瓦萊羅能源 (VLO) 2013 Q2 法說會逐字稿

Welcome to the Valero Energy Corporation reports 2013 second-quarter conference call.

My name is Larissa, 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 this conference is being recorded.

Now, I would like to turn the call over to Mr. Ashley Smith, Vice President of Investor Relations.

Sir, you may begin.

Thank you, Larissa.

Good morning, and welcome to Valero Energy Corporation's second-quarter 2013 earnings conference call.

With me today are Bill Klesse, our Chairman and CEO; Mike Ciskowski, our CFO; Joe Gorder, President and COO; 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 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 have described in our filings with the SEC.

As noted in the release, we reported second-quarter 2013 earnings of $466 million, or $0.85 per share.

The results include after-tax charges to general and administrative expenses of $20 million, or $0.04 per share, and income tax expense of $9 million, or $0.01 per share, both related to the May 1 spinoff of CST Brands to Valero's stockholders.

In addition, the results include after-tax charges to G&A expenses of $34 million related to various environmental and legal matters.

Second-quarter 2013 operating income was $808 million versus operating income of $1.4 billion in the second quarter of 2012.

The decrease was mainly due to lower refining margins in each of our operating regions.

Our second-quarter 2013 refining throughput margin of $9.26 per barrel was over $1 per barrel lower versus the second-quarter 2012 margin of $10.63 per barrel.

The decrease was partly due to significantly lower discounts for heavy sour crude oil.

For example, the Maya crude oil discount to Brent crude oil decreased by $4.40 per barrel from the second quarter of 2012 to the second quarter of 2013.

Fortunately, the Maya discount has improved by more than $3 -- over $3 per barrel with July month-to-date to Brent of nearly $8.20 per barrel.

Also contributing to the decrease in margins were the lower discounts for medium sour crude oil and light crude oil.

For example, the Mars crude oil discount to Brent crude oil decreased by $0.69 per barrel in the second quarter of 2013, compared to the second quarter of 2012.

For light crude oil on the Gulf Coast, the LLS crude oil was a slight discount to Brent crude oil in the second quarter of 2012 versus a premium in the second quarter of 2013, for an increase of about $1.80 per barrel.

In addition, the refining throughput margin was negatively impacted by the higher costs of Renewable Identification Numbers, or RINs, needed to comply with the US federal Renewable Fuel Standard.

For the second quarter of 2013, the reported costs to comply were $125 million, versus $58 million for the second quarter of 2012.

Given the recent escalation in RINs prices, we now estimate our costs to comply with the Renewable Fuel Standard to be in the range of $600 million to $800 million for the full year 2013.

Another factor that affected refining margins was the higher cost of natural gas.

Natural gas prices increased from $2.24 per MMBtu in the second quarter of 2012 to $4 per MMBtu in the second quarter of 2013.

In addition to affecting our operating expenses, this increase impacts our cost of sales due to our use of hydrogen, which is produced from natural gas.

So far in the third quarter, natural gas prices have favorably decreased about $0.40 per MMBtu versus last quarter.

Our second-quarter 2013 refining throughput volumes averaged 2.6 million barrels per day, for a decrease of 52,000 barrels per day from the second quarter of 2012, caused mainly by turnarounds and planned maintenance at our Quebec City, McKee, Port Arthur, and Meraux refineries.

Refining cash operating expenses in the second quarter of 2013 were $3.82 per barrel, which was higher than second quarter of 2012 due mainly to higher energy costs.

I would like to highlight several other items in our refining operations.

First, the new hydrocracker at Port Arthur has continued to perform well and contribute to earnings.

In the second quarter of 2013, we estimate the new Port Arthur hydrocracker contributed approximately $80 million in EBITDA, with the throughput rates nearly at capacity and achieving high conversion rates.

The contribution is slightly lower than last quarter due to changes in market prices for key drivers, such as higher natural gas prices, lower naphtha values, and lower butane values during summer RVP gasoline blending season.

Using 2012 average prices, we estimate EBITDA would have been approximately $120 million.

We look forward to the contribution from the recently completed St.

Charles hydrocracker, which is essentially a clone of the Port Arthur unit.

Earlier in July, the St.

Charles hydrocracker experienced a smooth and successful startup and is now running at planned rates.

As a reminder, both of these hydrocrackers were designed to take advantage of the current environment of relatively high crude oil prices, strong diesel margins, and inexpensive natural gas.

This is also consistent with our strategy to increase production of high-quality diesel.

Also at the St.

Charles refinery, the Diamond Green Diesel joint venture biofuels plant started up at the end of June.

Throughout July we have been ramping up rates.

This plant is designed to produce approximately 9,300 barrels per day of renewable diesel from low-quality recycled cooking oils and fats using refinery hydroprocessing technology.

The project is a 50/50 joint venture between Valero and Darling International, a leading gatherer of used cooking oils and animal fats.

Valero's retail segment reported $39 million of operating income in the second quarter of 2013 prior to the May 1 spinoff of CST Brands.

Subsequent to May 1, Valero reported its equity interest in the earnings of CST Brands as part of other income.

As a result of entering into long-term fuel-supply agreements, CST Brands became our largest wholesale customer.

Our ethanol segment reported operating income of $95 million in the second quarter of 2013, an increase of $90 million from the second quarter of 2012, mainly due to higher gross margins per gallon and higher production volumes.

Production averaged 3.5 million gallons per day in the second quarter of 2013, for an increase of 156,000 gallons per day, compared to the second quarter of 2012.

The increase in production volumes was mainly due to the economic incentive of higher gross margins per gallon.

In the second quarter of 2013, general and administrative expenses, excluding corporate depreciation, were $233 million.

Included in this were pre-tax charges of $52 million, or $34 million after taxes, for increases to environmental reserves related to nonoperating sites and legal reserves, and pre-tax charges of $30 million, or $20 million after taxes, related to costs incurred to effect the spinoff of CST Brands.

In the second quarter of 2013, net interest expense was $78 million, total depreciation and amortization expense was $405 million, and the effective tax rate was 37%.

Regarding cash flows in the second quarter of 2013, capital expenditures were $796 million, including $162 million for turnarounds and catalyst.

We returned $364 million in cash to our stockholders by paying $109 million in dividends and by purchasing 6.5 million shares of Valero common stock for $255 million.

In addition, Valero paid off $300 million worth of 4.75% notes that matured in June, and we received approximately $550 million of net cash from the CST Brands transaction.

At the end of the second quarter of 2013, we had approximately $3 billion remaining under our stock purchase authorizations.

With respect to our balance sheet at the end of the quarter, cash was $2.4 billion; total debt was $6.6 billion; our debt-to-capitalization ratio, net of cash, was 18.8%; and we had over [$6 billion] of available liquidity, in addition to cash.

We maintain our guidance for full-year 2013 capital expenditures of approximately $2.85 billion, which includes turnarounds and catalyst.

For 2014, we estimate capital spending, including catalyst and turnarounds, to be in the range of $2.5 billion to $3 billion.

Returning cash to stockholders remains a high priority, and we are bouncing this with opportunities to create value by strategically investing in logistics assets, hydrocracking, petrochemicals, and processing cost-advantaged lighter crude oil.

Our premise is to capture the competitive advantages provided by the growing supply of cost-advantaged crude oil and natural gas in the US and Canada.

Along these lines, we are also evaluating potential petrochemical investments that would leverage our existing assets to upgrade the value of abundant and growing supplies of natural gas and natural gas liquids.

Lastly, we are evaluating the formation of a master limited partnership for our logistics assets.

For modeling our third-quarter operations, you should expect refinery throughput volumes to fall within the following ranges -- US Gulf Coast at 1.5 million to 1.55 million barrels per day; US Mid-Continent at 420,000 to [440,000] barrels per day; US West Coast at 270,000 to 280,000 barrels per day; and North Atlantic at 470,000 to 490,000 barrels per day.

We expect refining cash operating expenses in the third quarter to be around $3.85 per barrel.

For our ethanol operations in the third quarter, we expect total production volumes of 3.45 million gallons per day, and operating expenses should average $0.38 per gallon, which includes $0.04 per gallon for non-cash costs, such as depreciation and amortization.

Also in the third 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 third quarter should be around $420 million, and our effective tax rate in the third quarter should be approximately 35%.

Larissa, we have concluded our opening remarks.

We will now open the call to questions.

During this segment, we request that our callers limit each turn in the queue to two questions.

After those two questions, callers may rejoin the queue with additional questions.

Thank you.

We will now begin the question-and-answer session.

(Operator Instructions)

Jeff Dietert, Simmons.

I'm sure there will probably be a long list of these, but I wanted to start with RINs.

One of the struggles I am going through is our blenders passing through the cost of RINs into the retail prices.

Does it vary by region?

What are the major considerations with regard to whether or not these RINs costs are getting passed through to the retail level?

Jeff, this is Joe.

It's a great question.

We are trying to figure the same thing out ourselves.

I would tell you that we look at it on a regular basis, and it's very difficult to quantify whether or not we are seeing the effect of the RINs in the cracks.

We think we might be, but we are not 100% sure.

I do know that if you look at our customers, there are some out there that are able to capture this and there are some that aren't, and everybody's interested in somehow capturing this.

The real question for us going forward -- is how much of this actually gets passed through into the marketplace and how much doesn't because it's a legitimate expense for us as we've mentioned, $600 million to $800 million, it's a big hit.

We'd like to be recapturing it, we're not sure whether we are or not.

There's been press reports that have talked about blenders in the Gulf Coast reducing the price of blended gasoline in order to try to shift more gasoline sales through the blended stream, rather than selling RBOB, perhaps in the colonial pipeline, and then it gets blended up in the Northeast.

Have you seen evidence of this activity on the Gulf Coast?

I guess the risk is, if you discount your blended gasoline, you lose the value on your traditional gasoline blended sales, and I don't know how much you might be able to shift over from RBOB sales to blended sales.

This is Klesse.

Trying to get a handle on this issue is obviously very difficult.

Joe gave you a couple of our perceptions as to the market and our estimate of costs.

I guess I need to remind you that we are no longer in the retail business, so we are not focused on the Street -- that's CST Brands and our other operations.

So, we are a wholesaler.

Valero is obviously trying to pass it through where we can.

We are obviously trying to recapture it where we can.

Our opinion is, we are getting some of it in the crack, but we are not getting all of it.

And then, we can have a debate whether we are getting 50%, 25%, but we think we are getting some in the crack, but not all of it.

Having said all that, Valero's going to maintain a competitive or be competitive to our wholesale-branded customers, where we capture the RIN.

We will stay competitive, and as -- if, in fact, the Street and these other people are taking it on the Street, we are going to be competitive to our customers -- for our customers.

Evan Calio, Morgan Stanley.

As a first question to follow up to keep the RIN conversation moving, I know, Bill, you been front and center in the RIN conversation, and I read portions of your testimony in Washington last week.

My question is, as you run your system, do you make operating decisions based upon a fully loaded RIN economic analysis of each asset?

The question is, would Valero or the industry potentially see economically induced RIN cuts based upon the RIN cost and margins, et cetera, particularly as you move into the seasonally weaker fourth quarter?

It's a prospective question.

Today, with the gasoline cracks where they are at the peak of the gasoline season -- and we're primarily talking about gasoline -- then I would say that you are not seeing it because we have good cracks.

Part of that question was, do we include that in our economics?

And, the answer is yes.

As we looked down the road into the fourth quarter, I don't know what the world will look like, but it is turning into a cost of manufacture for our Company, certainly for the independent refining segment of the industry.

Great.

That's helpful.

Thanks.

For a second question, on CapEx -- I know this is the first time you are providing 2014 CapEx, which looks flat, ex CST to '13.

Can you discuss how you think about overall CapEx levels, the new project returns, versus potential share back?

I guess this would be outside of MLP-able assets.

Our goals continue to be, as I've stated over the years, we are going to maintain a safe operation.

We're going to maintain our investment-grade rating.

We're going to hold a little more cash.

These are the things that I have continually said.

We are investing and reliability.

We think, in this world, you have to be reliable.

So, what the Company can do to support our people in the refineries by investment, we are doing.

But then, this is a long-term capital investment business, and the marketplace has given us these opportunities because they know people are questioning methanol and you see some comments on petrochemicals, so the marketplace is giving us this.

They've given us low natural gas, giving us the potential for very inexpensive butanes, which obviously can be converted to gasoline.

Valero has the wherewithal, the expertise, the talented people to be able to construct and operate these type of plants.

We have sustainable competitive advantages by extensions and bolt-ons to our existing assets, and these are sustainable.

I'm getting to be an old guy and I look at what management does, and I think part of management's job is to take our cash flow and to look at our alternatives.

Do we have projects that will give our shareholders value, growth, over the long term?

If we do, and we've looked at our stock and how we think our stock is priced, but if we do have these, then we should pursue them for our shareholder.

If we don't, we return cash.

I think this management team has done a very good job at this, frankly.

Over the years, we've bought a lot of our stock.

There was a lot of stock issued in the acquisition period of Valero's history, and we've bought a lot of stock back over the years.

We raised our dividend.

We got caught by the great recession, like a lot of people, and had to regroup.

But once we got past '09 and '10, we've gotten back on the same path we were on before, of returning cash to the shareholder.

We do continue to think our stock is inexpensive, and we know that many of our shareholders are looking for yield anywhere they can get it.

We do think the marketplace is giving us some opportunities.

So, we match it all up.

We've bought, in the last 2.5 years, 41 million shares.

We've spent about $1.2 billion on share repurchases.

I will probably be criticized from a few guys because some of those shares were bought at higher prices.

We raised our dividend numerous times.

I've made comments to the investment community that, when we have the hydrocrackers done, management will look at the dividend and make a recommendation to our Board.

So, we've done that.

Methanol has actually gotten some feedback from some of you that are questioning that.

Valero is very uniquely positioned at our St.

Charles refinery.

We have a lot of hydrogen production capability.

We can pull this syngas off these plants.

We can build a methanol plant for 50% of what a grassroots methanol plant can be built for.

And, with all the hydrogen capability of our own plants and third parties, we think we have an opportunity, here, to add significant shareholder value.

I feel strongly that this is our job.

Whether it's this, or alkylation, or adding some crude capacities around light, sweet crudes, which we don't have at some of our plants, we certainly don't want to be buying feedstocks when I am absolutely certain the light, sweet crude is going to be very long in the Gulf Coast.

These are the type of jobs, I think, that are clearly in our shareholders' interest, but it has to be a long-term thought process; because basically, just about anything we are doing anymore with permitting and stuff takes us four to five years.

So, that's how we look at it.

That's very helpful.

Just a quick follow up, and I will leave it there.

Within 2014, for CapEx, are the categories of spending similar to '13, in terms of growth versus maintenance and your MLP-able EBITDA growth rate, if you will?

Yes because some of those projects we're talking about we won't spend that much anyway.

We get the railcars coming in, the logistics is still -- all those projects are still significant part of that spending as next year.

Great.

Thanks, guys.

Robert Kessler, Tudor, Pickering, Holt.

Two questions for me on transportation economics and logistics assets.

One on barge traffic -- your recent presentation highlighted 20,000 to 30,000 barrels a day in barge delivers in the Gulf Coast.

I'm curious if you have any more color on the pace of increase there, and from where and to where you are moving?

Presumably, you are moving west to east.

I'm curious if the volumes have picked up, and what you are seeing in the market for barges on the coast?

Are you getting into a tight market situation there?

And then, I have got a question about railcars, as well.

Yes, Rob, this is Joe.

Our barge volumes have been pretty consistent.

I'd say if you look at everything, we are moving probably 90,000 barrels a day.

We barge sweet crude into Houston.

We barge sweet crude into Meraux.

Memphis receives Bakken -- it will come up from St.

James from barge periodically.

St.

Charles is receiving Cold Lake's.

We are taking heavy sour from Hartford down there, and then we have a little bit of barge volume around Corpus.

No major change there, as far as our volumes go, okay?

That's all I have there, so --

Thanks, and if you wanted to pick up additional barges, say in the spot market, your sense is it would be available for you?

Yes.

I think in the spot market -- it is a snug market, okay?

Barges are being highly utilized and Jones Act vessels, which you could product for crude on, are very tight and the prices have gone up on those.

So, there is not an abundance supply.

What we are seeing and hearing from the barging companies is they've got so many barges under construction that we are going to find ourselves with adequate supply going forward.

Okay, thanks for that.

Then on railcars, obviously, the changing dynamics of the spread as late has marginalized railcar transportation economics in the short term.

Putting that in context with your capital program, you've previously stated plans for significant expenditures on railcar purchases.

I think, in fact, that $850 million a the single largest of the spending buckets you've outlined in your investor presentations.

I know that's for optionality and feedstock and the like, but it begs the question about the possibility of marginalized railcars sitting idle in the portfolio down the road.

How do you think about that potential scenario in your overall capital budgeting process?

There's two things I would say.

You are right, the volume has come off, and a lot of it has to do with what we've seen Brent TI coming in so tight.

That's affected it.

That's going to vary, and we expect that discount will open up again.

The thing that we get with railcars, you get tremendous optionality in where you move volumes, and we are railing -- we are actually railing, now, some [benchman] down to Port Arthur.

That wasn't in our plan, but we've been able to get that, and we are taking it across a commercial terminal down there.

If we look out a little bit longer term, Valero has over 6,000 railcars we currently lease.

We use them to move asphalt, we use them to move LPGs -- what we're adding to our fleet, in a worst-case scenario, we would go ahead and place these leased railcars and use the ones that we purchased.

We still feel good about our decision to go ahead and get these cars.

I guess the fact that we have leased cars provides us a hedge on the downside, but we fully expect that as these markets go back to a more normal pricing, which we expect a WTI discount to go back out to [$7] relative to Gulf Coast, Bakken will open up again, and I think we are going to see more normal discounts, which will put the railcars right back in the market.

Understood.

Thanks, Joe.

Doug Terreson, ISI.

Bill, returning to your comments a few minutes ago about your meetings with Congress last week, and specifically, on the Renewable Fuels Standard -- I wanted to see if you would comment on whether you feel that industry is making progress in this area and having its position understood and the implications for consumers?

Also, any updated opinion that you may have on whether changes might be ahead in this area, and also what you think that might be?

Just a progress update on where we are headed with this?

I think everyone on the call understands the RINs issue, and the assumptions when the 2005 and then the 2007 law were passed are very different today than before.

The issue boils down to a few things -- cellulosic is not available, there's none on the EPA's website.

Everyone says there is going to be a little cellulosic production this year, but it's totally uneconomic, as well.

It was clearly a -- let's pass the law and they will come, and it hasn't happened.

The other part of the regulation that is clearly -- you pass part of this advanced biofuels in the sense of the ethanol piece and this -- so, you have got cellulosic.

The other part of it is, it encourages you, or you have to buy Brazilian sugarcane ethanol or somebody's sugarcane ethanol.

We have a law that encourages you to import over producing domestically.

Then, on top of all of this, gasoline demand has not continue to grow.

It's actually down, and now, flat.

So, the whole thing is screwed up.

That's why I said the other day, it needs to be redone.

I'm supporting the industry position.

I accept that.

It needs to be done -- redone because Valero is a little bit unique in that we are a significant ethanol producer, and we are also a significant renewable diesel producer.

So, we think E10 is part of the fuel mix.

We think E85 is part of the fuel mix.

We have no issues with renewable or biodiesel.

We think that's all fine.

Some of this tech technology is pretty darn good.

But, the EPA's solution of going to E15 is not practical.

There are no facilities.

Even the service-station people are saying they don't know about their tanks and lines.

There's hardly any certified pumps.

Then, you have the car warranties.

I understand some of the 2013 car warranties say it's okay, but there's a whole lot of (inaudible) out there besides this.

The whole thing needs to be redone.

The whole thing is, basically with RINs, is now, as I got quoted everywhere, it is out of control.

RINs were in the preamble of the EPA's regulations that they were not going to be significant.

They were there to give the industry flexibility and to give the EPA a way to monitor.

Now, it's become a huge issue.

It needs to be completely redone.

So, where do I think it's going?

The EPA doesn't seem to be able to do anything, so it's a White House or Congress conversation.

I think the only way the White House will move is they get enough political pressure, frankly, from consumers.

Because, at the end of the day, the consumer is going to pay for this.

Right.

They get enough pressure from consumers, or the option that you see happening, and there will be some bills introduced over in Congress, in the House and in the Senate, where people are, at least, understanding that the basis of the law are not appropriate anymore, yet there will be some compromise.

So, I'm optimistic that we are going to get something out of Congress, and then the President will have to make a decision -- is it backtracking or is it fixing a problem?

The earlier question is the reality, this is very unfair on the Street because you have winners and losers at retail.

Clearly, in the refining segment, this is hurting the independent refiner.

It's not hurting the majors, so you actually are hurting the independent guys.

Is that what you really want to happen?

So, I think will get some congressional action, but I'm not sure you are going to see anything this year.

Okay.

On methanol, the outlook for that business is pretty positive for the next several years, and you talked about some of the rationale for the new plant.

I wanted to see if you'd elaborate on the competitive advantages and the synergies that you referred to with some of your existing operations?

Then also, what you plan to do with the product once you manufacture it?

I recognize it is a ways out, but if you could cover those, that would be great.

Now, you're jumping from the ethanol business to the petrochemicals?

I am.

From ethanol to methanol, okay.

We think on ethanol, we think it's [out of thermex], and we think we have a decent business there.

Our people are doing a fine job.

I remember the old saying -- the renewable fuel old saying -- the Renewable Fuels Association, pigs get fat and hogs get slaughtered.

We've got a good business there, and everybody -- corn prices are up.

Farmland is up.

It's part of the mix.

It is accepted by the consumer.

So, I think some balance needs to get worked into this.

On methanol, because we have our own hydrogen plants at St.

Charles, we are able to strip the syngas before we finish and make hydrogen.

We can take the syngas, so we really don't have to build the front end of a methanol plant.

Right.

Because there is a lot of supply capability and additional capability coming in with the plants, when you look at the whole steam sync, everything that you have around this, this is why I'm saying -- we think that we will be able to build this plant for about 50% of what a grassroots plant -- 60% of a grassroots plant.

The other thing is, we used to be in this business.

We were in a joint venture down in Houston.

Then, it all shut down when natural gas prices were going up.

Obviously, it was part of the MTBE business as well, you could use methanol to do that.

Methanol is a way to move methane in a liquid form, if you think about it.

We think it's a nice little bolt-on and we will develop it a little further, but we felt it important to get it out into the marketplace that Valero was looking at this.

Okay.

Great.

Thanks a lot.

Paul Cheng, Barclays.

Maybe this is for Joe or maybe it is for Bill.

Bill, I was looking at -- I'm trying to understand between the difference in the ethanol business, how you invoice your customer -- in terms of, say, the reformulated gasoline, when you invoice it, you will have, say, what is your charge for the (inaudible) and what you charge for ethanol.

Is that possible?

Is there really that much difference that we can't move into the same system, related to RIN, that you could have two invoice, right?

If your customer want to buy the reformulated gasoline including ethanol, so you will have the invoice that have output and also that a separate item is ethanol.

If they just want to buy the gasoline with (inaudible), without ethanol, so you have that and then you have a charge off their RIN -- given that, every single refiner would sell to someone with out ethanol have to pay for that RIN?

It seems like it's just part of the cost, so possibly by doing it this way, you have the benefit to crystallize and make it very transparent what the consumer, ultimately, is paying for that.

As you say, Congress not going to do anything until they get the public outcry from consumer, and this will help the process.

Secondly, that it also may get -- I think that (inaudible) so that we don't get confused that, at least in the investment income reality how much is passed through or not passed through.

Is there any thought or obstacle why the industry, including you as the leader, why not moving into that?

I will let Joe and Gene add to this, but remember when you blend it, that's when you can separate the RIN.

Theoretically, the RIN has no value until you blend it.

Now, it is all of a sudden a value.

Because you can't get -- if you don't count the carryover from '12, because you can't get to the mandated volume, you are short RINs in the market, so you are short.

Now, I understand you're asking about a whole pricing mechanism, here, but RINs has taken on a life of their own.

They are a market in and of themselves, now.

Then, at the rack you have to be competitive.

We sell ethanol at the market price.

We sell gasoline at the market price.

So, if the whole industry moves to some different pricing relationship, I'm sure you are correct.

But unless the industry moves to that, you can't capture it.

(Multiple speakers)

That seems like it's exactly what happened in [2004], 2006, when we start moving into the (inaudible) a lot of confusion, and you never really separate out [happened], or as a separate item in the invoice.

By 2009, I think the whole industry moved.

I'm curious is there anything stopping because everyone is selling to their customer without the attachment of ethanol, need to recuperate?

It seems like it is also fair because the guys that are buying the reformulated gasoline and they don't pay for the RIN.

Yes.

Paul, Bill answered it, I think, correctly --

Do you guys have an answer to this?

No --

(Multiple speakers) process, and if you try to keep the RIN and another supplier that's in the terminal is going to give the RIN to the customer, you are uncompetitive, so it has all got to balance out.

It's a very [fundable] market out there, whether it be at the spot level or at the wholesale level --

No, I understand, but what I am saying is that you make it crystalline transparent for everyone to see and to know that what is that price that they are paying, so we don't have the confusion.

I think it's something we can kick around, Paul.

Clearly, we are not there yet.

We have to think through what the competitive implications are.

On the second question, that -- being curious that the $2.5 billion, $3 billion for next year for the CapEx, is that the new norm for the Company going forward -- at least, for the next several years?

I think last year that we have been talking about in the $2 billion, $2.5 billion, so has that now changed into this $2.5 billion and $3 billion?

If that's the case, how that impacting, in terms of your outlook on raising your regular dividend payout?

I've never given longer-term guidance than about two years out.

I have said that I thought '14 would be in the $2.5-billion range previously.

All we've done here is say, hey, it's $2.5 billion to $3 billion.

To me, we are still in the range, we are still in our budgeting for next year.

So, whether this is the new normal or not, I don't know.

I think it depends on whether or not we believe we will add value through some of these discretionary projects.

I have said several times that our stay-in business -- what I will call the whole maintenance end of the business -- turnaround, regulatory, all of that, seems to run somewhere in the $1.6-billion to $2-billion range.

Then, on top of that, we have this discretionary area.

But, your main question is, it's about returning cash to the shareholder.

I think that if we have projects that add greater value, we are going to pursue them.

If we don't, we are going to return the cash to the shareholder.

I don't see that as one bit change from what this management team has been doing.

Thank you.

Roger Read, Wells Fargo.

Maybe to change the subject a little bit -- light, heavies, obviously you had an impact on Q2.

Can you help us understand, as we are looking at Q3, where if you measure by LLS, light, heavy spread is pretty attractive.

If you measure it by Brent or WTI, not so much.

What are you seeing move out there?

And, what do you think really will drive the market here over the next -- let's say through year end in terms of the most important marker on the light side of that argument?

You mean, which would be more important, like a Brent or an LLS or TI?

Yes, and maybe how LLS fits in, in terms of driving the Gulf Coast market there?

Right, so Roger, if we think about what's happened in this quarter, we obviously we had Brent WTI come in, in a material way.

We saw LLS move out and get priced at a more significant premium to Brent.

A lot of that has to do with the simple fact that we ended up being shorter in the Gulf Coast on light, sweet crude oils then, perhaps, the market anticipated.

We've said all along that the pricing of sweet crudes in the Gulf is going to be dependent on the quantity of domestic crude that's there.

We saw that we did have a bit of short supply, and there was a host of reasons for it.

We had Syncrude outages in Canada that reduced the volume.

We've got BP Whiting still running light, sweet crude, which has supported Bakken prices at Clearbrook.

Bakken is pricing up in the field in LLS plus transportation, or adjusted for transportation, which is making it expensive.

It's expensive because it was in tight supply.

I think as we look forward into the third and fourth quarters of this year, we are going to have more takeaway capacity out of Cushing and out of the Permian, that's going to bring those barrels to the Gulf, okay?

I think that you will see more volume coming on stream and moving into Cushing, so the inventory draws that we saw will probably stabilize, here, a little bit.

What's that do to the overall crude markets?

I think you are going to the light sweets -- our view is that LLS will trade down and will trade in a discount to Brent.

Longer term, I think we'll see the WTI spread back out to maybe a $6-to-$8 discount.

And, I think what we will see is the medium sours will adjust to price themselves into the refinery.

Then, we're getting some relief on the heavy sour discounts now.

The Mexicans have adjusted the K factor as aggressively as they can over the last several months, and they adjusted it $1.90 and that will take effect on August 1, which will increase the discounts on the Maya, which affects, of course, all the other heavy sours.

I think, as we look at the -- we saw all the discounts on crude come in, in the second quarter.

I think we are going to see them start to move back out in the third and the fourth quarters.

Okay.

That's helpful.

The unrelated second question, probably more for you, Bill, getting back to the CapEx versus dividend versus share-repo evaluation.

What are the rough returns you are looking for?

What are the various ways you analyze what makes the most sense for Valero to do at a given moment, in terms of investing in the methanol plant versus, say, a more aggressive share-repo program -- or accelerated, maybe I should say, rather than aggressive?

Many of these plants are bolt-ons or extensions of our business.

Because you are capitalizing on the whole refinery that's already there, these returns are all north of 25% on all of them -- these are IRRs.

We get into a huge conversation, here, what is our cost of equity?

I've even had it with a lot of you that are on the call.

We look at it and we try to balance, and what you've really seen with this management team -- and I keep going back to this, is we bought our shares every single year that we've been on this -- as part of this management, except 2009 and 2010.

The other component, here, is next year we only have $200 million of debt that matures, and the year after that, we only have $500 million of debt that matures, so we also see that we have ample cash flow coming at us, as well.

I think some of these projects are very good returns.

We look at that.

We look at where our equity is priced, it's obviously down from where it was.

Don't forget, we spun off to the shareholders of CST, as well.

So, I think we are very shareholder focused, here.

The only caveat I really stick on it is, it's long term.

You've got to think what we are looking at long-term shareholder value, not tomorrow afternoon.

Okay --

And, we want a dividend that sustains, that we can sustain.

Okay.

When you are looking at the share repos, not necessarily -- it's more free-cash-flow driven than it is a return analysis?

In other words, you're not going to worry so much about the share price at a given moment as you are -- that's part of what you're doing, or is there more to it than that?

That would be correct.

Back a couple years ago, we made a decision, we weren't going to buy any refineries because we thought they were too high priced, and we turned around and had a very significant share repurchase.

So yes, if we have free cash flow, we have enough cash where we say our cash position is solid, we are going to maintain this investment-grade rating, then yes, we are going to return the cash to the shareholder.

Okay.

Thank you.

Doug Leggate, Bank of America.

Bill, maybe I could just change tack again a little bit to MLP.

I know you've suggested, now, that you are probably moving forward here, but you spoke to this $50 million to $100 million of EBITDA.

As we look through your presentation, it looks like there's a fair amount of MLP-related expenditures.

Can you help us a little bit with how you see the scale of that EBITDA ultimately, and what timeline is to get there?

We have said, and I think this was 2012 assets, that we had $50 million to $100 million of EBITDA.

That's probably the range of where we are looking to go out, initially.

As Mike Ciskowski is running this project for us, here, and he tells me that, getting everything done, this is probably a first quarter of '14 project, subject to, of course, our Board.

So, we are doing all of that.

Obviously, we are adding a lot of projects of pipelines, railcars, terminal enhancements, rail facilities to unload, and all of these assets are MLP-able.

What we have said is, our focus would be -- in the sense of a terminal and distribution MLP, because some people have asked us about other assets, we said -- well, our focus is more there.

But obviously, we have many more potential drop downs going forward.

Okay.

It doesn't sound like you want to be drawn a number, Bill, but to keep it in context, it looks like you are spending about $1.7 billion over the next -- it says five years in the presentation, but is it really five years, or is it a little quicker than that?

It would be quicker than that.

Okay.

Great stuff.

We can figure it out from there.

Last one, really, is to go back to the RIN question.

It's really on your guidance you gave for the full year.

If I'm not mistaken, you talked $500 million to $750 million before, but RIN prices were, like, $0.75.

Now, they are up 60% from there, and you are barely above the top end of that range in your guidance.

Can you help us understand why we are not getting a pro-ratable impact?

It sounds like there's not a lot of change in your cost, even though the RIN cost has doubled.

I will leave it there.

Thanks.

Part of it has to do with where we bought these RINs and our position in the whole process.

Plus, there's assumptions in our numbers as to export volumes, how much we are capturing, and all of that, so that's based in there as well.

This is the range that we are operating in now, $600 million to $800 million, but clearly, if it's $1.50 a RIN, we are at the high end of the range.

But, we are only in July.

Right.

What I'm trying to figure out is that your previous range at the high end was $750 million and the RIN price was $0.75.

Now, the RIN prices $1.36 and your high end is only up $50 million.

Why only such a modest increase?

I was at the high end.

I had a range before, and I was probably at the low end.

I think you have to accept that we are not trying -- we are not misleading you, this is how we are viewing it.

You guys are asking us for guidance, and I'm saying to you, okay $1.36 -- I was using $1.48 or something, but at these higher numbers, we will be at the high side of our range.

It has to do with our position as to when we bought a lot of this, so there is a serious timing component involved, here.

This is for 2013.

Does it change [dramatically] in 2014 -- does it change significantly?

Absolutely, it would change.

Remember when we first started this, they were $0.75, and in January or February they was still $0.05, and then it started moving up.

They went to $1, then pulled back to $0.60, $0.70, then they go back up.

Next year, it will be a much larger number at $1.50 a RIN.

Then, we will get into the conversation -- well, how much are RINs going to be in '14 because you're totally unfeasible (multiple speakers).

Okay, I will leave it there, Bill.

No, seriously, because you had the carryover from '12, so that's the big debate this year.

You're going to have to carry from '13 into '14, you can carry in 20%, but there are not going to be enough RINs around.

It is totally not feasible next year.

All right, Bill, thanks a lot.

Appreciate it.

Paul Sankey, Deutsche Bank.

Thanks a lot for the CapEx guidance, early CapEx guidance, we appreciate that.

Bill, you mentioned, really part of my question, which was the $1.6 billion to $2 billion that you have of ongoing stay-in-business CapEx --

Our DD&A is running at about [$1.6 billion to $1.7 billion] -- it's $1.7 billion?

[At 7], and I think it's really unrealistic to assume we don't have to spend the DD&A to maintain our assets.

Effectively, one way of looking at this is you effectively doubled your growth CapEx at the margin.

But, we are coming off two huge projects in the past year or so that would have come online.

I am wondering what the components are of the new, relatively high number for growth CapEx?

Could you list the biggest several projects that you are going to be investing in?

Thanks.

Paul, the best guidance we can provide right now about those details would be on slide 19 of our latest IR presentation, which we presented earlier this month.

That's focused on 2013, but the 2014 details are largely in line with that.

As we get later in 2013 and we complete our strategic planning process, we will be able to hone that give you the specific chunks, but it's very similar.

We also have -- it is basically a continuation of spending on existing processes, or existing projects.

Keep in mind, as Bill said earlier, they're long-term projects.

I know it takes you guys a second to update your model, but it actually takes years to get permits and construction and do all these things and to spend the money.

In order to achieve the returns Bill talked about earlier, it does take some time.

That's what -- that's why these are generally going to be continuation of existing projects.

On [slide 32] in that same handout, we give a little EBITDAs with some of the projects as well, okay?

So, you can piece together how we are looking at it.

We will update that later this year as we go through our planning process and complete that.

I don't think you were referring to Deutsche Bank models, by the way, there actually (laughter) What are you looking for -- from a planning -- thinking about how you decide on these investments?

I'm looking at your cash flows at a low in 2009 of a little bit under $2 billion -- [last year] $5 billion.

Is that how we think about it that you're -- and we've been asking this question in various ways on this call, obviously, but I'm wondering -- another way of looking at this is that you've effectively doubled your growth CapEx of the margin against expectations.

You could've effectively doubled your free cash flow, especially in a high-risk RINs environment.

I'm trying to drill down into why we are spending so much money (inaudible).

If you look at the logistics capital, that has kind of been in tech, so the place -- and I'll just try to add clarity here, the place where I'm sure some of you guys are wrestling with is in this whole petrochemical, methanol area.

Our view is that the marketplace is giving companies like us a huge opportunity to add a lot of value for our shareholder.

We expect low-cost natural gas.

That's why the hydrocrackers look so darn good --

Is that sub $4 that you are assuming there, Bill -- sub $4?

No, but sub $5.

We think the number needs to be a little higher long term so that the drilling industry can make a reasonable return.

There seems to be a debate, sub $4, how much return they are getting.

If you get into the $5 range, we believe they can make a return.

Now, you guys would know more about that, I suppose, than us.

Then, you look at the butanes coming.

We have alkylation units within our refineries right now.

These things look like something where Valero and its shareholders can really benefit.

Yes, I get you --

We are studying it and we are getting it out there, so at least you guys know these are the things that we are looking at.

I get you.

Can you give us a sense of how much more light sweet crude you think you'll be able to run, let's say, by the end of '14?

Yes, we actually can because we -- our projects won't quite be done --

By '14, not a whole lot more.

It's not until the toppers are done in early '15 that we would be able to increase those.

And those, I think -- You are really talking -- it's not until a '15 conversation.

If you take the Houston plant as 70, and Corpus is 90, we are looking at Port Arthur, where we have an idle crude tower -- excess crude tower, excess space in the tower, probably 50,000 to 75,000, and we are subbing -- Quebec is already a sweet crude refinery, but we will be subbing in North American crude more and more as we go through time.

Then at Meraux, we will be running more lighter crude there as well.

Those are projects that are significant, then we have these little change this, exchange, and add this deal here and re-pipe this projects going on, too.

(Multiple speakers) he will give you a number, here --

It's 160,000 barrels a day.

For those two?

For those two.

Not counting, then, the other ones I said, so we will pick up another 50 to 100 between Port Arthur and Meraux.

In closing for me, in '15, how much more light sweet will be, if you like, a substitution, and how much more will be incremental throughput in what total?

I will leave it at that, thanks.

It is almost all incremental throughput.

So, it's incremental throughput, but what it is backing out is our feedstock purchases.

Remember, we buy Algerian resids, a lot of those that we bring directly into our units.

We bring some other of these feedstocks in that basically go to the Cats, and instead, we'll be making a lot of our own gas.

It's all incremental replacement -- I'm confused.

Does it mean your overall capacity is higher at Valero?

The overall crude capacity will be higher, for sure -- not our throughput capacity.

Got you.

Okay, that's great.

So --

Remember, we run, today -- I guess, officially, we would say we are 2.3 to 2.4 million barrels a day of crude, but we are 2.8 to 2.9 of throughput because we are buying these other items.

Yes, I'm with you.

I don't want to take up the whole call, but that's very helpful.

I will come back, potentially, with more.

Thanks a lot.

Arjun Murti, Goldman Sachs.

Sorry for another follow up on RINs, but if we look out to 2014, and I agree with your comments on how unworkable the RFS looks, can you talk about to what degree you guys crank up your exports to help offset some of your RIN obligation next year, relative to what you might be doing this year?

It depends on the cost of the RIN.

You have to have a basic crack, so assuming we have a basic crack that says -- hey, it's profitable to make those barrels, then you have -- if RINs are $1.50, you technically have $0.15 a gallon, here, that you are playing around with, so you can be very competitive going export versus the US market.

As far as ramping up --

Ramp up the exports --?

If the industry is basically out of RINs next year, and you guys are on the coast so you do have export capability -- again, Congress is going to have to take action at some point, here.

In the absence of that, it seems like you could have a very high RIN price, well above where you are today.

No one wants to shut in their units, which I guess is the other way to not have a RIN obligation.

It would seem like exports is one of the outlets, and you guys would seem have the better position to do that.

Just tying to see if we can frame how much you could reduce your volumetric RIN obligation next year, if it's -- whenever the right phrasing is very high RIN price, much higher than where we are right now?

Arjun, let's assume that the market is out there for the barrels to be exported, okay, and that the [arb] supports the exporting.

Just as an example, we exported 70,000 barrels a day of gasoline in the second quarter and we exported 170,000 barrels a day of diesel.

Now, those numbers are what they are because we optimized the supply into the marketplace.

We had a very strong market with that too because you had Joliet turnaround and Whiting turnaround and were down, so we were able to move barrels to that higher [net-back] market.

Barring that, and saying that the market was demanding the barrels abroad, we could go to 225,000 barrels a day of gasoline and 280,000 barrels a day of diesel.

And then, the projects that we've got underway to improve docks and tankage and segregations at the refineries would allow us to take it up beyond that going forward, particularly with the St.

Charles hydrocracker coming on and the quality of the diesel fuels that we're getting out of St.

Charles and Port Arthur.

So, there is capacity --

I think Joe is giving you a capacity conversation.

I don't think it's realistic because the industry is in the same boat.

Yes, we are on the Gulf Coast and we would have that capability, but so would other people.

You get down to the basic -- you have to have the basic cracks.

Yes, to the way you phrased your question, Joe answered -- yes, we would have capability.

Yes, we are on the Gulf Coast, so we could do that.

But, I would not want to lead you down a path that this would be a significant solution for us.

I don't think so.

I appreciate -- go ahead (multiple speakers).

This is Gene.

I would just add, both of these solutions that are exporting more or reduce and refine runs reduced supply.

So, demand really doesn't go down, which we don't think it does next year.

You've got to meet demand, which tells me it's (inaudible) pricing on the cracks on the US basis and maybe a lower basis for exported barrels, but --

That, to me, would be the mechanism, right, by which you get the true pass-through, especially if the US economy is recovering, the demand is there.

You either supply less, which I don't think you do, but potentially export more, it's clearly a mechanism to get the pass-through.

I appreciate your candor and the answer.

Thank you so much.

Edward Westlake, Credit Suisse.

Obviously, a lot going on in refining, lots of questions.

I guess the 2Q Gulf Coast was probably the weakest absolute number that we've seen for long time, I guess, despite the first hydrocracker.

That's also despite there's some cheap Eagle Ford coming into Corpus.

Clearly, light heavy is weak, but is there anything else material going on that we should focus on?

And I guess, if not, then as light heavy expands again over time you should go back to a more normal capture?

That's it.

When you are referring to light heavy, Ed, are you talking about really the sour crudes versus the sweeter crudes, in general?

Yes.

Because, they were -- you are right, the discounts on all those crudes, relative to the sweet crudes, were off.

We shifted the slate and we ran about the same amount of heavy sour crude -- Q2 '12 versus Q2 '13.

We ran quite a lot less medium sour, though, because it tended to be out of the market.

Now, on the heavy sour side, we don't price all of our heavy sour crudes up, so we had some advantages there.

But, I don't know of anything else -- Bill -- I don't know of anything else going on in the Gulf other than that.

We make a lot of other products and they are all moving around.

But, if you take our Port Arthur refinery, which is a very -- it runs Maya crude oils, it did very poorly in the second quarter.

Okay --

Even with its new hydrocracker --

Yes, and that was due to the pricing of Maya (multiple speakers).

You can see it had a huge impact.

Then, a second question, more broader around the Texas market, I guess.

You've got the Eagle Ford growing, some decent Permian well results recently.

You've got two major pipelines, probably more, coming down into Texas.

Do you think there is a limit on the effective capacity of the industry to move those barrels over to Louisiana?

Or earlier, you spoke about there being enough barges, but it feels like it's a lot of volume and it could cause some stress.

Any color on that would be helpful.

I think as the volume comes into Houston, eventually here, it's got to move east.

You are going to have Shell's pipeline running, which has a very high tariff, which is a lot higher than barge.

I think you're going to see the barge is you are going to see assets come into play, here, because it's got to move.

It's got to move along the coast and one of our competitors has signed a deal to ship it up to the East Coast by water as well, so you are going to see it moving.

To us, Houston is going to be the focal point of all of this.

In terms of -- obviously, there is only a limit to how much light you can run, I guess, moves across.

As you talk to your major suppliers, I'm thinking, the Mexicans, obviously, there's mediums coming over from the Middle East.

How do you think they're going to respond to the fact that -- not just yourselves, but the whole industry on the Gulf is going to be probably looking for less of their product?

It remains to be seen and there will be political considerations, as well.

Valero -- we buy from the Persian Gulf suppliers and they have a stake in this market.

Their crude is more medium than this light that we are talking about.

This isn't today's issue and it's probably not tomorrow's.

This is probably a 2015, 2016 conversation.

Over time, the US is going to have a lot more oil on the Gulf Coast, and I think the refining industry is going to figure out how to run it.

Thank you.

That's very clear.

Faisel Khan, Citigroup.

Another ethanol question, I guess, how difficult would it be for you guys to increase your blending capability?

I know you saw a certain amount of merchant volumes and you blend some of your own volumes, but how difficult would it be to increase your blending capability, given your natural supply of ethanol and your production of gasoline?

Faisel, we are looking at increasing it everywhere we can, as you would expect.

For example, with the Diamond Green project, we are going to have a lot more renewable diesel that we can blend into the pool.

We are looking at every asset we have, and if it requires some modest investment to increase the blending capabilities there, we are going to do it.

But, generally said, we don't have access to the terminal assets to control blending of all of the product that we produce.

We are merchant refiner and we sell a lot at the plants of the refinery, and we don't have the opportunity to blend that up.

Okay.

Understood.

We are blending where we can.

Diesel side is what Joe is talking about more because you have a customer base, here.

Sure.

The customer base goes into a terminal -- everybody sees, I guess, somebody said $1.36 RIN.

It's a matter of customers, as well.

Where we can, we have added facilities, and where we are, we are blending.

But clearly, the marketplace is in disarray, because at the wholesale racks, theoretically anyway, you've got all these different prices, now.

Right.

Fair enough --

We are trying to minimize -- if the question is, are you trying to do things to minimize your exposure?

The answer is, absolutely.

Okay.

Got it.

Then, last question from me -- I know the call has been going on for a while.

On the potential investments in natural gas liquids, and also alkylate investments, can you talk a little bit -- in a little more granularity and where -- what type of assets you are looking at building and where you are looking at doing that?

Is it fractionation, and where would it be?

Also, on the alkylate side, where are you looking to increase production of alkylate?

It's not fractionation, per se, with us.

We don't think -- I answered this on the last call, last April, I don't think we add value, per se, just to build a fractionator.

Where Valero -- we don't really have a competitive advantage over some of these guys -- like Enterprise, for instance, they can come in and build a fractionator.

Sure.

What we do do is, we have alkylation units in all our refineries.

Alkylate is a great blend spot.

When you look at how we make gasoline, gasoline is a blend, remember that -- it is made up of all these different components.

So, as we look at our system, we believe we are going to have very inexpensive butanes.

I've spent the last -- we have spent the last 10 years of our -- maybe it's 15 years, of our careers, removing butanes from gasoline.

One way you can stick butane back into gasoline is by alkylating it or making a longer carbon chain.

So, as we see normals coming and converting them to butylenes, and you see cheap or inexpensive isobutane, we think this is a good option in a refinery to be able to increase the amount of that blend stock.

That make sense.

Where do you do that and how -- what are the magnitude of investments you make to increase that capability?

These alky units would be $200 million, $300 million.

All of the sulphuric acid -- Valero would not build a new HF alky.

As we look at our system, they would be on the Gulf Coast.

Okay.

Understood --

With one possible exception, for a different reason.

Got it.

Thanks, guys.

I appreciate the time.

Chi Chow, Macquarie Capital.

Sorry to keep pounding this RIN issue, but Mike, can you tell us how the accounting works on your RIN purchases?

And, how exactly does it flow through your P&L?

Sure.

Our accounting is based on whatever our RINs deficit is.

We amortize in -- we purchase forward and we have been purchasing forward a number of contracts and we amortize that cost in as a deficit that is basically created.

Okay.

Great.

Is that split by region, as far as where that amortization goes -- in the cost of goods --?

From a regional standpoint, we allocate all of that based on a throughput basis to the regions.

Okay, so it's split in each region by throughput?

Correct.

Okay.

Got it.

Thanks on that.

Bill, I just want to clarify -- I think you mentioned on one of the other questions the $600 million to $800 million on 2013 costs -- is that a net number, net of some pass-through assumption?

No, that's not a net number.

That's just what the deficit would cost us.

Okay, good.

Thanks for that.

I guess, final question on rail movements.

How do you think this Quebec railcar accident is going to impact crude by rail going forward?

Is there going to be more regulation, costs -- any thoughts on that?

This is Klesse.

I don't think it will impact it in the sense of the extremes.

I do think that you are not going to see one-person trains anymore.

You are not going to see trains left sitting on the siding full of products.

I think it's just one of those areas that people just hadn't focused on.

This is a very tragic accident, and we all understand that.

I think you are going to see more of the procedures.

You are going to see a very strong review of procedures.

I think you will see cooperation increased in North America, here, between Canada and the US and regulation on tank-car design.

You will see more on that these bonnets, beefing them up.

I think, also, you will also have a conversation that will pull the Mexicans into this as well.

Railing crude oil, railing ethanol, railing distillers grain, railing corn, railing asphalt, propanes, they are all here -- they are part of the distribution system.

There will be procedural things that will change.

This train was left alone.

I don't think you are going to be leaving a train on the siding with nobody there anymore.

Yes.

Sure.

Not going forward --

Those kind of things will take a little time, but to me, that's where we will see more procedures and -- maybe it's in the operating area.

You mentioned changes in railcar -- tank-car design.

Does that impact your deliveries at all, going forward, here, on your railcars?

No, it would not because there is no change now, right?

Right --

Then, if it is, we operate a very -- we strive, all the time, for safety and reliability.

If something happens, we will take a look at it.

Okay.

Thanks, Bill, appreciate it.

Allen Good, Morningstar.

Just a question on the chemical investment follow up.

You mentioned some of the characteristics around St.

Charles that made it attractive.

When you look around your system, what are some of the other opportunities you think for additional chemical investments.

If you do identify those, would you be willing to move forward with several of these similar-size investments at the same time?

It's a very fair question.

We are looking at this because the marketplace is changing so quickly.

Because, I'm of the belief that the United States can have a huge manufacturing and petrochemical resurgence, here, if our government would figure out how to get behind it.

We look at the Gulf Coast plants.

There are -- in the sense of our crown-jewel assets, they give you access to the water because some products would be exported.

Remember, Valero is already in the (inaudible) business.

We are already in the propylene business.

We are in a lot of these businesses anyway, so we are talking about bolt-on.

They would be along the Gulf Coast.

Would we take on several projects at the same time?

Sure, we have the capability, as the other companies do, to manage projects in the capital spend level that we've guided you.

Okay.

Thanks.

I guess a second question, earlier you mentioned you expect some of these crude differentials have narrowed in the first half of the year to widen back out later this year.

Looking at your most recent presentation, you have a small list, here, of rail and barge projects that you anticipate to come online later this year, moving cost-advantaged crude to the Gulf Coast, the West Coast, and the North Atlantic region.

If we are at the same situation, here, as far as differentials are concerned, and I guess, mainly, being the WTI Brent, as we get into the third and fourth quarter, where there is basically no differential, would you still expect some of those rail projects to come online and start delivering some of that crude via rail?

Or, would you delay that to next year until we get some more widening in the spread?

It would absolutely depend on some of our deals.

But, hey, we are in business to make money.

If it's not economic to do something, we may have some fees we have to pay a few guys -- where we have to take it, we will have to do it and make the best of it.

But, we try very hard to maintain optionality on these deals.

Sure, if you don't have any spreads, you are going to optimize them.

Is there a general WTI Brent spread, or any other spread we could use as a rule of thumb to see whether some of these rail projects, in general, are economical for you?

In the back of our handout we had that big map where we made this price, call it, 12 to 18 months.

We said New York Harbor is where we see the equilibrium play between Brent and delivered sweet crudes into the harbor, so you take Brent plus $2 for freight.

We've been saying that's where a lot of this balance is, it is on the East Coast, and then you back up from there.

So we think, over time, you're going to have these differentials because the crude has got to move to the markets, and it's got to displace the foreign barrels.

Sure, you could have a spot month or two or what's going on right now, but we don't believe they are going to last.

We are in business for the long term.

(Multiple speakers) in our appendix that's in it, we put all those numbers in there.

I think we say 12 to 24 months is our price outlook, but the basis is the East Coast being equilibrium.

So, Gulf Coast, we think that LLS is several dollars below Brent.

Great.

Thanks.

Paul Cheng, Barclays.

Just real quick question -- I know you may not want to give us an absolute number, but what is the percent of your rail arrangement with the rail operator, as take or pay for the long term?

Or, what percent is (inaudible) time of deal?

I don't know if it's that I don't want to give it to you, I'm not sure we know.

We don't have (multiple speakers).

I think, here, we will give Ashley a couple -- we will put something together.

The railroad -- we own the cars, so Joe's point is -- hey, you don't have that.

The reason I was hesitant on the previous question is, we make some commitments to load cars at these third-party loading, at our own refinery they're our facilities, so there are no obligations.

We do have some fee commitments to load and a couple things like that, purchases of oil.

We will put something together, but it is relatively small.

We have a -- once we get all our railcars, we will have a $750 million investment in railcars and $200 million in sidings, so we want a return, too.

Sure.

Secondly, on the Keystone XL Salt Lake, and also the Seaway one and two, can you give us a rough idea what is your take-or-pay commitment on those?

Paul, we don't do that.

Okay.

Final one, Bill, when we are looking at your dividend policy, when the Board determines whether you are going to increase or not, is there a policy from management that this is an annual exercise, or it is semiannual, or there's really no policy at all?

I'd like -- in the way you phrase your question -- no policy at all (multiple speakers).

I think we are a little better than that.

We raised our dividend in January.

I said that we would look at it and management would have a recommendation.

We haven't had our Board meeting, yet, this month, after we finished the hydrocrackers.

We look at our balance, we look at our forecast, we look at our payout rate.

I have said that Valero wants to be among the highest in dividends and returning cash to our shareholders of our peer group.

So, we looked at those guys, as well.

I feel like there's more of a process, but we don't say -- the July Board meeting is a dividend meeting.

It is a dividend meeting with the Board, but we don't say management is going to raise the dividend or something at the January meeting or the April meeting or the July.

We go into it with us having looked at our forecast, where we think our cash is, do we think we can sustain it, and then we make a recommendation to the Board.

Thank you.

Thank you.

We have no further questions.

Okay.

Thank you, Larissa.

I want to thank everyone for listening to our call today.

I believe we set a record for length.

Thank you for that interest.

Please visit our website or contact Investor Relations for additional information.

Thank you.

Ladies and gentlemen, this concludes today's conference.

Thank you for participating.

You may now disconnect.