-cash asset impairment loss for retail stores in Canada. For the year, our retail business generated $348 million of operating income, making it our second-best year in history and nearly as high as last year's record-setting level of $381 million. Retail fuel volumes in both regions declined slightly compared to fourth quarter 2011 as weak gasoline demand impacted sales. U.S. retail merchandise sales were higher but on flat merchandise margins in the fourth quarter of 2012 versus the fourth quarter of 2011.
Canada retail merchandise sales and margins were down slightly in the fourth quarter of 2012 versus the fourth quarter of 2011. Our plan to separate our retail business and unlock value for our shareholders is progressing. Earlier this month, CST Brands, Inc, formerly known as Corner Store Holdings, Inc, filed an amended registration statement with the SEC. In summary, our plan is to distribute 80% of the shares in CST Brands to Valero shareholders, and Valero will receive approximately $1.1 billion in cash and incur a tax liability of approximately $300 million, primarily in Canada. We expect to liquidate the remaining 20% of CST Brands' outstanding shares within 18 months of the distribution. Regarding timing, we expect the retail distribution will occur in the second quarter of 2013, but that assumes a favorable private letter ruling from the IRS and clearing all comments from the SEC.
We believe the separated retail business will perform well and unlock value for shareholders for several reasons. First, CST Brands will be the second-largest publicly traded independent retailer of fuel and convenience merchandise in North America, with nearly 1,900 sites. Second, these sites are located in geographically diverse regions: the southwestern United States and eastern Canada. Third, many of the 1,032 U.S. retail sites are in Texas and surrounding states, which have strong economic growth. Fourth, CST Brands has substantial ownership of the sites, with approximately 60% owned and not leased. Fifth, there's a long history of strong financial performance and brand recognition. Finally, CST Brands has significant growth opportunities in merchandise, food service, and new build locations.
Our ethanol segment reported operating income of $12 million, which was down $169 million from the fourth quarter of 2011, mainly due to much lower gross margins as high corn prices and excess ethanol inventories squeezed margins to low levels. Production averaged 2.7 million gallons per day in the fourth quarter of 2012, for a decline of nearly 800,000 g p d compared to the fourth quarter of 2011. Until margins improve, we expect production rates to remain well below capacity, with three of our plants temporarily idled. In the fourth quarter of 2012, general and administrative expenses, excluding corporate depreciation, were $189 million. Total depreciation and amortization expense was $402 million, and net interest expense was $70 million, all in line with company guidance. The effective tax rate in the fourth quarter was 34%.
Regarding cash flows in the fourth quarter, capital spending was $942 million, which includes $140 million of turnaround and catalyst expenditures. That brings our full-year capital spending, including $479 million for turnaround and catalyst expenditures, to $3.4 billion or $100 million below our guidance. Also in the fourth quarter, we paid $97 million in cash dividends to our shareholders and bought 4.2 million shares for $133 million in cash. For the full year 2012, we purchased 10.6 million shares of Valero stock with $280 million of cash. With respect to our balance sheet at the end of December, total debt was $7 billion, cash was $1.7 billion, and our debt-to-capitalization ratio net of cash was 22.7%. At the end of December, we had nearly $5.7 billion of available liquidity in addition to cash.
We expect our 2013 capital spending to be consistent with our prior estimate of $2.5 billion, and this includes approximately $200 million for our retail segment. Our 2013 estimate also includes spending to complete the St. Charles hydrocracker project, which has a total expected cost of approximately $1.6 billion, or an increase of approximately $100 million from our previous estimate. Looking at the economic growth portion of our 2013 capital spending estimate, we are focused on three strategic areas. The first area is logistics, and the spending is spread across our refining system for rail cars, rail unloading facilities, pipelines, storage, and terminals. The objective is to increase our access to more volumes of discounted U.S. and Canadian crude oils.
The second strategic area is for modifications to our refineries that increase the flexibility to export products to premium markets and to process more of discounted crude oils, particularly domestic light crudes. The third strategic area is for expanding our distillate-focused hydrocrackers, Port Arthur, St. Charles, and Meraux. Regarding other uses of cash in 2013, we retired $180 million of 6.7% senior notes that matured in mid-January. We expect to retire $300 million of maturing notes in the second quarter of 2013. Last week, our Board of Directors increased the quarterly dividend rate by $0.025 per share or 14% to $0.20 per share, or $0.80 per share on an annualized basis, which is our highest level in company history. This increase reflects our positive outlook for Valero and our commitment to return more cash to shareholders.
On the macro side, we continue to believe many of Valero's refineries have several competitive advantages versus other Atlantic Basin refiners, including low-cost natural gas, increasing access to discounted domestic crude oil, and larger, more complex and reliable refineries. These advantages have enabled us to compete in both domestic and foreign markets and operate at higher utilization rates versus less competitive Atlantic Basin refiners. For modeling our first quarter operations, you should expect the refinery throughput volumes to fall within the following ranges. The Gulf Coast at 1.4 million barrels per day- 1.45 million barrels per day. Mid-Continent at 390,000 bpd - 400,000 b p d. The West Coast at 245,000 bpd - 255,000 b p d. North Atlantic at 450,000 bpd - 470,000 b p d. Refining cash operating expenses in the first quarter are expected to be around $4 per barrel.
Regarding our ethanol operations in the first quarter, we expect total throughput volumes of 2.4 million gallons per day. Operating expenses should average $0.40 per gallon, including $0.05 per gallon for non-cash costs such as depreciation and amortization. Also, we expect G&A expense excluding depreciation, to be around $170 million. Net interest expense should be around $85 million. Total depreciation and amortization expense in the first quarter should be around $405 million. Our effective tax rate in the first quarter should be approximately 35%.
Okay, Trish, we have concluded our opening remarks. We will now open the call for questions. I do want to advise callers that our goal is to keep the duration of the call to about an hour. Therefore, we are going to ask that you limit your each turn on asking questions to two questions. If you have additional questions, you can hop back into the queue. Okay, Trish.
Thank you. We will now begin the question-and-answer session. If you have any questions, please press star then one on your touchtone phone. If you wish to be removed from the queue, please press the pound sign or the hash key. If you are using a speakerphone, you may need to pick the handset up first before pressing the numbers. Once again, if you have a question, please press star then one on your touchtone phone. Our first question comes from Jeff Dietert from Simmons. Please go ahead.
Good morning.
Morning, Jeff.
You guys had a strong quarter. Throughputs were better than expected. Cash operating costs lower, but I wanted to focus on gross margin in the Gulf Coast. I assume that the feedstock advantages probably flowed through and contributed to a very strong margin capture. Could you talk about any one-time events or talk about how feedstock changes could be sustainable in continuing strong margin capture? Any step function change in U.S. crude or Canadian crude influence in the fourth quarter?
Well, Jeff, this is Joe. Good morning to you, too. We did well on the Gulf Coast. If you look at the slate that we ran, we ran more heavy sour and medium sours in the fourth quarter than we did in the third quarter. Ashley mentioned during his comments what those discounts looked like, and they were very strong. We also ran a lot more resid. We ran a bit more resid in the quarter, but we ran resid with better pricing than we had in the third quarter, and a lot of that had to do with the fact that the Libyan production was back on stream.
So basically, the guys did just a very good job of optimizing the crude and feedstock slate into the plants. Actually, in the quarter, we continued to push to run more domestic light sweet crudes, which we were up over, I think, 700,000 bbl a day. So all in, if you look at the crude slate, we had discounted crudes coming in really every form.
How do you see your feedstock changing with the addition of Seaway having started up an incremental 250,000 bpd and the Permian pipes coming on late March or April, and incremental rail coming into the market? How do you see those benefiting you in the first quarter and second quarter going forward?
Well, clearly we're getting access to more crude, right? We mentioned, I think in the notes that we were 100% domestic light sweet crude. We were running sweet crudes in the Gulf, so we backed off all of our foreign sours. Seaway has had an impact, Jeff, as you know, but they're not running at the rates that have been anticipated, and I think that's why we see that LLS is still trading at a bit of a premium to Brent.
I think as you get Seaway up to speed, and then we've got significant additional projects that are going to bring more crude into the Gulf through 2013, you'll end up seeing Brent trading at that discount that we're all expecting to LLS going forward, okay? As we run light sweet crudes, and Lane and Bill can speak to the projects that we're looking at, and I think you know some of those to allow us to run more light sweet crudes. We're going to be the beneficiaries of that.
Thank you, Joe.
Our next question comes from Doug Leggate from Bank of America. Please go ahead. Doug, your line is open.
Doug, whenever you are ready. All right. We might have to hop in next. Trish, can you move to our next caller?
Yes. Our next question comes from Evan Calio from Morgan Stanley. Please go ahead.
Hey, good morning, guys. Great quarter today.
Good morning, Evan.
Yeah, just maybe a follow-up on some of those projects. I know you mentioned the fourth quarter replaced the imported lights with domestics in the Gulf Coast and Memphis, and you are pursuing several options. I believe you are considering a condensate splitter. Clearly, Gulf Coast will see more condensate moving out of the Eagle Ford. Rail was mentioned as an option that would, I think, increase in viability if Keystone is delayed or blocked. Can you comment just generally on what those projects are, kind of the cost magnitude, dimension, maybe the logistics spending, because that would be important as well, as that could be put into a different structure, and whether any of these expenses are currently included in that $960 million of strategic 2013 CapEx?
All right. Well, Evan, good morning. We are looking at a lot of rail projects. If I look at the logistics capital that we have in the 2013 budget, a lot of it has to do with dock capacity and just being sure that we have the ability to export the volumes that we have. We think today we can put 225,000 bbl a day of gasoline on the water, and we are looking at ways to increase that at St. Charles and Port Arthur. Diesel, we think we can move 280,000 bbl a day, and we are looking at projects to take that up to over 400,000 bbl a day. A lot of the capital that we have in the capital forecast is for that.
In addition, we announced that we bought the rail cars, and we are working projects to figure out where we want to take this crude with these rail cars. We certainly have some things in mind, but we are looking at projects, for example, at St. Charles to rail crude in. We have a project to rail crude into Quebec. We have the two West Coast refineries that we are looking at rail options for. Then Memphis, we think we can rail a significant amount of crude into Memphis. So we are working all those options, and the guys are going through the overall logistics strategy for that, including potentially additional rail cars. As far as the capital attributed to it, right now, we do not have anything identified above the plan. Yeah.
Just to clarify, all those things Joe was talking about, those are included in our strategic growth category, which is just under $1 billion for 2013.
That is great. In terms of Memphis, you say that you backed out all foreign imports there, which I presume used to come off Capline. What are you running there and how is it getting there? Is there any yield pickup from the slate change at Memphis that has improved its profitability?
I'll speak to the crude supply piece, and maybe Lane wants to talk to the yield improvements. We are running Bakken that is really still coming up Capline. We have not changed the method of delivery into that refinery right now. We are looking at waterborne deliveries into Memphis going forward, but right now, the economics have supported continuing to use Capline.
Yeah. This is Lane Riggs. In terms of the quality of Bakken, it is really nominally around LLS, but I would say because LLS historically had been a blended barrel made from a number of different components, Bakken is a neat barrel, and in terms of its ratability and our ability to steady our operations around running it, we are certainly getting the benefit of a more steady crude diet. It is lighter, so really its value versus, say, LLS is directly a function of what the gas crack is. But nominally, today it is slightly discounted on a quality basis to LLS. For us, though, we are getting quite a bit of value just out of the steady operation running Bakken neat to our refinery day in and day out to Memphis.
Okay. I'll leave it there, guys. Thank you. Appreciate it.
We have Doug Leggate from Bank of America. Please go ahead.
Hi, can you hear me now, guys?
We can.
I apologize. Technical problems.
Welcome back.
Yeah. I hope I didn't get my quota of questions taken there. I wanted to follow up on Jeff's, if I may, real quick, and then I've got a follow-up. I guess this question is really for Joe, but as you see the light sweet barrel increase in terms of volume in the Gulf Coast, what's happening to the relationship as you see it for heavy crude, particularly as it relates to its historical discount to LLS? What I'm really trying to get at is, if you eventually see LLS move to a discount to Brent, do you expect the heavy medium sour barrels to maintain their relationship with LLS or narrow the discount? I'm just curious as to how you see that playing out, and then I've got a follow-up, please.
Well, that's a good question. Bill and—
I'll answer it. The way we actually look at it, we would agree that if LLS goes to a discount of Brent, which we expect to happen, the world crude is still Brent. So heavy crude will sell at a discount, but the discount against LLS will narrow. But you'll still have an acceptable discount against Brent. So going into a sunk coker, we think that you'll have economics to do that, but not to build a grassroots coker.
What is the logic then of expanding your ability to process light crude if the heavy crude is going to move to the same discount as the light, if you see what I mean.
Just because of the availability. We will see if Keystone actually gets built. As you can see in the press today, Enterprise is having trouble moving the oil once it gets to Houston. We have a lot of availability, and personally, we have said that the discount, and I know it is different today, okay? The discount LLS against Brent will move to several dollars, at least tariffs, but it could move more.
Thus, it will be attractive to run that, but it is just so available where the heavy barrels are having to be imported. Now you start to look around and, as I said, it depends on what happens with Keystone. As you begin to look around, the Mexican volumes are moving different directions. You have the Venezuelan volumes moving different directions. You do have increases in Colombia. We just manage a supply function here and think the light crude is going to be readily available.
Great. Thanks for the full answer, Bill. My follow-up is probably something that you have been asked a lot about here recently, but your free cash flow obviously steps up this year. You have made this comment again in your earnings statement about having a competitive or the highest yield in the sector. Can you just help us understand what is framing the scale of ultimately what you think between your dividend policy and buybacks? I guess you could bring into the answer perhaps the shares that you issued in the middle of the crisis, in terms of whether or not that would prioritize buybacks over dividend increases, and I will leave it there. Thanks.
Well, Doug, I think we clearly have demonstrated as a management team that we return cash to the shareholders. You go back to 2006, 2007, when we did not have better opportunities, we bought a lot of shares, which we did get some criticism for. But actually, we didn't have better projects, so we returned cash to the shareholder. So we've demonstrated our ability to return cash to the shareholder. In the last two years, we've purchased 27 million shares. We've increased our dividends several times. We'll continue to buy our shares because we think our shares are undervalued. We do not think the market is giving us credit for this distribution of our retail businesses. But on the other hand, we're going to maintain our investment-grade rating. We think it's very important for a company of our size.
Ashley mentioned we're paying off about $500 million of debt here in the first half. And with this volatility that we have in the marketplace today, we're going to hold more cash. So, a couple of our projects are slightly behind. Obviously, Ashley said we're $100 million over from our previous guidance at St. Charles hydrocracker. So we're going to make sure we finish all of that. Then what we tend to do is look at a balanced approach to everything. In our business, this is a very capital-intensive, long lead time business.
And if we believe that we can add more shareholder value than we can looking at our stock price today, then we make these investments. So we tend to have balance in our approach. You ask about the approximate 50 million shares that we issued in, I guess, the second quarter of 2009. And sure, we would like to take those out. And everybody that supported us at that time sure had a nice return as well. But it's not a goal per se. It's more of the stock is undervalued and we'll have a balanced approach.
Great. I appreciate the answer, Bill. Thanks.
Our next question comes from Robert Kessler from Tudor, Pickering. Please go ahead.
Good morning, guys. I wanted to ask you a little bit more about the dynamics you are seeing along the Gulf Coast, and that is: are you getting a widening spread in the east versus west coastal price of light? I mean, you are getting a deeper price for light crude at, say, Corpus, than Houston, and now a Seaway discount, a deeper discount at Houston versus Louisiana. What do you expect to happen with that east-west spread going forward? Are there any limits to exploiting a wider spread should one emerge?
Well, Rob, your description of the market is what we are seeing. Corpus crude is trading less than Houston crude, and Houston crude is less than St. James. What do we expect going forward? I think if St. James is going to be Bakken based, it is always going to price more than Eagle Ford into Corpus or the Mid-Continent crudes, the Permian crudes into Houston.
I would add to that as long as these areas are long, so for instance, let us just say Corpus Christi is long Eagle Ford crude, thus it has to move, then it is going to move with the tariff and some timing deltas. The clearing place is St. James now for LLS, so you are going to have differentials toward Houston and differentials towards St. James.
Okay.
You have to have the supply demand imbalance in those markets. The minute the market flips to short, then the tariff turns around.
Is there adequate barge capacity to exploit the spread if one persisted for long enough to want to put money to work and inventory on the water to take advantage of that?
Yeah. I would say, I don't know if there's enough barge capacity, truly.
Well, I think your question is, would you store oil on the barge to take advantage, or are you talking about just shipping it?
Yeah. To me, when you have a spread like that potentially emerge, you guys would seem to be as best placed as anyone to be able to take advantage of it. I just don't know, is there some limiting factor I'm not thinking of, whether it's loading, unloading along the coast that kind of circumvent what might be in place already on the pipeline side? Is there some kind of storage bottleneck? Just what could be a limiting factor that I might not be thinking of on your ability to displace that dislocation and offset it into your system?
Well, I would assume others are doing what we're doing. We're fixing docks, we're increasing our capability. At Corpus Christi, come the second quarter, we'll be able to load a lot more onto water. Lead time for rail cars is a year to 18 months. Lead time on barges is a year?
Yes.
A year. I think it just tells you by those lead times that those type of assets are short or tight.
Second question from me. When you look at Western Canadian Select or bitumen in Canada in general and the spread versus, say, Maya in the Gulf, it seems like rail is a no-brainer. Certainly, you guys ordered a couple thousand more rail cars. Some of those will be put to work moving that crude down. With about a year turnaround time, I think, on a new rail car, why could that not just accelerate to an exponential degree? Where do you see that developing in, say, just overall market rail out of Alberta, say, down to the Gulf Coast in a year or two years' time? How much will Valero participate in that?
Well, I think Joe answered you earlier, said we're looking at rail at St. James, St. Charles, so that's Louisiana.
Yes.
We're doing it. Clearly, we're looking at rail into Southern California, just like all our competitors are as well. As far as exponential, there is no question rail is growing very rapidly by every single company, and part of it is because of the uncertainty surrounding some of the pipelines. The long lead time that seems to be developing. But the supply is there, and the market demand is in these refining centers, and you would not get any argument from us or I think any of our competitors, since all of us are buying rail cars, that this is a big part of our future in this business, is your logistics capability to move distressed crude oils through your refineries.
If you were in 12 - 18 months' time, if the market was moving 200,000 bbl - 400,000 bbl a day out of Alberta by rail, that wouldn't surprise you?
I do not know the numbers, I think, as well as you do, but it does not surprise me that there is going to be a lot of rail cars. I just do not know those kind of numbers.
Sure. Okay.
Okay?
Well, thanks for your comment, appreciate it.
We're looking at the same thing that I'm sure you hear from the other people.
Gotcha. Thank you, guys.
Sure, Robert.
Our next question comes from Cory Garcia from Raymond James. Please go ahead.
Morning, fellas.
Morning, Cory.
Just kind of have one quick question. You guys alluded to in your slide deck regarding your Port Arthur hydrocracker that you have been seeing some higher quality diesel and actually some better distillate yields overall. Just wondering how we should think about that today as it normalized back towards your expectations of, I think, I want to say closer to 60%, or have you maintained these high levels? And really how we sort of get that around in terms of modeling.
So hi, Cory, this is Lane Riggs. Right now, as we are doing this test run, as Ashley alluded to in his opening remarks, we are at about 80% distillate yield. That is jet fuel plus distillate. Our diesel index, our cetane index coming off the unit is about 62% on the diesel, which is much better than we had anticipated. The properties on the jet are great. So certainly, these are great distillate yield and great products for our products guys to try to figure out where the best place to market it.
We have new catalyst.
Yeah, start of run conditions.
Everything's new, so you got high activity.
Right. Start of run conditions.
We think that this unit will run till we have to replace catalyst.
Three years.
Three years, so there will be some degradation over that period.
That is right.
Okay, great. Thank you, guys.
Our next question comes from Roger Read from Wells Fargo. Please go ahead.
Yeah, good morning. Again, congratulations on the quarter. You've talked a little bit about, specifically in the quarter, sourcing more heavy oil. Can you talk a little bit about where those mediums and heavies are coming from? I mean, is this incremental Canadian barrels? Is it let's call it Western Hemisphere? Is it something out of the Middle East? Is it a mix of the above? Then as you're looking forward, we clearly are going to have more heavy sour capacity coming on globally. I was just curious, is it ultimately we need Keystone, we need rail, or is there something else you're looking at in terms of sourcing those mediums and those heavies?
Okay. Well, the heavy barrels, I mean, we got them out of South America and Mexico, okay? Our normal suppliers, we increased our volume from Venezuela and from Mexico both. I would say that honestly, there was nothing unusual about the sources of supply of these barrels other than the economics associated with running them versus not running them. We are bringing some heavy sour Canadian crudes into Port Arthur, and we're running that, but we didn't have any material change in the volumes there. Then if I step forward to what you're talking about going forward, we want heavy sour crude in the Gulf Coast. Keystone Pipeline is the most economical way for us to do that. We're still fully supportive of the pipeline, and we want to see it happen.
Second to that, then you look at other alternatives to get heavy sours out, and we continue to look at those. Is there capacity on Enbridge? Is there ability to take the crude into [Harcourt] and then barge it down to St. Charles, which we tend to be doing some of? Can we do more of that? Then rail, of course. We do not know exactly what those numbers might be today, but we are looking at. We have heated rail cars, and we are looking at the ability to move heavy sour Canadians via rail. We are looking at all the options there, Roger.
Okay. The follow-up question, looking at the hydrocrackers, obviously we can all look at the prices of the various products. If I always understood it correctly, it was really the sensitivity to natural gas as feedstock and power source. Can you walk us through what we should really think about the full quarter contribution in Port Arthur, and then obviously as we see the ramp up at St. Charles as well, what are the big things we should watch here on the price side to really determine the economics of these?
Yeah. Roger, there is several key drivers. Natural gas is one of them, diesel is one of them, overall crude is one of them. We have got sensitivities per barrel in the appendix to our standard IR slide deck. To give you a feel for how it has been running, it has been running at these kind of planned test rates at around 50,000 bbl a day. So far in January where the market has been with low gasoline cracks, but good diesel cracks and pretty cheap natural gas, the kind of EBITDA has been up around between $20 and $25 a barrel. We have been running at about 50,000 bbl a day. So, it has been pretty much what we expected. This is kind of a depressed environment. I would not assume January is full year commodity price deck. But in this environment, it has been pretty dang good.
Yeah, it definitely sounds like it. Then as we think about moving into the springtime, the gasoline crack typically would react a lot better.
That's correct. You'd have to assume, you would hope you could assume a higher average gasoline crack because as Lane said, it's nearly 80% distillate right now. The remainder is primarily gasoline or gasoline-related components. As that crack picks up, then you should see overall margins.
Okay. Yeah, because I was interested in that. The original calculations we looked at was more like 2/3 distillate, 1/3 gasoline and others. The 80% reflects, again, the comments about catalyst over time. Maybe we think 2/3, 1/3.
Yeah. Well, we'll see where it shakes out because as Bill mentioned, the catalyst is highly selective right now, which is advantageous. We'll see where it shakes out. But, yeah, I'm not ready to change the base model for it yet.
Okay, great. Thank you.
Our next question comes from Sam Margolin from Dahlman Rose. Please go ahead.
Morning, everybody. Thanks for taking the question.
Sure.
I guess a lot of the conversation has been around crude. I was a little more curious about product. In general, how have exports looked? Is that kind of plateauing? Obviously, there has been some pretty healthy inventory building over the past month or so on the gasoline side, and I was just wondering if there is any trends that stand out to you on the export front, if it is decelerating or if you anticipate the same kind of growth that we have had over the past two years.
Okay. Well, hey, Sam, it's Joe.
Hey, how are you?
I'm good. You?
I'm good, thanks.
Good. Well, in the fourth quarter, we moved out almost 110,000 bbl a day of gasoline, and it went primarily to Latin America and Mexico. Those are pretty high numbers because typically we are doing 60,000 bbl-70,000 bbl range. So demand was still very good. Latin America is growing, and they continue to have supply issues. Mexico's demand is growing, and they have some supply limitations. So from a sustainability perspective, we still think that these export markets are going to be very good. In the first quarter of 2013, from a gasoline perspective, we will probably export less than we did in the fourth quarter, and a lot of that has to do with the turnaround activity that we got going on at Corpus Christi. If we talk about diesel inventories, unlike gasoline inventories, diesel inventories are low. They are at the low end of the five-year range.
Although U.S. demand for distillate continues to be weak, distillate demand abroad is strong, and it continues to grow. In the U.S., I think we exported over 1 million barrels a day of diesel fuel. That is up significantly from where it was last year. Valero exported 157,000 bbl a day of diesel fuel in the fourth quarter and will increase that volume in the first quarter as we have got the throughputs of the new hydrocracker. From us, from our perspective, and I think everybody else is, it is always a market-driven phenomena and is the arb open or not? If the arb is open to move the barrels to South America or Europe, we will move them, and if not, we will keep them here at home.
Okay.
That is the answer.
Thank you. That data was really helpful. Secondly, on the East Coast, I am sure you saw it was officially announced a plant that came up for sale. Historically, it has not been particularly competitive, but I was just wondering how you guys think of the East Coast as a derivative of your LLS thesis. Barge activity might accelerate from the Gulf up to the North Atlantic, and if you think that timing-wise, it could make sense to position into that theme a little early.
Well, as far as Valero's opinion on the East Coast, we exited the East Coast.
Right.
I think as far as a refiner goes, we are still a supplier marketer into those markets. Our actions speak for themselves.
Okay. Fair enough. Thanks so much. Have a good one.
Our next question comes from Blake Fernandez from Howard Weil. Please go ahead.
Guys, good morning. Congratulations on the results.
Thanks, Blake.
I had a question for you on the retail spin. Presumably, the $1.1 billion of cash coming to the parent company, I assume that is a result of the retail company taking on leverage. Just trying to confirm, can you give us an idea of capital structure for the parent company post-spin-off?
Well, for the parent, for Valero, we have just got $7 billion worth of debt. We will be receiving, as we put in the release, $1.1 billion in cash from the separation. We will have about $300 million of tax leakage associated with the separation. Then, of course, we are retaining 20% of CST Brands, and at some point in the future, I think within 18 months, we will dispose of that.
Mike, to be clear, that 18 months, should that be thought of as a slow kind of bleed into the market, or is that hold it for 18 months and then all at once sell those shares?
We have not determined how we will divest that. We will be doing that in the next few months.
Okay, fair enough. The second question was on MLP. I know in the past you have talked about considering that after the retail spin. It sounds like you have got a decent amount of capital investment going into the logistics and midstream side of things. Presumably, it would make sense to move sooner rather than later, just so you have some incremental revenue opportunity and sell that to the market. I am just curious if you have any thoughts on your appetite of moving forward with an MLP.
It has not changed at all. We have said that we will look at this seriously. We watch what is happening in the marketplace, and I am really talking about logistics and terminaling here. But really, for our organization, the retail spin is occupying many of our people, and we need to execute and get this done first. So I have not changed what we are saying on this subject at all.
Okay. Thanks, Bill.
Our next question comes from Faisel Khan from Citi. Please go ahead.
Good morning. It's Faisel from Citi.
Hey, Faisel.
Hey. Wondering if you could go back to the crude oil import into the Gulf Coast, particularly the sweet crudes. You talked about how you backed out the foreign imports of sweet crude into the Gulf Coast, I believe, and to Memphis. In the fourth quarter, what was the impact of backing out those foreign crudes? What kind of uplift did you get from consuming domestic suites versus buying foreign-born suites in the fourth quarter?
At Memphis, that was really where this happened, right? Lane, do you have a good idea on the—
I am not sure. Are we trying to dollarize it? Is that—
Yeah, I think he is looking for, so it is—
I don't have the actual numbers yet, but we were paying an LLS plus like $0.50, and now it's like LLS minus $0.50. In the ballpark of a buck a barrel, something like that.
Okay.
The landed cost versus and it depends on when and which, because it's moving all over the place. We've been making this switch over the past year.
Okay.
We're bringing in foreigns into Three Rivers. We used to bring foreigns into Houston. We used to bring foreigns into Memphis. So we've been backing those out based on economics, but it could be a dollar or a few dollars per barrel improvement in economics versus the landed cost of the foreign.
We're also starting to see where we're bringing in some of the domestic sweets into the Houston area and backing out medium sour. I think that's the other move that we're seeing in terms of dollarizing. I'd have to check it. So it's not just foreign sweets at this point. Typically, in that Houston market, we're seeing where we may be displacing some medium sours too.
Right. I guess if I am looking at the sequential improvement in margin from the third quarter to the fourth quarter, I get that the heavy crude discounts widened out, and I get the Mars discounts widened out. But I am just trying to figure out, did your purchases of light sweet crude, did they beat the benchmarks in the fourth quarter versus the third quarter? Did you purchase them under the benchmark into the Gulf Coast and Memphis in the fourth quarter versus the third quarter, or was it relatively similar?
I do not think there was any change relative to the purchase price of these crudes. I think you got it right. It was heavy sour and medium sour change and the improvement in those discounts, and then the discounts on the resid that really drove the economics.
Okay. Got you. Was there any—
However, we always act in our economic self-interest on this. We switched to a domestic crude because it was more economical.
Right. Okay. What about the impact of the big Permian discounts we saw in the fourth quarter? Were you able to purchase those crudes at discount into the Gulf Coast, or were those mostly trapped in that area?
Yeah, they were mostly trapped.
Okay.
Yeah. We do move Permian Basin, Midland area crudes up to McKee and Ardmore, but we've always done that.
Okay. Last question for me, was there any sort of derivative movements in the quarter? Any gains or losses, non-cash derivative gains or losses in the quarter?
No.
No.
Okay. Fair enough. Thanks, guys. Appreciate it.
Our next question comes from Ed Westlake from Credit Suisse. Please go ahead.
Hey, congrats on the numbers. I wish I had the number out there so that you could beat it. Just on a follow-up to a question earlier. You spoke about Corpus trading at discounts to Houston and then Bakken trading into St. James at a premium. I appreciate it is a moving target, but if it is possible to be a bit specific about, say, what is the Eagle Ford discount into Corpus, what is the Permian discount or the Seaway blend down into Houston, and what is the Bakken discount into St. James in 4Q, say, relative to LLS? That would be helpful.
Okay. So relative to LLS, and if we keep it just as simple as we can.
Yeah.
We look at transportation, right? There are so many good reports out there now that are addressing these issues, and we look at those too. You have a couple of dollars of transportation to get Eagle Ford over to Houston. Then you got another couple of dollars to get from Houston over to St. James. Theoretically, you could argue that Eagle Ford ought to trade at an LLS minus $4 over in Corpus and LLS minus $2 in Houston. Then if you look at it relative to WTI, and you said, well, WTI is $3 or so, $3.50 to the coast. WTI is going to be, if you took it into the Houston markets, you would get it there for $3.5. So it would be, what? A buck and a half over the Eagle Ford into Houston.
Then if you took it all the way over to St. James, you are $3.50. This is the kind of the math that we are working on. But we are doing it kind of the same way you guys are. We are saying, okay, what is it going to be if LLS? Bill mentioned it before that St. James will be the clearing point for LLS, and everything is going to trade as you move west to a discount to LLS. Then, what does that do with Brent? Well, you are going to have Brent ultimately into the East Coast be at a LLS plus $4.50 - $5 a barrel, which is the U.S. flag transportation cost to get it up there.
Yep. That makes a lot of sense, and that is very helpful. Thanks very much. Then I have a chart of LLS Maya in front of me for what it is worth. Obviously, there was a bump up in Q4, and clearly, your earnings have benefited from that. Maybe just talk a little bit about market conditions as we come into Q1 in terms of particularly the surprise that I guess we feel in terms of Mars and Maya benefiting your results more than expected.
All right. Well, Maya discounts were very good in the fourth quarter. A lot of that had to do with the weakness that we saw in WTS there that spiked that discount a bit. Also we mentioned that the residual fuel markets were weak, and so that helped it also. Resid is still weak today. The WTS discount has come in a bit, so those margins have compressed a little bit. But Lane and I were talking about it earlier today. I guess we are seeing medium sours price into the Gulf now basically at a flat price to light sweet domestic crude.
Right.
Anyway, we are still seeing decent discounts on these, and you are seeing pressure on light sweet as more of it gets there.
Okay. Thanks very much.
Our next question comes from Ann Kohler from Imperial. Please go ahead.
Great. Good morning, gentlemen. Just a question, certainly regarding some of the projects that you are working on and how you are viewing the permitting issue and being able to move forward with some of those, particularly when thinking about the Houston expansion.
I think you're alluding to the greenhouse gas permitting.
Yes.
We are at Houston and our Corpus Christi Refinery, due to some units that we have shut down in the last few years. We're able to put forward a project that will allow us to be underneath the greenhouse gas permitting. This will affect the industry. I'm sure everybody's looking at this in terms of their investment. It may ultimately limit how big some of these investments can be if they can make it a decent investment that keeps you below the greenhouse gas permit. Both our crude expansion project at Corpus and at Houston are set pretty much at that level.
Great. Thank you very much.
Our next question comes from Paul Sankey from Deutsche Bank. Please go ahead.
Hi, guys.
Morning, Paul.
Correct. Congratulations to Joe on making President as well. If I could ask you firstly about the export story. You have talked about it, but could you just clarify? I think you said you are exporting about 100,000 bbl of gasoline, and I think it was 200,000 bbl of distillate. Is that at export capacity now?
No. I would say no. The gasoline, that was a good quarter. 100,000 bbl a day of gasoline is a good quarter for gasoline exports. But we have the ability probably, Paul, to take out 225,000 bbl.
Okay. I got the 225,000 bbl number, and then I think your 280,000 bbl of diesel is your—
Yeah.
—distillate is your—
280,000 bbl is where we would say we are today, and then we got the logistics projects, as we mentioned, that improve docks and just really take away capacity. That we expect is going to take us up to about 425,000 bbl a day of capacity.
And when I think, did you say the timeframe on that? Is it 2Q?
No, we're working on projects right now. Some of them will come on in the second quarter, but really, I think these projects that we're talking about we'll have in place by the end of the year or early next year.
And—
2Q was being able to load crude out of Corpus Christi.
Got you. Then you've mentioned distillate exports. Is there an expansion of gasoline capacity above the 225,000 bbl?
Yeah. Some of these projects, and really it's primarily stuff we're doing at St. Charles and Port Arthur, will take us up to about 250,000 bbl.
Okay, that's great. I know we're running out of time, so just the follow-up is, one of the issues that we've seen with all these crude differential moves has been at times very narrow, heavy light spreads, but we had a pretty good number in Q4. How's that dynamic working now this quarter, and how do you expect that to play out? I'm thinking particularly one of the hardest things when we think about this is the fact that essentially a lot of that heavy crude is priced on a formula with a K factor. Would we naturally expect that to be a narrower number going forward because of how wide it got in Q4? Thanks.
Well, as I mentioned, it's come in a bit, Paul, and a lot of it has to do with the fact that WTS was dislocated for a period there when there was some turnaround activity in Mid-Continent. That, and then the fact that residuals have been priced at a significant discount. Both of those contributed to the Maya discount. It has come in a bit, and then the Mexicans have adjusted the K to try to get it back to where they think the market should be. Yes. I think we'll still have decent discounts, but they have come in.
Right. Could you clarify where the Mexicans think it should be?
Well, what do we say, Bill, on Maya discount?
Well, into a sunk coker, I have said to all of you that we need in this 10% range so that we would have economics to go through the coker. But if you have good economics in a coker, you need 15%.
I get it, Bill. I have heard you say that. That is kind of clear as long as, I guess, on the contractual side, that is their view, too. I had not heard you kind of. We had not squared that circle previously. Then the residual fuel aspect to the discount, I guess I have heard you say in the past is kind of a secular issue to do with lower demand for resid fuel. Could you just, in the one minute or so we have got left, talk a little bit about how you see that playing out?
Well, China is not running resid anymore. They are running crude, okay? So that has backed resid into the marketplace, and then with Libya production back online, we have just found ourselves in longer supply than we have been in the past, and so that is what helped.
I think the demand side is weak as well, right?
Yeah.
Great. Thanks a lot.
Our next question comes from Chi Chow from Macquarie Capital. Please go ahead.
Great. Thank you. Just one more question that's light heavy discussion. Are all your barrels the heavy barrels in the Gulf Coast priced off Maya, or do barrels from Venezuela and Colombia, there's a price on a different metric?
They all look at Maya, Chi, but they're not all priced off of Maya.
So the non-Pemex barrels, do you expect the differentials to stay wider on those barrels than what is happening with the formula based on Maya?
I would think so.
Okay. Great. Then, just in first quarter in general, we talked a little about this, but how is the environment looking for you now in the different regions, 1Q versus what you realized in the fourth quarter?
Chi, it is really kind of too soon to say. It is too soon to get any guidance for the first quarter, particularly on margins.
However, we did say that the heavy differentials or discounts did narrow.
Right. Okay. Bill, you mentioned it a couple times here on Keystone XL. Do you have any thoughts on how this might go?
I don't. You mean the answer of what the administration's going to do?
Yeah, exactly.
My thought would be no better than yours.
Okay.
However, I think it's just ridiculous. There's pipelines everywhere. There's a pipeline in front of your home, out in the streets. Canada's an ally. The refineries on the U.S. Gulf Coast need the Canadian oil. The jobs and the assets and the taxpayers are here in the United States. My opinion's no better than yours.
Yeah. Seems pretty absurd if it doesn't go. Yeah. Thanks, Bill. Appreciate it.
Our next question comes from Doug Leggate from Bank of America. Please go ahead.
Well, hi guys. Sorry for the follow-up. I just had a couple of quick ones I want to hit you up again. Can you talk about the cash burn in the quarter? What went on there in terms of working capital? It looks like there was a big move there. Finally, any comments on what you are hearing in terms of potential LIFO accounting changes on inventory and how that might affect you guys? I will leave it there. Thanks.
Okay. In the fourth quarter, we did have an increase in our receivables quite a bit. It is about $700 million, but it was really a timing issue as our cash receipts have picked up quite a bit here in January. Part of the differentials or the reduction in cash was we had a tax payment in the fourth quarter, too, a large one. So that was part of the reason cash going down.
I will note that this business is a taxpayer of nearly $500 million in the quarter.
Noted. Thanks.
You asked a question on LIFO?
Yeah, I am just curious about what you guys are hearing about potential changes and what would happen if we did see international accounting standards imposed across the U.S.
Our LIFO reserve is—
$6.7 billion.
—is the value not on the books? $6.7 billion.
That's correct.
We have $6.7 billion of value that is not represented on our books. If they did away with LIFO and nothing changed, we would owe tax on $6.7 million. Again, we would be a taxpayer.
Okay. How much of that would be cash and how much would be non-cash? Can you quantify that?
It would be cash. We'd pay 35%, I guess. 35%?
Yeah. That's around
35% of $6.7 billion.
Okay. Obviously, a scary number, guys. Can you put some framework around how likely or what progress you think has been made on that issue? I'll leave it at that.
Well, I'm going to say it's not going to happen. LIFO is used in many industries. It's not unique to the oil business, but I don't think it would happen. If it did happen, let's say it did, then we would obviously lobby for a payment schedule. I mean , obviously.
Great. Thanks, guys. Appreciate it.
Okay.
Bye, Doug.
Our next question comes from Robert Kessler from Tudor, Pickering. Please go ahead.
Hi, guys. Sorry for the double up. I know you want to wrap up the call, but since you opened Pandora's box of Brent versus LLS and how you calculate that spread, you referenced a $4 - $5 cost of moving LLS up to the East Coast. I guess my question would be, that's a limited market, and with the rate of growth in U.S. supply, you saturate that market in maybe a quarter or so worth of time. How do you price the spread post that event?
Okay, so you're saying what have you got—?
Maybe I just answer you. That's way out in the future, but I will say to you that the marginal cost of transportation is going to be what is going to be the diff. If Bakken lays into the East Coast at $15 - $17 by rail, and you can lay it into the U.S. Gulf Coast at $12 by rail, you're going to have an inherent differential there. I think that's why you saw one of our competitors lock up some transportation, water transportation from the Gulf Coast up to the East Coast. We would think then those differentials, when the markets are in balance, will all equate close to the tariffs of the marginal source, water from the Gulf Coast to the East Coast, or rail from the Bakken or somewhere out there to the East Coast versus getting it all down to the Gulf Coast.
Yeah.
You'll have that delta.
I get you on the once you are in balance, but the moment you flip to a net long position on the crude and you filled up all the coasts, I guess, is what I am trying to get to.
Well, then it is looking for a home and who can take it, and it will drop. If you cannot export crude, then it is going to be pushing to another refinery, some other place. The other thing it will keep doing is discounting and keep backing out some of these other types of crudes. Exactly what Valero is looking at here, at our Houston Refinery, where we are a feedstock buyer, we are looking at a crude unit to produce our own feedstock.
Yep.
You have projects like that we, and I am sure others will look at to keep filling this up.
I could be wrong, but let us just say it comes quicker than that project comes online. You have already sort of maxed out at, what, 530,000 bbl a day in your Gulf Coast system. You have already got a scenario where some of your light sweet domestic delivery is equal to your medium sour grades. Is there a scenario where you could force feed more into your Gulf Coast system while you wait on those projects?
Not to a great extent. We would need the projects, because you would overload your light ends handling capability.
Yeah.
However, we have very smart people, and our people are out there trying to figure out how to handle the light ends. But the increment would be if the delta gets wide enough, we are going to take it to Quebec.
Yeah. Fill that one up pretty quick too, I imagine.
Well, it is a 200,000 bbl and some thousand barrel a day refinery, but yeah. But it will be because we like those numbers, and then we are also involved in Line 9, so you will be feeding Quebec from a lot of different ways. That will be another refinery that today is a —so it is Canada, but today runs a foreign suite for Canada, and instead it might run U.S. suite and Western Canadian.
Mm-hmm. Thanks for the color. Appreciate it.
Okay. Thanks, Robert.
That was our last question. I will now turn it back to the speakers for any closing remarks.
Okay. Thank you, Trish. I just want to thank investors for listening to the call. If you have further questions, please contact Investor Relations. Thank you.
Thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating.