瓦萊羅能源 (VLO) 2013 Q4 法說會逐字稿

Welcome to the Valero Energy Corporation reports 2013 Fourth-Quarter Results conference call.

My name is Sylvia and I will be your operator for today.

(Operator Instructions)

Please note that this conference is being recorded.

I will now turn the call over to Mr. Ashley Smith, Vice President of Investor Relations.

Mr. Smith, you may begin.

Thank you, Sylvia; and good morning to everyone listening to our earnings call today.

With me today are Bill Klesse, our Chairman and CEO; Joe Gorder, President and COO; Mike Ciskowski, our CFO; Gene Edwards, our Chief Development Officer, and several other members of Valero's 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.

I would like to direct your attention to the forward-looking statement disclaimer contained in the press release.

In summary, it says that statements in the press release and on this conference call that state the Company's or management's expectations or predictions of the future are forward-looking statements intended to be covered by the Safe Harbor provisions under federal securities laws.

There are many factors that could cause actual results to differ from our expectations, including those we've described in our filings with the SEC.

So as noted in the release, we reported fourth quarter 2013 earnings of $1.3 billion, or $2.38 per share.

Excluding the $325 million non-taxable gain on the disposition of Valero's retained interest in CST Brands, our adjusted fourth-quarter 2013 earnings were $963 million, or $1.78 per share, which compares to the fourth quarter 2012 adjusted earnings of $1.05 billion, or $1.88 per share.

For the full-year 2013, we reported earnings of $2.7 billion, or $4.97 per share.

Excluding the aforementioned gain in special items related to our May 1 spinoff of CST Brands to Valero stockholders as detailed in the release, full-year 2013 adjusted earnings were $2.4 billion, or $4.42 per share.

Operating income was nearly the same in the fourth quarters of both 2013 and 2012.

An increase in ethanol operating income was offset by decreases in the refining and retail segments.

The retail segment decrease was due mainly to the effect of the May 1 spinoff of CST Brands.

The decrease in refining segment fourth-quarter operating income from 2012 to 2013 was primarily due to three key items: additional depreciation and amortization expense driven mainly by the new hydrocracker units at our Port Arthur and St.

Charles refineries, increase in operating expense is mostly driven by higher energy cost, and a decrease in throughput margin.

The refining segment throughput margin in the fourth quarter of 2013 was $11.20 per barrel, which is down approximately $1 per barrel versus the fourth quarter of 2012.

A decrease in gasoline and distillate margins in our regions was mostly offset by an increase in medium and heavy sour crude discounts.

For color on the crude pricing from the fourth quarter of 2012 to the fourth quarter of 2013, the Mars medium sour crude discount since Brent increased favorably by $7.66 per barrel, and Maya heavy sour crude oil discount since Brent increased favorably by $2.73 per barrel.

Regarding light crude pricing during the same timeframe, WTI discounts to Brent narrowed unfavorably by $10.10 per barrel, while the LLS prices improved favorably by $8.39 per barrel, going from a premium to a discount versus Brent.

Our refining throughput volumes averaged 2.8 million barrels per day in the fourth quarter, which is an increase of 139,000 barrels per day versus the fourth quarter of 2012.

Refining volumes were higher primarily due to less maintenance activity and the incentive of favorable crude discounts, particularly for light crude in our Gulf Coast system.

Refining cash operating expenses in the fourth quarter of 2013 were $3.79 per barrel, which was similar to the fourth quarter of 2012.

Our ethanol segment earned record operating income of $269 million in the fourth quarter and $491 million for the year.

The outstanding results are attributed to strong gross margins driven by low industry ethanol inventories and a decline in corn prices, which were combined with record high quarterly average production volumes of 3.6 million gallons per day.

In the fourth quarter of 2013, general and administrative expenses excluding corporate depreciation were $175 million.

Net interest expense was $102 million, and total depreciation amortization expense was $437 million.

The effective tax rate was 28.6%, which is lower than guidance due to the $325 million non-taxable gain on the liquidation of our CST Brands shares in November.

Adjusting for this item, the effective tax rate was 35%.

At the end of the year, total debt was $6.6 billion.

And cash and temporary investments was $4.3 billion, of which $375 million was held by Valero Energy Partners LP.

Our debt-to-capitalization ratio net of cash was 10.2%, and we had over $6.2 billion of available liquidity in addition to cash.

Regarding cash flows in the fourth quarter, capital expenditures were $538 million, including the $107 million for turnarounds and catalysts.

Also in the fourth quarter, we received net proceeds of $369 million from the offering of Valero Energy Partners LP.

That cash was retained in the partnership.

We also received $448 million of (inaudible) proceeds from the disposition of our remaining interest in CST Brands, which included $19 million in associated fees.

In the quarter, we returned $459 million in cash to our stockholders, paying $120 million in dividends and by purchasing approximately 8.3 million shares of Valero common stock for $339 million.

This brings our full-year 2013 stock purchases to 22.4 million shares for $928 million plus dividends of $462 million for a total of cash return to stockholders of nearly $1.4 billion.

For perspective, that is more than double the total cash that we returned to stockholders in 2012.

Also in 2013, our spinoff of CST Brands was a dividend to Valero stockholders based on its current or recent equivalent value to approximately $3.60 per share of Valero including CST Brands' cash dividends.

Earlier this month, we continue to show our commitment to return cash to stockholders by purchasing 4 million shares of Valero common stock for $208 million and by increasing the regular cash dividend last week.

For 2013, capital expenditures, including turnaround and catalysts, were $2.76 billion, or more than $90 million below our previous guidance.

For 2014, we maintain our guidance for capital expenditures, including turnaround and catalysts, at approximately $3 billion.

Similar to 2013, we expect approximately 50% of total spending to be on state and business capital.

The other half of our 2014 capital spending is allocated to strategic growth investments, largely in logistics and increasing our capability process to process light crude oil.

When modeling our first-quarter operations, you should expect refinery throughput volumes to fall within the following ranges: US Gulf Coast at 1.475 million to 1.525 million barrels per day; US Mid-Continent at 390,000 to 410,000 barrels per day; US West Coast at 230,000 to 240,000 barrels per day; and North Atlantic at 440,000 to 460,000 barrels per day.

We expect refining cash operating expenses in the first quarter to be around $4 per barrel.

For our ethanol operations in the first quarter, we expect total production volumes of 3.6 million gallons per day; and operating expenses should average $0.37 per gallon, which includes $0.04 per gallon for non-cash costs, such as depreciation and amortization.

Also in the first quarter we expect G&A expense, excluding depreciation, to be around $160 million and net interest expense should be about $100 million.

Total depreciation and amortization expense in the first quarter should be around $420 million, and our effective tax rate in the first quarter should be approximately 35%.

Okay, Sylvia, we have concluded our opening remarks.

We will now open the call to questions.

I do want to remind our callers that we will continue the previous practice of limiting each turn in the queue to two questions.

If you have additional questions, you can always rejoin the queue.

(Operator Instructions)

Doug Leggate, BofA Merrill Lynch.

I've got a couple of micro-questions, actually, I'm hoping you can at least give your perspective on.

The first one affects you guys in the Gulf Coast is the pricing of Maya.

It continues as an indicator -- I guess of heavy sour in the Gulf -- it continues to create fairly wide relative to LLS in particular.

Are you guys seeing anything that is happening differently in terms of either flows out of Mexico or the [K-factor] pricing that Pemex is using?

Any color on how sustainable you think this might be?

And I've got a follow-up question.

Doug, this is Gary Simmons.

The Maya formula -- 40% of the Maya formula is based on WTS.

And so I think of lot of what you have seen in the Maya formula is that they are basically chasing the Brent TIR.

And so it got very narrow and then the Brent TIR widened back out and Maya went with it.

So we are seeing some additional production come to us.

I think some of that was due to refinery turnarounds in Mexico.

So we are getting some volume above our contract levels, but the pricing has been more tied to the volatility in the Brent TIR than anything else.

So you're not -- do you have a perspective, Gary, as to whether this is something that is somewhat transitory?

Or do you -- does it change the way you think about your feedstock given that all the focus, obviously, is on light sweet in the Gulf?

But if heavy's going to trade that wide, how does it impact your planning in terms of how you're going to basically plan your slate going forward?

Yes.

So we have a lot of flexibility in the Gulf Coast system, being able to swing from the heavy barrel to the light.

It has been encouraging that the Maya has continued to price at competitive values to the medium sours and the light.

I don't think it really changes our thinking going forward though.

Okay, thanks.

My follow-up is also a micro-question, if I may, and it relates really to gasoline.

We are all focused on gasoline exports in terms of the expansion you guys have got going on.

So I wonder, first of all, if you could give us an update as to where you are currently.

And, really, what is behind my question is, it seems to us that the US was self-sufficient as across the country for the first time in the fourth quarter and we've basically seen gasoline in the Gulf trade under Brent in terms of an apples-to-apples basis.

So I'm just curious as to -- are you concerned that we're going to see gasoline pricing move away from Brent towards domestic crude?

And if so, how does that change your export policy?

And I'll leave it there.

Thank you.

Hi, Doug, this is Joe.

Listen, on the exports -- in the quarter, we did 133,000 barrels a day of gasoline exports.

December was particularly strong, but it was pretty consistent throughout the entire quarter.

If you look forward to the first quarter, I would tell you that we're seeing volumes at similar levels.

And it all has to do with the fact that we've had some low prices and the Latin American countries continue to be short.

And so we have the opportunity to move the barrels there.

I'll just give you the distillate number -- you didn't ask, but while we are on this we exported an average of 219,000 barrels a day of distillate in the quarter.

And those volumes look consistent going forward also.

As far as the -- I guess the longer-term view of gasoline and its relationship, we are in a strange period right now.

Prices have been low, refinery run rates in the Gulf Coast have been very, very high, so we've had a significant volumes of production.

And we are at the time of the year when gasoline demand is historically down.

And so I guess the guys who pulled the stats here that came out just today, and we had a pretty good pop in gasoline demand, but we're getting into the time of the year -- although its hard to imagine right now with as cold as it is -- we're getting into that time of the year where, ultimately, we will stop blending butanes in, the gasoline pool will tighten up, and we should get a little bit of recovery in the margin.

So I don't really see that much difference this year versus last.

Gene, you --

Yes, this is Gene.

My only extra comment would be, I think as you move into the summer period, ultimately the gasoline has got to revert back to a breadth-related type [crack] because of the incremental refineries in the world are so priced in off of a Brent-priced crude.

Ed Westlake, Credit Suisse.

Thanks for the time and, obviously, great earnings.

Congratulations.

Obviously, Q3 to Q4, there was a big swing, and there's a number of different things that could've accounted for that -- crude discounts widened out in the Gulf; butane blending in winter; product exports we just had a brief discussion on; secondary products was something that hurt in Q3 and obviously got better in Q4 if the crude price came back a bit; and then, obviously, there's the continued self-help that you guys are putting in with the new units.

I'm just trying to look for some color as to which, do you think, of those, or something else -- RINs maybe -- drove the big delta Q over Q.

Yes, Ed, you kind of nailed most of those things.

This is Ashley.

I would say, in absolute terms -- there's a million ways you can slice and dice this, but in absolute terms, the biggest drive -- and somewhat in terms of indicator of capture rate, one of the biggest drivers was just outright crude discounts helping out.

After that, from 3Q to 4Q, the decrease in RINs cost helped.

On a capture-rate basis, absolutely being able to blend butanes, which -- and get a price more like your [finished] gasoline helped out.

I would say those are the key drivers.

But just getting better crude discounts helped, not only in capture rate but also outright discount, outright cracks for margins.

Right.

Thank you.

And then the second unrelated question is, obviously, light crude is coming at you thick and fast from the Eagle Ford and eventually the Permian and all the pipes, so that's very helpful.

And you've announced that you're thinking about some topping units for late 2015.

You said relatively low cost per barrel.

I don't know if you've got an actual cost -- that would be helpful.

But, generally, if you can talk about how you take your slightly heavier designed refineries to be able to actually process this light crude that perhaps is better in other people's refineries.

Hi, Ed.

This is Lane Riggs.

We -- when we are going ahead with our 70,000-barrel-a-day crude -- light crude unit at [Corpus] and our 9,000-barrel-a-day crude unit at Houston.

We have approval to do that.

And those are designed to run nominally about [50 ACI] crude, which is a little bit lighter than our crude diet in either of those crude units that we have existing.

So we can run some of those lighter -- a little bit incrementally a lighter crude.

We have less flexibility to be able to run something that looks a little bit more like [TI] -- maybe a little bit down to the low 40s.

But we -- this is -- these are really our big additions in terms of -- or not big, but our additions to the Gulf Coast (inaudible) to run these types of crudes.

And, Ed, these aren't -- these projects don't convert a heavy refinery to run light crude, they generally take light to medium refineries and just allow them to process additional like crude.

But it's still up the downstream unit.

A little more color on that -- what these do is these essentially are backing out.

We float those refineries or short topping capacity and long conversion capacity so what it will allow us to do is to buy less intermediate to fill our conversion capacity.

So it's really [displacing BGO] and light [sulfur ATP].

But it is not moving us from being -- it's not -- as Ashley commented, we are not -- we're adding crude capacity.

We are not displacing crude capacity.

Yes, we haven't seen any incentives to destroy heavy capacity because discounts are wide.

So most of this is just adding and -- either adding through construction or through processing in operations, finding additional debottlenecking and capability to process light crudes.

And if down the road light did completely disconnect and heavy stayed linked to global markets, how -- what would be the first thoughts on in terms of how you adjust -- would adjust the units to get these heavy refineries a little bit more flexible in terms of what they could take?

Well, we are still -- we still have some additional capacity, we think, with our existing units down there.

And it is something that we'll just -- we will continue to work on.

It's all a function of how disconnected it actually is and it can really get there.

But we still have some open capacity to run additional light crude in our Gulf Coast as it is today.

And then, after you get to when you really -- as you get there and you drive towards these limits, then it is all about trying to test what are the marginal economics of sweet crude versus medium versus heavy and we'll just -- we'll find out.

But it's just a matter of how disconnected it gets.

Okay.

Thanks so much.

Jeff Dietert, Simmons and Company.

My question has to do with Gulf Coast oil imports.

We had another robust import number in the DOEs today despite the wide differentials that were in place in November and December, which I would assume establish the import levels.

It appears that the countries that are shipping crude to the US are continuing to ship, despite the disincentives that were in place during the fourth quarter.

Can you comment on what you are seeing on both light and medium and heavy crude imports coming into the Gulf Coast?

Are those staying pretty stable for you and what are you seeing more broadly in the industry?

Yes, so overall, I would say we are not importing light crude into the Gulf routinely anymore at all.

Our imports are medium sour and heavy sour.

On the medium sour side, some of the medium sours that we were taking into the Gulf we've now shifted, and a lot of those barrels are now going to West Coast and the heavy sour has been somewhat (inaudible).

Secondly, could you update us on the hydrocracker rates?

How are they performing, both at Port Arthur and St.

Charles, and how are they performing in the fourth quarter and so far in 1Q?

This is Lane Riggs again.

They run very well in the fourth quarter and they are currently running well.

I would say we were able to optimize our Port Arthur refinery in looking at our permits -- really, our permits are based on a heat release or a firing rate.

As we ran at 57,000 barrels a day and looked at it a little bit more and optimized, we've actually been able to get the rates up to 60,000 barrels a day nominally and still live inside our existing permit.

But other than that, they are running as designed and doing quite well for us.

Thanks for your comments.

Sam Margolin, Cowen and Company.

I guess I'll circle back to imports for a second.

That's probably going to lead to a follow-up.

It's been our observation that a significant portion of the medium imports that are leftover industry-wide are from Saudi Arabia and Kuwait -- something like 80%, and more or less everything else -- legacy, medium imports from Nigeria and other places -- have been backed out.

Are these volumes from Saudi and Kuwait just much stickier because of refining interests from the exporting countries here or just because they are in more of a -- it's more in their interest to maintain US market share with those volumes?

And I guess what I'm getting at is, are these -- with everything else being backed out from the medium pool at a pretty rapid rate, are those volumes really an unlikely candidate to follow that trend?

For us, it really is a matter of economics and we've continued to see that the barrels that we are getting from Saudi and the barrels we are getting from Kuwait to be economic.

Again, we've shifted some of that volume to the West Coast and we see better value in moving those to the West Coast now that we have other options available to us in the Gulf.

But for us, it is an economic question.

Okay, so it is basically just a matter of price and the exporters are going to make the determination of whether there is another location to send it to or whether they need to market to US pricing.

Yes.

Basically?

Okay.

And then, this is a follow-up on imports and replacing imported crude with domestic crude.

The time to delivery of the average barrel through your system has been reduced significantly.

It stands to reason that the industry is able to structurally handle a lot lower import -- or, sorry, a lot lower inventory levels on an ongoing basis.

And we have seen significant draws, up until this week, of inventories from the Gulf Coast.

And I was just wondering if that de-risking of your supply is contributing to that at all and if that's also why the curve is so backward dated, potentially.

Well, it is difficult to say.

But we definitely have seen that, as we switched to more and more domestic crude, it is having an impact on the inventories in the required inventories in our system for exactly the reasons you are seeing.

All right, thanks so much.

Appreciate it.

Robert Kessler, Tudor, Pickering.

I wanted to ask about Quebec City as that refinery is slowly transitioning to 100% North America accrued feedstocks.

Can you give us the numbers for the quarter and how much was delivered by rail and by ship from Texas?

And maybe if I can add a bonus to that, the average late-in crude price to that refinery for the quarter?

Well I don't know that will give you the average late-in crude cost, but I can tell you that our rail has come up and has been very successful.

It has the capacity to do about 60,000 barrels a day.

It started up in August and we continue to ramp up volumes.

We began to hit some snags with the weather in December and January.

The cold weather really hurt that operation.

We were up to about 40,000 barrels a day in November.

The volumes did fall off in December and January a little bit to the cold weather.

We also exported five cargoes from the Gulf to Canada in the fourth quarter.

So we've run Canadian send for the first time at Quebec.

We've run WTI.

We've run Bakken and we've run Eagle Ford.

We continue to ramp up our volumes there.

In the fourth quarter we saw some weather issues, even on the Gulf movements, that hurt us.

We continue to see some challenges on the logistics to be able to get the barrels to the water.

And then as you get into the winter in Quebec, the fact that we have to have ice collide ships in the supply chain, also, hinder our ability some to be able to get to the well up there.

But we continue to ramp up those volumes and see good economics on those barrels compared to our Brent-related alternatives.

That is good to hear.

What was the average throughput for the refinery overall for the quarter?

Yes, we -- Robert, I'm going to continue do take us (inaudible) near traditionally high records or at traditionally high rates.

But we are not going to disclose refinery-by-refinery throughputs and margins, things like that.

Okay.

And everything is still on track as (multiple speakers) -- go ahead.

I was just going to say, as you can see from the regional data for North Atlantic region -- ran at fairly high rates.

Yes.

And everything is still on track as far as future expansion and capacity to take North American crude, most notably the additional loading capacity in Corpus about mid this year coming on with another 50,000 barrels a day or so?

Yes.

So two significant changes during the year -- midyear the Corpus loading facility coming online and then in the fourth quarter we expect the line 9 reversal [to come online] also.

And you're pretty confident that hits 4Q and not 1Q?

Everything we hear still tells us 4Q.

Great.

Thanks very much.

Blake Fernandez, Howard Weil Incorporated.

I had a couple broader questions for you.

The first one is on rail regulations.

Obviously we are hearing some rumblings of more stringent regulations coming down here potentially at some point.

And I guess if I'm thinking about this correctly, certainly would help support differentials on the refining side, but then potentially impact some of the potential earnings you would get on the logistics side.

And if I recall, you've got about over 5,300 rail cars on the way.

And I'm just curious if you could talk about how you see this unfolding.

Does this impact your decision on owning versus leasing and basically any dynamics you see unfolding as a result of this?

Sure, Blake, this is Joe.

And I'm very impressed that you got our number of rail cars down.

You remembered.

Thank you.

Obviously, this is an issue.

The DOT has the ball.

They are involved.

They are working the regulations and I think the dates that we've talked about here is that they should have recommendations in place by November 14.

This is also an issue that's being worked by the American Association of Railroad, by the [AFPN] and many others.

And I would say, obviously, the conversations are around tightening the standards on cars.

So that would be something that we would expect to see.

There's a conversation around rerouting around urban areas, slower speeds through urban areas.

A lot of focus on classification of the cargo, so what type of crude is being carried.

All those things would make sense and I think we would expect to see some of that.

The one issue that is hanging out there that none of us really know about, because of the nature of the rail fleet, is how long would it take to retrofit?

And how long will they allow for a phase-in of any recommended changes?

The 5,320 cars that we have on order are all the rule 111A cars, so they do have additional safety features over traditional cars.

So we are just waiting to see where that goes, but we believe that cars with -- that would meet the standard would be okay.

As far as changing what we're doing, I don't see that this is going to have any impact on our plans to move crude by rail.

And then if you say, what happens if it materially affected the economics?

We currently have some 6,000 cars under lease in the fleet.

And what we would do is ultimately just go ahead and replace the cars that we have under lease with the cars that we own and we continue to use them for other services, such as asphalt and ethanol.

So, not a lot of downside for us on our investment in rail cars.

Okay, good.

Thanks, Joe.

And then, the second question, a little bit off but, on the ethanol side, obviously this has been a home run of an investment for you guys and you bought at the right time.

And, obviously, you've recouped all of that investment, if I'm not mistaken.

But I'm just curious, is there a lot of synergy between that and your refining business?

And I guess where I'm going is, ultimately, is this just a flip where you could basically just sell it at a premium and take your profits and walk away?

Yes, Blake, this is Gene.

Yes, the ethanol is doing quite well.

We produce more ethanol than we actually blend ourselves.

It's not necessarily in the same barrels.

We try to optimize both.

We try to get the highest netback in our ethanol plants and then our marketing operations tries to procure ethanol at the lowest cost.

Sometimes those intersect, sometimes they don't.

So I would say there's probably not a whole lot of synergy there.

It is roughly run as a -- it could be run as an independent business.

We are very happy with the returns we are getting though.

And I don't think the multiples you would get in the case of -- because last year was basically a breakeven business.

This year we've been doing almost $500 million.

In the prior year we -- 2011, we made almost $400 million.

So we're not exactly sure of how that would trade in the marketplace due to that -- all that volatility.

So I think we're just -- and also we would have a significant tax gain.

As you know the rapid depreciation -- tax depreciation we've had on these plans.

So I think we are satisfied with the investment, but we always look at our options too.

Okay.

Thanks, Gene.

Roger Read, Wells Fargo Securities, LLC.

I guess a couple of questions.

Some of the main things have been hit here, but getting back to the crude exports to Canada question.

And maybe not the exact feedstocks to the refinery or the crude cost this time around, but what much -- how much more progress do you need to more or less convert that refinery to pure North American crudes?

And then, once that is done, is there anything you can do about moving things to Pembroke in an advantaged way?

Is that something you would want to do in the current regime, or do we need changes in the -- either from the President or Congress on that front?

So, overall, Roger, we anticipate that, by the end of the year, Quebec will be running 100% North American domestic crude.

You will continue to see volumes ramp up.

I mentioned the two-step changes that occur; when we get our Corpus dock in place mid-year that will certainly help.

And the line 9 reversal -- when line 9 reversal is complete, then they certainly will be on 100% domestic crude.

The Pembroke question is a little bit more difficult.

We don't see that we would be looking to export to Pembroke, at least any time in the short term.

Okay.

And then, in terms of the bigger projects you are undertaking in Corpus and in Houston to move to using more light, what else are you able to do?

I mean, maybe it's just tweaking around the edges, but maybe in the aggregate, how many barrels of light do you think you might be able to run, say, 12 months from now versus what you are running today or what you ran in the fourth quarter along the Gulf Coast?

So, this is Lane.

I'm trying to figure out how to answer that question exactly.

So the two crude units are 100 -- will add an additional 150,000 barrels a day of domestic light crude capacity.

We believe we have somewhere on the order of about 300,000 to 315,000 barrels a day of sweet crude capacity on the Gulf Coast.

But, again, as I mentioned earlier, we have not filled all that capacity up yet.

So you will see as we get -- as the economic becomes absolutely compelling and all the logistics get debottlenecked we'll approach that number.

And it could -- I'm pretty confident it will be higher than that number but that's where we are today.

And the crude fraction (inaudible) our top reserve is a 15 project not a 12 months.

Right.

No, I understood it's two different.

I was trying to understand -- other than the two very large projects, what are some of the smaller things that can happen that maybe aren't as high profile but ultimately do have a positive impact.

And then, I guess my last question, cash flow -- I think Ashley mentioned at the beginning about twice the amount of capital return to shareholders in 2013 versus 2012.

Can you give us an indication of what you would expect or what you would plan to do in 2014?

I know you don't want to give guidance on a specific number, but maybe as a percentage of cash flow versus what we saw in 2013 that we could expect to be directed towards share repurchases, dividends, et cetera.

Well, we just raised our dividend to $1 per share on an annual basis.

So that is $540 million.

And then, on top of that, our capital budget is $3 billion.

And then the rest of it is how we conducted ourselves in the past and we take a relatively balanced approach here.

We will look at our dividend as the year goes on.

We will look at our investment opportunities, and I think you can expect the same actions you've seen from us in the past.

Okay.

Thank you.

Faisel Khan, Citigroup.

I think you may have answered some of this in your prepared remarks, but when I'm looking at the capture rate going up sequentially from the third quarter to the fourth quarter, can you give a little bit of breakdown of what caused that increase in the capture?

How much was crude related I guess in percentage terms versus how much was product related?

About half -- and this is very general, because each region has its own specifics, and then -- but about half was crude related.

The other you could say was product or RINs related, things like being able to blend butanes so the indicator is more accurate versus -- compared to what we are actually doing, and then RINs coming down.

So, in general, its path was crude related and the remainder is a mix of things, including product stuff.

Okay.

And then, in terms of -- on the ethanol side of the equation, what is your guys' outlook for the rest of the year?

Is this something that can be sustained over the course of 2014 or are there other factors that work against this level of profitability?

Faisel, this is Gene.

First of all, 2013 was a world of contrast.

It started the year at more or less breakeven margin.

Some of our plants were actually down and the fourth quarter was a really big month where we had like $0.80 margins.

I think if you look at our -- divide our numbers out, we averaged about a $0.40 margin over the course of the year, which started in January a little higher than that, but that's about where we are today is about $0.40 going forward.

How it pans out?

Who knows.

It is very volatile because it is a result between an ethanol price and corn price, which really don't correlate.

But, however, ethanol inventories remain pretty low.

Production is hanging right around 900,000 barrels a day.

I think demand is expected to average, under the RFS, about 850,000 barrels a day.

So, we would normally be in a build situation, but we are exporting a lot of ethanol.

With lower corn prices, lower ethanol prices as a result, we are seeing good export economics.

We are probably at lower cost to ethanol than Brazil with a lot of the market.

So that is what's keeping the market fairly snug as far as inventories.

The only other thing I would add, I guess, is that, as -- the production numbers are starting to ramp up, you could build from there.

But Valero -- we always maintain that we have a really good competitive advantage, so even in oversupply situation we feel like we have a $0.20 or so gallon margin against our competitors.

So if it starts dropping, you get some of these other plants start to [fall back off].

So, long answer -- but a lot of uncertainty there.

I don't think directionally it is going to be the $0.80 margins we saw in the fourth quarter.

But something between $0.20 and $0.40 is probably something that would be a reasonable expectation.

Okay.

Okay, thanks.

I appreciate the color.

Evan Calio, Morgan Stanley.

Lots of focus on the light side here this morning, but Keystone started up last week.

Actually it's running at about 400,000 barrels a day currently.

I know line fill was primarily light crude, but are you seeing any impact from the Gulf Coast market today, whether it be heavy or light?

And do you see inability or potential ability to [arm] heavy barrels that are in cushing storage today that is estimated up over 5 million to 8 million barrels?

So the barrels being offered off the line are really being priced at something competitive to Maya in the Gulf today -- the barrels that are coming off the --

So they haven't had any -- there hasn't been any reflexive impact from those volumes, right?

No.

There really hasn't yet.

And do you expect that would take time given the K-factor or do you think that might develop sooner?

Well, I think you're still -- the trouble with getting significant volumes of Canadian heavy to the Gulf is still getting the barrels across the border.

So it will make a difference, but I don't know how big of a difference it will make in the Gulf.

Right.

Until Flanagan, right?

This is a different question, on potential crude oil exports, and not on the policy question, but you are one of the only refiners that have exported crudes off the Gulf Coast.

The system has clearly been designed for its entire history to import crude.

Can you discuss some of the coastal infrastructure and logistic issues that were related for you to reverse those flows and just the system limitation that may pose a risk, if there is any, loosening of that policy?

Well, that's difficult to answer.

Some of the challenges we are seeing -- I'll just go through some of those.

The logistics are still very much a challenge in the Gulf.

And so some of the issues we've seen are just the barrels that show up at the dock are not necessarily what we are expecting to load onto the ship.

So, certainly some tankage needs to be built out in the Gulf, ability to be able to segregate barrels better.

And that is why we have taken the path that we want to be able to completely control the logistics and load the barrels on over our own dock at Corpus for that very reason.

And where were you in the quarter on the water exports to Quebec?

We did five cargoes to Quebec in the fourth quarter.

And is that your -- what do you think your max run rate is?

We can run a lot more than that at Quebec.

Really the issue was primarily the logistics of getting the barrels on the water.

And then for us, the other thing is most of those grades were new to the refinery.

So we don't want to send a bunch of crude that they've never run before.

So those have been be processed now, we have the operating history, and we can continue to ramp up as the logistics allow.

Right.

So logistics being the primary bottleneck there?

Yes.

And then, maybe lastly, any comments on Aruba?

I know, given changing crude dynamics in the Gulf, does that breathe any potential life into that asset, or any comments there?

I'll leave at that.

This is Klesse.

There is some interest in the marketplace, but really in the cokers, and it is more tied to upgrading.

I would say there is no interest for processing oil or anything there.

So it would be more like --

Tied to upgrading.

So it would be more of maybe a second derivative effective if there is a negative effect toward heavy pricing in the Gulf?

I suppose if heavy oil gets deep enough discounted, you can offset some of the economic disadvantages of low-cost natural gas and the other items we've talked about.

But we don't anticipate that ourselves.

Great.

Appreciate it, guys, thanks.

Paul Cheng, Barclays Capital.

I have to apologize.

First, because I came in late so you may have already answered that question.

Two questions -- one, you're talking about 50% of the margin improvement is crude [related] and 50% is imported and (inaudible).

When we are looking at that, if we think is there any tie up or one-off operating benefit, whether you have a large (inaudible) of a distressed crude cargo that you have been able to purchase that we have been saying that those are [the factor] not necessarily repeatable into the first quarter or into 2014.

Is there anything that you can quantify, whether there is any meaningful among there?

I think we are looking at each other, Paul, and none of us -- nothing comes to mind like that.

Yes, nothing that is purely one-off benefit.

We are always in the market looking for distressed cargoes and those opportunities change from quarter to quarter.

But it wasn't -- in the fourth quarter, it wasn't an overwhelming and meaningful difference versus 3Q or year-over-year results.

We are always getting [that stuff].

On distressed, but the discounts themselves (inaudible).

Sure.

But I mean that is just the market condition.

You are just being running extremely well in capturing the market, but I'm just talking about anything say somewhat unique and less likely to repeat, tie-off, one-off items on the operating side?

No.

The answer is, no.

Okay.

So, second question is then we are talking about increasing your light oil processing capability, which is what you are doing.

Bill, have you also looked at your system?

Is there any real opportunity to maybe building some condensate [spitter] and use it to figure into the system -- actually this pacing like oil processing?

Because condensate is probably going to be even at a bigger discount.

So the answer to the question would be, yes, we would look at something like that in the right circumstance.

If we are sure we can add value.

Bill, can you elaborate what kind of (inaudible) [consensus]?

I mean is that the current discount is just not big enough or the yield, or is this a really big investment that we're talking about.

Well, it would be bigger than one of our competitors announced for some of the things that they've done with the Marcellus or Utica.

But permitting and there is a lot of other issues to come with this so you have to be comfortable that these discounts will last long enough, because the lead time is significant.

But these are things that you would expect us to look at.

Can you give us roughly what kind of (inaudible) in terms of one in metric quantity that you maybe -- we maybe talking about here if it is the right economic circumstances?

No, I really can't -- I don't have a good answer for you on the actual volume you are asking.

I see.

Okay, very good.

Thank you.

Allen Good, Morningstar.

Quick question on the impact of increasing light crude.

You have in your recent presentation a slide indicating that distillate yields will move to 43% in 2015.

Does that include all the light crude or projects associated with increasing light crude?

Or is there a risk there that gasoline yields could actually be a little bit higher if you attain all those goals?

Allen, that includes what our expected runs are, including those new projects.

But, depending on the margin environment, we are going to always optimize.

So actual results could be different.

But that is what was targeted in the overall runs, based on our including projects.

Okay, great.

Thanks.

And then just one quick one on exports.

Was there any new additional markets that you identified during the quarter with respect to gasoline or either distillate imports or exports that you hadn't previously exported to?

I know previously we talked about picking up some market that Europeans had typically exported to.

Was there any additions there, or is it the same straightforward countries that you've typically exported to over the last year or two?

There were no material changes to any of the markets.

We are finding very, very consistent demand for distillates in both South America and Europe.

And gasoline, the bulk of our volume continues to move to Mexico and then into South America.

Okay, great.

Thanks.

And we have no further questions.

Okay.

Thank you, Sylvia, and appreciate the listeners for listening to our call today.

If you have any other questions, feel free to contact Investor Relations.

Thank you.

Thank you, ladies and gentlemen.

This concludes today's conference.

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