瓦萊羅能源 (VLO) 2012 Q4 法說會逐字稿

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 www.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 described in our filings with the SEC.

So 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 loses 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 the 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 to 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 barrels per day 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 to -- 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 start-up 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 barrels per day 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 barrels per day.

We are continuing to work on a 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 US 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.

US 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 retail -- the separated retail business will perform well and unlock value for shareholders for several reasons.

So 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 US 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.

And 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 gallons per day 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 at 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 railcars, rail unloading facilities, pipelines, storage, and terminals.

The objective is to increase our access to more volumes of discounted US 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.

And the third strategic area is for expanding our distillate focused hydrocracker, 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.

And 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 to 1.45 million barrels per day, Mid-Continent at 390,000 to 400,000 barrels per day, the West Coast at 245,000 to 255,000 barrels per day, and North Atlantic at 450,000 to 470,000 barrels per day.

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, and 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 and net interest expense should be around $85 million.

Total depreciation and amortization expense in the first quarter should be around $405 million, and our effective tax rate in the first quarter should be approximately 35%.

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 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.

(Operator Instructions)

Jeff Dietert, Simmons.

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 US crude or Canadian crude influence in the fourth quarter?

We did well in 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 look like, and they were very strong.

We also ran a lot more resid -- well, we ran a bit more resid in the quarter, but we ran resid with better pricing than we had in the third quarter.

A lot of that had to do with the fact that the Libyan production was back on stream.

So basically the guys did 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 700,000 barrels a day.

So all in, if you look at the crude slate, we had discounted crudes coming in, in every form.

How do you see your feedstock changing with the addition of Seaway having started up an incremental 250 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.

And we're -- we mentioned, I think, in the notes that we were 100% domestic light sweet crude where we are running sweet crude in the Gulf so we backed off all of our foreign sours.

And 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 will end up seeing Brent trading at that discount that we're all expecting to LLS going forward.

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, Jim.

Evan Calio, Morgan Stanley.

Good morning, guys.

Great quarter today.

Follow up on some of those projects.

You mentioned fourth quarter replaced the imported lights with domestics and the Gulf Coast and Memphis, and you are pursuing several options.

I believe you are considering 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 block.

Can you comment generally on what those projects are, the cost magnitude, to mention maybe the logistic spending 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?

We are looking at a lot of rail projects and the logistics capital, if I look at the logistics capital that we have in the 2013 budget, it is -- a lot of it has to do with dock capacity, just being sure that we have the ability to export the volumes that we've got.

We think today we can put 225,000 barrels a day of gasoline on the water, and we're looking at ways to increase that at St.

Charles and Port Arthur.

Diesel we think we can move 280,000 a day.

We're looking at projects to take that up to over 400,000 barrels a day.

A lot of the capital that we have and the capital forecast is for that.

In addition, we announced that we bought the railcars, and we're working projects to figure out where we want to take this crude with these railcars.

We certainly have some things in mind, but we're looking at projects, for example, at St.

Charles, to rail crude in.

We've got a project to rail crude into Quebec.

We've got the two West Coast refineries we're looking at rail options for.

And then Memphis, we think we can rail a significant amount of crude into Memphis.

So we're working all of those options, and the guys are going through the overall logistics strategy for that, including potentially additional railcars.

So as far as the capital attributed to it, right now we don't have anything identified above the plan.

So all those things, 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 '13.

That's great.

And in terms of Memphis, you say that you backed out all foreign imports there, which I presume used to come up cap line.

What are you -- what are you running there, and how is it getting there?

And is there any yield pick up from the slate change at Memphis that's improved its profitability?

I'll speak to the crude supply piece, and maybe Lane wants to talk to the yield improvements.

But we're running Bakken that's really still coming up cap line, so we haven't 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 continued use cap line.

In terms of the quality at Bakken, it's nominally around LLS.

But I would say because LLS has historically been a blended barrel made from a number of different components, Bakken is a neat barrel and it's been in terms of its rateability 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 it's really -- it is value versus, say, LLS, directly a function of what the gas crack is but nominally it's slightly -- today it's slightly discounted on a quality basis to LLS.

For us though, we're getting quite a bit of value just out of the steady operation running Bakken need to our refinery day in and day out to Memphis.

I'll leave it there, guys.

Thank you.

Appreciate it.

Doug Leggate, Bank of America.

This question is really for Joe, but as you see the light sweet borrow 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 this 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 not with the discount?

I'm just curious as to how you see that playing out, then I've got a follow-up.

That's a good question.

Bill?

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 will still have an acceptable discount against Brent.

So going into a sunk coker, we think that you will have economics to do that, but not to build a grass roots coker.

So what's 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?

Do you see what I mean?

Just because of the availability.

We'll see if Keystone actually gets built, but as you can see in the press today, Enterprise is having trouble moving the oil once it gets to Houston.

So we have a lot of availability, and personally, we've said that the discount -- and I know it's different today -- the discount LLS against Brent will move to several dollars, at least tariffs, but it could move more, and thus it will be attractive to run that.

But it's just so available where the heavy barrels are having to be imported.

So now you start to look around, and as I said, depends on what happens with Keystone.

But 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.

So we just manage the 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've 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 annual statement about having the competitive at the highest yield in the sector.

Can you help us understand what's framing that -- the scale of ultimately what you think between your dividend policy and buyback?

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'll leave it there.

Thanks.

Well, Doug, I think we clearly have demonstrated at the management team that we return cash to shareholders.

You go back to 2006, '07, 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 dividend 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 then we can, looking at our stock price today, then we make these investments.

So we tend to have balance in our approach.

You asked about the approximate 50 million shares that we issued in the second quarter of 2009.

And, sure, we would like to take those out and everybody that supported us at that time has sure had a nice return as well.

But it's not a goal, per se.

It's more of our stock is undervalued, and we'll have a balanced approach.

Great.

I appreciate the answer, Bill, thanks.

Robert Kessler, Tudor, Pickering.

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?

You're getting a deeper price for light crude at say Corpus than Houston, and now at Seaway, a deeper discount at Houston versus Louisiana.

And what do you expect to happen with that east-west spread going forward?

Then, are there any limits to exploiting a wider spread should one emerge?

Rob, you're on.

Your description of the market is what we're seeing.

Corpus crude is trading less than Houston crude, and Houston crude is less than St.

James.

And what do we expect going forward?

I think if St.

James is going to be Bakken based, it's always going to price more than Eagle Ford into Corpus or the Mid-Continent crude, the Permian crudes into Houston.

I would add to that, as long as these areas are long, so for instance, let's 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.

So declaring place is St.

James now for LLS, so you're going to have differentials toward Houston and differentials toward St.

James.

But 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?

I don't know if there's enough barge capacity, truly.

I think your question is would you store oil on the barge to take advantage, or are you talking about just shipping it?

Yes, I just -- to me, when you have a spread like that potentially emerge, you 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 to circumvent what might be in place already on the pipeline side, is there some kind of storage bottleneck?

I just want what could be a limiting factor that I might not be thinking of and your ability to displace that dislocation and offset it in your system.

Well, I would assume others are doing what we're doing.

We're fixing docks, we're increasing our capability.

So at Corpus Christi come the second quarter we'll be able to load a lot more onto water.

Lead time for railcars is a year to 18 months.

Lead time on barges is a year.

So I think it just tells you by those lead times that those type of assets are short or tight.

When you look at Western Canada Select, or bitumen Canada in general in the spread versus Maya in the Gulf, it seems like rail is a no-brainer.

Certainly you guys ordered a couple thousand more railcars.

Some of those will be put to work moving that crude down.

With about a year turnaround time on a new railcar, why could that not accelerate to an exponential degree, and where do you see that developing in overall market rail out of Alberta, say down in the Gulf Coast, in a year, two years time, and 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.

And so we're doing it.

Clearly we're looking at rail into Southern California, just like all our competitors are as well.

So 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 and 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 railcars, that this is a big part of our future in this business, is your logistics capability to move distressed crude oils to your refineries.

So if you were in 12 to 18 months time, if the market was moving 200,000 to 400,000 barrels a day out of Alberta by rail, that wouldn't surprise you?

I don't know the numbers as well as you do, but it does not surprise me there's going to be a lot of railcars.

I just don't know those numbers.

Sure.

Well, thanks for your comments.

We're looking at the same thing that I'm sure you hear from the other people.

Got you.

Thank you, guys.

Cory Garcia, Raymond James.

Good morning, fellows.

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 some better distillate yields overall.

Just wondering how we should think about that today.

Has it normalized back towards your expectations, I want to say closer to 60%?

Or, have you maintained these high levels and really how we get that around in terms of modeling?

Right now, as we're doing this test run, as Ashley alluded to in his opening remarks, we're at about 80% distillate yield.

That's [jet caro] 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.

Properties on the jet are great, so certainly these are great distillate yield and great product for our products guys to try to figure out where the best place to market it.

So we have new catalyst [Multiple Speakers], so you have high activity, and we think that this unit will run until we have to replace catalyst.

Three years.

Three years.

So there will be some degradation over that period.

That's right.

Okay, great, thank you, guys.

Roger Read, Wells Fargo.

Congratulations on the quarter.

You have 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?

Is this incremental Canadian barrels?

Is it Western Hemisphere?

Is it something out of the Middle East?

Is it a mix of the above?

And 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, we got them out of South America and Mexico.

And 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.

If I step forward to what you are 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 Hartford, then barge it down to St.

Charles, which we tend to be doing some of, can we do more of that?

And then rail, of course.

We don't know exactly what those numbers might be today, but we are looking at, we have heated railcars, and we are looking at the ability to move heavy sour Canadians via rail.

So we're looking at all the options there, Roger.

Okay.

Looking at the hydrocrackers, obviously we can all look at the prices of the various products but if I always understood it correctly, it was really sensitivity to natural gas as feedstock and power source.

Can you walk us through what we should 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?

Yes, Roger, there's several key drivers.

Natural gas is one of them, diesel is one of them.

Overall crude is one of them.

We've got sensitivities per barrel in the appendix to our standard IR slide deck.

But to give you a feel for how it has been running, it's been running at these planned test rates at around 50,000 barrels a day.

And so far in January, where the market has been with low gasoline cracks, but good diesel cracks, and pretty cheap natural gas, the EBITDA has been up around between $20 and $25 a barrel.

And we've been running at about 50,000 barrels a day.

So, it's been pretty much what we expected.

And this is a depressed environment.

Wouldn't assume January is full-year commodity price deck.

But in this environment, it's been pretty dang good.

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 would 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.

So as that crack picks up, then you should see overall margin.

I was interested in that.

The original calculations we looked at was more like two-thirds distillate, one-third gasoline and other.

So the 80% reflects the comments about catalysts over time.

Maybe we think two-thirds, one-third?

We'll see where it shakes out, because as Bill mentioned, there's -- the catalyst is highly selective rate now, which is advantageous.

We will see where it shakes out.

But, yes, I'm not ready to change the base model for it yet.

Okay, great.

Thank you.

Sam Margolin, Dahlman Rose.

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 plateauing?

Obviously there's been some pretty healthy inventory building over the past month or so on the gasoline side.

I was just wondering if there's any trends that stand out to you on the export front, if it's decelerating or if you anticipate the same kind of growth that we've had over the past two years.

Well, in the fourth quarter, we moved out almost 110,000 barrels a day of gasoline and it went primarily to Latin America and Mexico.

Those are pretty high numbers, because typically we're doing 60 to 70 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.

From a sustainability perspective, we still think that these export markets are going to be very good.

In the first quarter of '13 from a gasoline perspective, we'll probably export less than we did in the fourth quarter and a lot of that has to do with the turnaround activity we have going on at Corpus Christi.

If we talk about diesel, diesel inventories, unlike gasoline inventories, diesel inventories are low.

They're at the low end of the five-year range, and although US demand for distillate continues to be weak, distillate demand abroad is strong, and it continues to grow.

And the US, I think we exported over 1 million barrels a day of diesel fuel.

That's up significantly from where it was last year.

Valero exported 157,000 barrels a day of diesel fuel in the fourth quarter and will increase that volume in the first quarter as we've got the throughputs of the new hydrocracker.

But, from our perspective, and I think everybody else's, it's always a market-driven phenomenon and is the ARB open or not?

If the ARB is open to move the barrels to South America or Europe, we'll move them.

If not, we'll keep them here at home.

Thank you.

That data was really helpful.

Secondly, on the East Coast, I'm sure you saw it was officially announced a plant became up for sale.

Historically it hasn't 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.

And so I think as far as a refiner goes, we're still a supplier, marketer into those markets, so our actions speak for themselves.

Okay.

Fair enough.

Thanks so much.

Have a good one.

Blake Fernandez, Howard Weil.

Congratulations on the results.

Had a question for you on the retail spend.

Presumably the $1.1 billion of cash coming to the parent company, I assume that's 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, Valero, we've got $7 billion worth of debt.

We'll be receiving, as we put in the release, $1.1 billion in cash from the separation.

We'll have about $300 million of tax leakage associated with the separation.

And then, of course, we can -- we're retaining 20% of CST Brands, and at some point in the future, I think within 18 months we'll dispose of that.

And, Mike, to be clear, that 18 months, should that be thought of as a slow bleed into the market, or is that hold it for 18 months, then all at once sell those shares?

We have not determined how we will divest that.

We'll be doing that in the next few months.

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've 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'm 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's happening in the marketplace, and I'm really talking about logistics and terminalling here, but really for our organization, the retail spin is occupying many of our people, and we need to execute to get this done first.

I haven't changed what we're saying on this subject at all.

Thanks, Bill.

Faisel Kahn, Citi.

Good morning.

Wondering if you could go back to the sweet crude oil.

The crude oil input into the Gulf Coast, particularly the sweet crudes.

You talked about how you backed out the forward imports of sweet crude into the Gulf Coast, I believe into Memphis.

What was the -- in the fourth quarter, what was the impact of backing out those foreign crudes?

What kind of uplift did you get from consuming domestic sweets versus buying foreign born sweets in the fourth quarter?

At Memphis, that was really where this happened, right?

Lane, do you have a good idea?

Are we trying to dollarize it?

I think he's looking for --

I have directionally the numbers.

We were paying LLS plus $0.50 and now it's LLS minus $0.50.

It's a ballpark of $1 a barrel, something like that.

The landed cost, and it depends on when and which -- because it's moving all over the place.

We've been making the switch over the past year.

We were working in foreigns industry 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 -- $1 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 foreigns, or domestic sweets into the Houston area and backing out medium sour.

So I think that's the other move that we're seeing.

In terms of dollarizing, I'd have to check it, but it's not just foreign sweets at this point, particularly in that Houston market.

We're seeing where we may be displacing some medium sours too.

Right.

If I'm looking at the sequential improvement in margin from the third quarter to the fourth quarter, I get that the heavy crude discount has widened out, and I get the Mars discount has widened out.

I'm trying to figure out, did your purchases of light sweet crude, did they get -- 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 don't think there's any change relative to the purchase price of these crudes.

And I think you got it right.

It think 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.

Got it.

However, we always act in our economic self-interest on this.

So we switched to a domestic crude because it was more economical.

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?

They were mostly trapped.

Okay.

We do move Permian Basin Midland area crudes up to McKee and Ardmore, but we've always done that.

Okay.

Were there any derivative movements in the quarter, any gains or losses, non-cash derivative gains or losses in the quarter?

No.

Okay.

Fair enough.

Thanks, guys.

Appreciate it.

Ed Westlake, Credit Suisse.

Congrats from me on the numbers.

I wish I had a 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 Bakken trading into St.

James at a premium.

I appreciate it's a moving target but if it's possible to be a bit specific about what is the Eagle Ford discount into Corpus, what is the Permian discounts or the Seaway blends down into Houston and what is the Bakken discount into St.

James, say relative, in 4Q, relative to LLS?

That would be helpful.

So relative to LLS, and if we keep it as simple as we can and we look at transportation.

There's so many good reports out there now that are addressing these issues, and we look at those, too.

But you've got a couple of dollars of transportation to get Eagle Ford over to Houston, then you have another couple dollars to get from Houston over to St.

James.

So, theoretically you could argue that Eagle Ford audit 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, WTI is $3 or so, $3.50, to the coast, WTI is going to be, if you took it into the Houston markets, you can get it there for $3.50 so it would be $1.50 over the Eagle Ford into Houston.

Then if you took it all the way over to St.

James, you're $3.50.

And then -- so this is the math that we're working on.

What we're doing is the same way you guys are.

We are saying, what is it going to be if LLS -- Bill mentioned it before that St.

James would be the clearing point for LLS and everything is going to trade, as you move west, to a discount to LLS.

What's that do with Brent?

You are going to have Brent ultimately into the East Coast be at a LLS plus $4.50 to $5 a barrel, which is the US flagged transportation cost to get it up there.

Yes.

So that makes a lot of sense, and that's very helpful.

Thanks very much.

Then I've got a chart of LLS Maya in front of me for what it's worth.

Obviously there was a bump-up in Q4 and clearly your earnings have benefited from that.

Maybe talk a little bit about market conditions as we come into Q1 in terms of, particularly, the surprise that 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 we saw in WTS there despite 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.

Lane and I were talking about it earlier today.

We're seeing medium sours price into the Gulf now basically at a flat price to light sweet domestic crude.

Right.

So, anyway, we're still seeing decent discounts on these and you are seeing pressure on light sweet as more of it gets there.

Thanks very much.

Ann Kohler, Imperial.

A question, certainly, regarding some of the projects that you're 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.

We're very -- I think you are alluding to the greenhouse gas permitting.

Yes.

So we are -- in 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 allows us to be underneath the greenhouse gas permitting.

But this will affect the industry.

I'm sure everybody is looking at this in terms of their investment.

It may ultimately limit how big some of these investments can be, if they can make 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.

Paul Sankey, Deutsche Bank.

Congratulations to Joe on making president as well.

If I could ask you firstly about the export story, you've talked about it, but could you just clarify?

I think you said you're exporting about 100,000 of gasoline, and I think it was 200,000 of distillate.

Is that at export capacity now?

No, I would say no.

And the gasoline, that was a good quarter.

100,000 barrels a day is a good quarter for gasoline exports.

But we have the ability probably, Paul, to take out 225,000.

So I got the 225,000 number, then I think you're 280,000 diesel.

280,000 is where we would say we are today, then we've got the logistics projects, as we mentioned, that improve docks and take-away capacity.

We expect it is going to take us up to about 425,000 barrels a day of capacity.

And when -- did you say the time frame on that is 2Q?

No, no, we're working on projects right now.

Some of them will come on in the second quarter, but really I think these projects we are talking about we'll have in place by the end of the year, or early next year.

Q2 was be 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?

Yes, some of these projects, and really it is primarily stuff we're doing at St.

Charles and Port Arthur, will take us up to about 250,000.

So just the follow-up is, one of the issues that we see with all of these crude differential moves is being at times very narrow, heavy light spreads but we had a pretty good number in Q4.

How is that dynamic looking 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 essential a lot of they have crude is priced on a formula with a K factor?

We would naturally expect that to be a narrower number going forward because of how wide it got in Q4?

As I mentioned, it's come in a bit, Paul.

And a lot of it had to do with the fact that WTS was dislocated for a period there when there was some turnaround activity in Mid-Continent.

That and 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.

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.

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 -- to have good economics in a coker, you need 15%.

But I --

I got it, Bill.

I've heard you say that.

That's clear, as long as on the contractual side that's their view, too.

I hadn't heard you -- we hadn't squared that circle previously.

Then the residual fuel aspect of the discount, I've heard you say in the past is a secular issue to do with lower demand for res fuel.

Could you just, in the one minute or so we've got left, talk a little bit about how you see that playing out?

China is not running resid any more.

They're running crude.

So that factors it into the marketplace.

Then with Libya production back on line, we've just found ourselves in longer supply than we have been in the past.

So that's what helped.

I think the demand side is weak as well, right?

Yes.

Great.

Thanks a lot.

Chi Chow, Macquarie Capital.

One more question on this light/heavy discussion.

Are all your barrels, the heavy barrels in the Gulf Coast priced off Maya?

Or, do barrels from Venezuela and Colombia 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's happening with the formula based on Maya?

I would think so.

Great.

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's really too soon to say, too soon to get into guidance for the first quarter, particularly on margin.

However, we did say that heavy differentials or discounts did narrow.

Right.

Okay.

Then, 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 to the answer of what the administration is going to do?

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 is an ally.

And the refineries on the US Gulf Coast need the Canadian oil.

And the jobs and the assets and the taxpayers are here in the United States.

But my opinion is no better than yours.

Seems pretty absurd if it doesn't go.

Thanks, Bill.

Appreciate it.

Doug Leggate, Bank of America.

Can you talk about the cash burn in the quarter?

What went on there in terms of working capital?

Looks like there was a big move there.

And finally, any comments on what you're hearing in terms of potential LIFO accounting changes on inventory and how that might affect you guys?

I'll leave it there.

Thanks.

In the fourth quarter, we did have an increase in our receivables quite a bit, so about $700 million, but it was really a timing issue as our cash receipts have picked up quite a bit here in January.

And part of the differentials are the reduction in cash, we had a tax payment in the fourth quarter, too.

A large one.

So that was part of the reason cash is going down.

Which I will note that this business is a taxpayer of nearly $500 million in the quarter.

Thanks.

And then you asked a question on LIFO?

Yes.

Just curious about what you guys are hearing about potential changes and what would happen if we did see international accounting standards employed across the US.

So our LIFO reserve is the value not on the books, $6.7 billion.

We have $6.7 billion of value that is not represented on our books.

So if they did away with LIFO, and nothing changed, we would owe tax on $6.7 million.

And 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%.

35% of $6.7 billion.

Obviously a scary number, guys.

Can you put some framework around how likely or what progress you think has been made on that issue?

And I'll leave it at that.

I'm going say it's not going to happen.

And obviously, LIFO is used in many, many industries.

It's not unique to the oil business, but I don't think would it happen, and if it did happen, let's say it did, then we would obviously lobby for a payment schedule.

But, obviously.

Great.

Thanks, guys.

Appreciate it.

Robert Kessler, Tudor, Pickering.

Since you opened Pandora's box of Brent versus LLS and how you calculate that spread, you referenced a $4 to $5 cost of moving LLS up to the East Coast.

My question would be, that's a limited market.

With the rate of growth in US 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 are saying --

Maybe I'd 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 dip.

So if the Bakken lays into the East Coast at $15 to $17 by rail, and you can lay it into the US Gulf Coast at $12 by rail, it is 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.

So we would think then, those differentials, when the markets are in balance, we'll 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.

(Multiple Speakers)

I get you on once you are in balance.

But the moment you flip to a net long position on the crude and you filled up all the coast is what I'm trying to get to.

Then it's looking for a home, and who can take it, and it will dry.

So if you can't 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're a feedstock buyer, we're looking at a crude unit to produce our own feedstock.

So you have projects like that, that we, and I'm sure others, will look at.

And I could be wrong, but let's just say it comes quicker than that project comes on line.

You've already maxed out it at, what, 530,000 barrels a day in your Gulf Coast system.

You've 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 need -- we would need the projects, and it's because you would overload your light ends handling capability.

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're going to take it to Quebec.

And fill that one up pretty quick, too, I imagine.

It's a 200,000 barrel and some a day refinery, but it will be because we like those numbers and we're also involved in line nine so you will be feeding Quebec from a lot of different ways.

That will be another refinery that today is a -- so it's Canada, but today runs foreign sweet for Canada, and instead, it might run US sweet and western Canadian.

Thanks for the color.

Appreciate it.

Thanks, Robert.

And that was our last question.

I will now turn it back to the speakers for any closing remarks.

Thank you, Trish.

And 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.

You may now disconnect.