瓦萊羅能源 (VLO) 2014 Q2 法說會逐字稿

Welcome to the Valero Energy Corporation reports 2014 second-quarter earnings results conference call.

My name is Sylvia, and I will be your operator for today's call.

(Operator Instructions)

Please note that this conference is being recorded.

I will now turn the call over to John Locke.

John Locke, you may begin.

Thank you, Sylvia.

Good morning, and welcome to Valero Energy Corporation's second-quarter 2014 earnings conference call.

With me today are Joe Gorder, our CEO and President; Mike Ciskowski, our Executive Vice President and CFO; Lane Riggs, our Executive Vice President of Refining Operations; Jay Brown, our Executive Vice President and General Counsel, 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 our Investor Relations team after the call.

Now, 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 can cause actual results to differ from our expectations, including those we've described in our filings with the SEC.

As noted in the release, we reported second-quarter 2014 earnings from continuing operations of $651 million, or $1.22 per share.

For all periods shown in the tables that accompany the earnings release, our results of operations reflect our Aruba refinery as discontinued operations.

And we recognize $63 million of charges, in the second quarter of 2014, associated with recording asset retirement and other obligations related to our Aruba refinery.

Second-quarter 2014 operating income improved over second-quarter 2013, with gains in the refining and ethanol segments partly offset by a decrease in the retail segment, due to the spinoff of CST Brands in May of 2013.

The refining segment throughput margin in the second quarter of 2014 was $9.84 a barrel, which is an increase of $0.58 per barrel versus the second quarter of 2013.

Decreases in gasoline and distillate margins, relative to Brent in most regions, and narrower WTI discounts in the Mid-Continent, relative to Brent, were more than offset by wider discounts on light sweet, medium sour, and heavy crude oil in the Gulf Coast.

Also contributing to the higher throughput margin was our Quebec City Refinery's increased consumption of North American light crude in the second quarter.

North American grades composed 83% of the refinery's feedstock diet, up from 45% in the first quarter of 2014 and up from 8% in the second quarter of 2013.

Additionally, at our St.

Charles Refinery, we began processing Canadian bitumen via our new crude-by-rail unloading facility.

The US crude supply landscape continued to transition in the second quarter, with oil stocks shifting from the Mid-Continent to the Gulf Coast.

The inventory reduction in Cushing and corresponding oil supply growth in the Gulf Coast led to a $2.49 per barrel decline in the WTI discount to Brent and a $5.19 per barrel increase in the LLS discount to Brent, compared to the second quarter of 2013.

Gulf Coast sour crude oil differentials to Brent also widened over the same time period, due to the increasing supply of crude oil.

The discounts from Mars and Maya, relative to Brent, increased by $4.69 per barrel and $8.49 per barrel, respectively.

Refining throughput volumes averaged 2.7 million barrels per day in the second quarter of 2014, which is an increase of 115,000 barrels per day versus the second quarter of 2013.

Less turnaround activity and higher utilization rates spurred by the increased availability of discounted North American light crude in the Gulf Coast led to the increase in refining throughput volumes.

Refining cash operating expenses in the second quarter of 2014 were $3.90 per barrel, which is $0.07 per barrel greater than the second quarter of 2013, due mainly to higher energy cost.

The ethanol segment generated $187 million of operating income in the second quarter of 2014, versus $95 million of operating income in the second quarter of 2013.

The increase in operating income was mainly due to a $0.39 per gallon increase in gross margin, which was driven by lower corn prices on an abundant corn crop and low industry ethanol inventories at the start of the quarter.

Ethanol production volumes averaged 3.3 million gallons per day in the second quarter of 2014, which were lower than the second quarter of 2013, due to production slowdowns caused by lingering rail congestion in the Mid-Continent.

Now, looking at the third quarter for ethanol, we expect volumes to increase with the startup of our recently acquired plant in Mount Vernon, Indiana.

Given the favorable ethanol margin environment, we look forward to this plant's contributions.

General and administrative expenses, excluding corporate depreciation, were $170 million in the second quarter of 2014.

Net interest expense was $98 million, and total depreciation and amortization expense was $414 million.

The effective tax rate was 34.3%.

With respect to our balance sheet at quarter-end, total debt was $6.4 billion.

And cash and temporary cash investments were $3.5 billion, of which $382 million was held by Valero Energy Partners.

Valero's debt to capitalization ratio, net of cash, was 14.1%, excluding cash held by Valero Energy Partners.

Valero had approximately $5.8 billion, and Valero Energy Partners had $300 million of available liquidity in addition to cash.

Cash flows in the second quarter included $806 million of capital expenditures, of which $240 million was for turnarounds and catalysts.

We also repaid $200 million of debt that matured in April.

In the second quarter, we returned $361 million in cash to our shareholders, which included $133 million in dividend payments and $228 million in purchases of approximately 4 million shares of Valero common stock.

Subsequent to the second quarter, we continue to return cash to stockholders by purchasing an additional 2.0 million shares of common stock for $104 million.

We also increased our regular quarterly dividend for the third quarter of 2014 by $0.025 per share to $0.275 per share, or $1.10 per share annualized.

Also in the second quarter, we announced the sale of the McKee Crude System, the Three Rivers Crude System, and the Wynnewood Products System to Valero Energy Partners for $154 million.

This transaction closed on July 1 and is an example of executing our strategy to create stockholder value through Valero Energy Partners.

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

We expect stay in business capital to account for slightly under 50% of total spending and for the remainder to be allocated to strategic growth investments, primarily for logistics and advantage crude oil processing capability.

I should add that approximately $870 million of Valero's estimated strategic capital spend for 2014 is all logistics.

And most of this is expected to be eligible for drop-down into Valero Energy Partners.

For modeling our third-quarter operations, we expect throughput volumes to fall within the following ranges -- Gulf Coast at 1.5 million to 1.55 million barrels per day, Mid-Continent at 410,000 to 430,000 barrels today, West Coast at 260,000 to 280,000 barrels per day, and North Atlantic at 440,000 to 460,000 barrels per day.

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

For our ethanol operations in the third quarter, we expect total production volumes of 3.6 million gallons per day.

And operating expenses should average $0.40 per gallon, which includes $0.04 per gallon for non-cash costs such as depreciation and amortization.

We expect G&A expense, excluding depreciation for the third quarter, to be around $165 million.

And net interest expense should be about $95 million.

Total depreciation and amortization expense in the third quarter should be approximately $420 million.

And our effective tax rate should be around 35%.

Okay, Sylvia.

We have concluded our opening remarks.

In a moment, we'll open the call to questions.

During this segment we request that our callers limit each turn to two questions.

They may rejoin the queue with additional questions after that.

(Operator Instructions)

Jeff Dietert, Simmons.

I was hoping to hit on capital spending.

You're staying consistent with your $3 billion forecast for 2014.

I was curious, as you look forward -- continues to be an opportunity-rich environment.

In your view, more light processing, more logistics.

Perhaps on the logistics side, do you see that as a steady trend, or a trend that's accelerating -- as far as logistics investment opportunities?

This is Joe.

Yes.

I'd say you raise a very good point.

If you look at it broadly, we're going to maintain a very balanced approach with the use of cash, returning it to shareholders via dividends and buybacks.

And then investing to maintain the quality assets, which is a core part of our capital program.

And then we're also investing to take advantages -- natural resource advantage we're enjoying.

Relative to the investment and logistics aspects, I think what you would see, now, is a bit of a shift in capital, in the strategic capital, from -- for example, we shifted some of the spending for the proposed methanol plant out to 2015, and we moved the crude-by-rail facility up into 2014.

So, as to percentage, I think [what] we have now is 54% of our strategic capital is now focused on logistics.

Whereas previously, Jeff, it was in the high 40s%.

The point that you made is one that we clearly agree with and recognize.

So, we have seen a shift in that capital.

Secondly, could you talk a little bit about your historical capital investment and what types of returns you're seeing so far from some of those investments?

Maybe on the hydrocracker investments at Port Arthur and St.

Charles?

What kind of returns are you seeing there, based on their performance to date?

Jeff, I'll tell you what -- you ask a question, and I think you recognize that it's very difficult to look at a unit within a refining complex and determine specifically what the return of that is, because of all the interrelationships in the plant.

I think we've said in the past -- and we would continue to say -- that the hydrocracker projects were very good investments.

The units are running very well, and Lane can't speak to that.

And the products that we're getting out of the units, are good, high-quality diesel fuel that we're able to export as EN 590 grades, versus a conventional diesel fuel.

So, although I don't have a specific return on the hydrocracker projects, per se, for you, I'll tell you we're pleased with the investment.

We think they have improved the quality of the portfolio, and are they're performing very well.

Yes.

Jeff, this is Lane.

They've averaged 120,000 -- the combine units averaged 120,000 barrels of the second quarter.

They've definitely earned very well.

These are great units.

We're currently in the process of performing a test run at our St.

Charles refinery.

I would be careful not to say where we are on that.

But it certainly allows us to look at a very limited, opportunistic capital investment (inaudible) to really bring them up to, essentially, (inaudible) out the equipment and the sizes of it.

But they've ran fantastically the second quarter.

Thanks, guys.

Paul Cheng, Barclays.

Two questions.

Joe, I joined a little bit late -- maybe you already covered it.

Do you have a preliminary CapEx outlook for 2015 and 2016?

No, Paul, we don't.

I'll tell you what.

What we're doing right now is, we're going through the strategic planning process, here at Valero.

And part of that, obviously, is the review of any kind of growth projects we want to be looking forward to doing in 2015, in addition to what we've got -- base loaded.

We're spending $1.4 billion, $1.5 billion a year on maintenance and reliability turnaround.

So, that is going to continue to be fundamentally part of what we're doing.

But we haven't settled in the on the growth projects that we want to carry forward, other than that we continue to pursue the crude units.

We continue to look at the methanol plant.

As you would expect, there's a host of logistics projects that we're evaluating.

But, we haven't settled in on the number, yet.

But you have settled into a direction, at least.

[This year, there's three.] Are we talking about -- from a direction standpoint -- flat, up, or down?

Yes.

Paul, it won't be up.

Okay.

The second question -- do you have an estimated downtime cost in the second quarter, in terms of the actual incremental cost?

[Also, it would be helpful that for two] -- number one is the actual incremental cost.

And the second one is the opportunity cost that you lost.

Paul, this is Lane.

Our unscheduled downtime cost in the second quarter was $103 million.

$103 million.

That's pretax or after-tax, Lane?

That's really EBITDA.

And you say that's opportunity cost, or it's actual cost?

I'm sorry.

That was what we would call our volume variance, which is if the units would've performed the way we had planned them, they would have generated another $103 million.

Right.

So that's the opportunity cost?

Yes.

How about the actual incremental cost?

Because I presume that you probably have some -- because of all the downtime, you have some additional maintenance cost and all that?

(multiple speakers)

Yes.

I'm not -- really, that's embedded inside our performance.

We'd have to get back with you on that exact number.

Okay.

Will do.

Thank you.

Paul Sankey, Wolfe Research.

Your throughputs in the quarter beat your guidance in every region.

You've effectively raised your guidance for 3Q to be more in-line with the better performance in Q2.

Could you talk a little bit more about the dynamics of how you're coming in so much higher?

Really, within weeks and months of having set the guidance, you're coming in about 10% plus higher, in terms of throughputs.

Could you just talk a bit more about, firstly, the technicalities of that?

Secondly, the implications?

Thirdly, where we might go, given the CapEx you've highlighted this year for [presenting] yet more light sweet?

Thanks.

Okay.

Paul, this is Ashley.

On actual run, throughput runs versus guidance.

Guidance is a conservative estimate based on planned downtime and turnaround, things like that.

And often, what you can do is run some -- get some throughput.

It might be a lower-margin throughput because you're buying higher-priced intermediates or other feedstocks to keep downstream going.

Generally, that's where you're going to see deltas.

So, it's not a function of you running more light sweet and, therefore, pushing more crude through the refineries?

No.

I think we had, generally, planned to run the amount of light sweet that we expected a few months ago.

It more has to do with planned downtime.

Okay.

So actually, what you're pretty clearly saying is, the better performance is simply due to a conservative guidance that you beat?

Because of the relatively heavy planned turnaround activity.

Right.

The final part of my question was, does your current CapEx program expand the capacity?

Or is it a shift mix entirely?

Paul, we'll let Lane talk about the crude units and what the impact will be.

Yes.

So Paul, this is Lane Riggs.

Again, we have our announced crude units -- one in Corpus Christi and one in Houston -- with the combined capacity of incremental sweet capability of about 160,000 barrels a day.

And then we'll finish McKee [plant], which is an incremental 25 a day next year.

Those are really the planned expansions on light [sweet product] and capability.

With that said, we still are learning the limits of our system on how much light sweet crude we can run, particularly in the Gulf Coast, where it's available.

We're not really -- we still optimize those crudes into our system, versus our alternative medium sour, heavy sour, and Canadian heavy, and all these others.

We can still optimize and run more if the economic signals are there.

Final part of this whole question is for me to ask you -- in the past, you said that you need a 10% light heavy differential to run a [coker], I think, was the guidance.

Do you have a sense the -- you talked about the sensitivities -- can you give us a sense for what the price differentials need to be to be running, more or less?

On light.

Paul, this is Lane.

You're saying that we've given guidance in the past that we [need] a light heavy differential of 10% versus--

Yes.

Kind of a rule of thumb for what causes you to run more light sweet in a mix against, for example, a medium sour.

To back out heavy and run.

Yes.

Back out heavy, and run sweet.

It's probably fair -- somewhere in that number.

Today, we definitely have incentive to run all three.

And they all have slightly and pretty similar margins into our crude capacity and/or into an open [coker].

So I think today, if you were to look at them, they're fairly reflective of what the relative values in the refineries are.

Okay.

So today, [you'll find] 13% off of [red], right?

It's in that general range.

And it still would signal us to run the heavy sour crudes versus pushing more light sweet into the plant.

Yes.

Correct.

Okay, guys.

That's helpful.

Thank you.

Sam Margolin, Cowen and Company.

I'll just touch on the condensate export issue.

It seems like it's come into flux a little bit over the past couple days.

I was wondering, as we await the BIS public guidance, as far as what the requirements will be in processing, if you have identified any opportunities at Corpus Christi, maybe either on the midstream side or sourced at the VLO level for that kind of processing capacity?

Where you can lean into some regulatory shifts that might nominally work against you.

But with the VLP, could actually become the revenue margin driver over time.

We look at these projects all the time.

Right now, we don't have a condensate [splitter] project on the board.

We're very focused on the two crude units that we talked about and, really, nothing beyond that at this point in time.

Sam, this is Lane.

I'll follow-up a little bit.

The two [crude units] that we have designed have a designed API gravity of 50.

So, these two crude units are fairly long on what we would say the equipment necessary to run a pretty light diet.

We could run condensate in them -- it's just going to be a matter of, again, what the economic signals and how distressed it is.

In our economics, we had LLS and Brent [parity].

And we had to export NAFTA out of the US Gulf Coast to the Far East.

So that stream, whether it's condensate, it's NAFTA, whatever form it takes, it has got to find a market -- whether it's Western Europe or the Far East.

The value of NAFTA is in the value of these condensates.

It will be interesting to see how it unfolds.

Okay.

Even if they are taking up to 50, they'll still produce some BGO for the hydrocrackers and some of the other downstream units, too?

Yes.

But not as much, right?

Because, it's lighter.

And that will be included in our economics.

Our alternative would be the intermediates to fill out our conversion units.

Okay.

Thanks.

I just wanted to touch on differentials in the Gulf, too.

There's been a lot of volatility.

I think last year, when LLS spiked to that Brent premium briefly in July and August, you guys had highlighted the fact that some barrels were coming in on Longhorn off spec.

And the spot market for LLS and in Houston got very tight because of that.

Is there any single piece of infrastructure development that we can be mindful of here, over the last couple of weeks, aside from very high utilization in the Gulf?

Maybe the delay in BridgeTex or something of that nature that might explain that LLS pop a couple of weeks ago?

Sam, this is Joe.

Randy Hawkins is with us this morning.

Randy is our Senior Vice President of Crude and Feedstock Supply.

And he'll be able to answer that for you.

I think you touched on it already -- the high utilization rate that lead to some of the spike that we saw in LLS at the end of the August trade month.

But I think you hit on the nose.

The thing that we're looking ahead is the BridgeTex start up that we're anticipating some time late Q3.

That will bring some of this distress -- the [midland-type] barrels to the Gulf Coast.

It should help provide some of the barrels that the Gulf Coast needs.

Okay.

Great.

I think it's delayed, right?

Is there some planned barrels or something that people are missing?

Sort of a spot market issue, maybe?

Yes.

I think there were, maybe, some people that were anticipating BridgeTex to be in a bit earlier.

And I think that overall, the high run rate, people were just a bit short.

And falling inventories, as well, led to that.

All right.

Thank you so much.

Blake Fernandez, Howard Weil.

I had two for you.

One bigger picture, and one more specific.

The big picture, Joe, as you transition into your new role -- I'm just curious if there's any low-hanging fruit or any strategic shifts that you see on the radar screen that you really want to address out of the gate?

That's a fair question.

But quite honestly, I think that this management team that's in the room today has been working with Bill for a long time.

And the plans that we put in place are plans that we're all very comfortable with.

So, if you look at what we've got on the burner -- with the crude units and the logistics investments -- and then you look at some of the projects that are being contemplated like the methanol plant, these are all projects this team feels pretty good about and that we're continuing to advance the conversations around.

So, from an investment perspective, there isn't.

From a use of cash perspective -- we have maintained, for some time now, that we're going to try to maintain a balanced program between investment in capital projects for growth and return of cash to shareholders.

I think we're going to continue to do that.

Very clearly, the fact now that we've had our second dividend increase this year, would support the fact that we are committed to increasing the cash returns to shareholders.

And then today, we bought back about 10.4 million shares.

And we'll continue to do that throughout the year, as cash flow is available to do it.

So, I would say there's no major shifts right now.

The ox cart is not in the ditch.

And as I mentioned earlier, we're going through the process of pulling together our strategic plan for the next several years.

Included in that will be the capital plan.

I think we're in a pretty good position.

All right.

That's great.

The second question -- I hope this is one question.

Your runs up at Quebec of North American crude hit 83%.

I was hoping you could give us a breakdown of how much of that is being barged from the Gulf Coast, and how much is actually piped from Canada?

And, similarly, on the rail to Saint Charles?

Just trying to understand.

Should we be thinking about the economics on that, as far as once you pay for transport, is that competitive with Maya, or even more competitive?

Just some general feel about how we should be thinking about the margin impact there.

Thanks.

Blake, this is Randy Hawkins again.

At Quebec, the split of our North American crude is [rough] around 50 a day by rail and about 100 a day via ships from the US Gulf Coast into Quebec.

Could you repeat the question on the Canadian?

Yes.

Basically, it looks like you started railing bitumen into St.

Charles.

I guess I view that as competing, maybe, with Maya.

And I didn't know if, by the time you paid for transport to rail it down from Canada, if we should be viewing that as more competitive -- in other words, discounted to what you could access Maya at, at par.

I would say the stuff we're railing down from Canada would be on par or better than Maya.

The volumes for Q2 were fairly small.

We anticipate those increase as we moved into Q3.

Blake, the refinery was moving [turnaround] in the second quarter.

So, we really aren't going to see effect in any of those -- that bitumen movement until third quarter.

Okay.

Great.

Thanks so much.

Faisel Khan, Citigroup.

Just a question to follow-up on Blake's question on Canadian heavy.

With the rail capacity at St.

Charles and even some of your other facilities, and with the connection to Keystone from Port Arthur, how much Canadian heavy do you guys envision having the ability to access by the end of the year?

How are you thinking of that, versus your term contracts with PEMEX.

Is there flexibility?

Just sort of arbitrage those barrels between each other?

Sure.

Faisel, this is Randy Hawkins again.

On our Canadian volume -- we do anticipate, with our rail facility in Lucas coming up later in the year, that we will increase the amount of rail [bit] that we're taking into our Port Arthur facility.

We also buy, regularly, Canadian heavy off of the pipeline systems coming out of Cushing, as well.

Right now, we don't anticipate that impacting our volumes with Mexico.

It more is backing out some of the spot heavy that we're doing elsewhere from around the region.

Okay.

How much capacity for Canadian heavy do think you guys will have the ability to run by the end of the year with all this pipeline and rail capacity?

For now, we are going to be limited by logistics more so than refinery configuration.

Okay.

Fair enough.

And then, my last question -- it's on the changes in the rail regulations that we've seen from the DOT and also the Canadian regulators.

Is that going to have any impact on the volumes you guys are moving around your system by rail?

Yes.

You know, Faisel, I think we're all waiting to see what those regulations are going to end up settling in at.

If you look at the things that are being proposed with the shell (inaudible) protection systems, the braking systems -- there's going to be a lot of retrofitting activity and modifications to already planned cars that are going to have to take place.

Frankly, the rail fleet that's in service today is very large.

And depending on a timeline for these retrofits, it's just going to have an effect on rail movements, just in general.

So, we don't have a good estimate, yet, as to what the overall impact is going to be.

We are in process of working the issues ourselves.

Specifically, working with AFPM and formulating a response to DOT and to Transport Canada's proposal.

But it's probably just a little bit early for us to give you any idea as to what the impact might be.

Okay.

Understood.

I will get back in the queue.

Doug Leggate, Bank of America.

It's actually Jason Smith, on for Doug.

If we could touch on throughput from the product side.

With you guys and industry seemingly running at a higher overall level -- in the release, I think you highlighted product prices versus Brent -- can you talk about what the implications of a self-sufficient US system are, particularly on gasoline, where I think we're exporting as much as we're importing, at this point?

We are looking at each other, trying to figure out exactly what it is that you're trying to understand.

Are you saying, at what utilization rates do we satisfy US demand?

No.

I'm trying to say, we've basically seen -- we've talk to a product prices, pricing off Brent.

But is there -- as we become more self-sufficient on the gasoline side, is there risk?

Do we potentially price off of LLS?

I see.

How do you see that playing out?

We're producing 9.5 million a day of gasoline today.

We're exporting as much as we're importing.

Right.

That's an interesting question.

Why don't we let -- Scott Lively is with us today.

He's our Senior Vice President of Products Supply and Trading.

Maybe he can give some thoughts on that.

I guess the way that I think about it -- I don't think about, necessarily, what price products have to price off of, as a feedstock.

I think you've got prices that are around the globe, and we have to compete.

So, barrels either [arbor] to those markets, or they do not [arbor] to those markets.

You can say, are we priced against brand?

Are we priced against something else?

Well, we're running a lot more WTI-based crudes in the Gulf Coast.

So that's a region -- sees more of a WTI-like margin.

Whereas something on the East Coast of a New York refinery, say, might price more against a West African, a Canadian that moves eastward.

So, I think you're going to see pockets of differentiation based on what crude types people run.

But, I don't think that I necessarily think about it the way that you're trying to describe, with pricing against Brent, specifically, or WTI, specifically.

Yes.

We do talk about the incremental barrel into a refiner being a light sweet [waterborne] barrel, which would be a Brent-type barrel.

But [as long as that's the incremental barrel,] you're going to be pricing products off of Brent.

You'd have to get rid of all the gasoline production in those marginal refineries, which that's a lot of European and African and South American refineries.

Those would have to be backed out and shut down before you're pricing the marginal barrel off of LLS or WTI.

That's a significant amount.

So, those are the price centers.

Yes, you're going to have times where US low-quality gasoline in the winter is going to trade cheaper than it does in the summer.

You always have seasonality.

But, the marginal barrel is still going to be priced outside of US.

That's going to set the prices.

Got it.

How is the shift to a lighter crude [slate] -- how is that impacting your gasoline yield?

Are you seeing more gasoline out of that crude, at this point?

This is Lane.

No.

We're still pretty much running, making almost -- within the noise of our systems -- the same amount of gasoline that we were.

And that's because of the flexibility of the system and how we can change end points.

Whether we made NAFTA or gasoline, there's just a lot of optimization points that we still have.

Got it.

My follow-up is on the West Coast.

One of your peers recently announced a petrochem feedstock project.

Are there any opportunities for projects like that within your portfolio?

And also, if you could, maybe, give us an update on the Benicia rail project and where that stands right now?

Okay.

This is Lane again.

I'll start with the Benicia rail project.

It's currently in the -- the DEIR is out during the comment period.

We expect to close on that.

The comment period will close September 15.

We're still confident that we will get a permit.

Of course, we'll, along with the city of Benicia, will have to help answer all the questions that come out of the DEIR.

On the first point, we aren't looking at a lot of projects -- to the ones that you are talking about.

And I think we're fairly skeptical.

It would be tough to get permits, I think, at the end of the day.

Even if we -- it would take a while to develop the project and get permits pushed through.

It's quite an effort, as you can see with the crude-by-rail project on the West Coast.

Okay.

Thanks, guys.

Appreciate it.

Roger Read, Wells Fargo.

I wanted to ask a little bit about the export market -- what you see for volumes as we head into the fourth quarter.

Traditionally, the strongest part of the year.

And if you could give us a recap of what you've seen in the diesel market year-to-date.

If we looked at where the futures were a year ago versus what we realized, margins came in a lot lower -- and I'm just speaking from a general or generic term.

Can you walk us through what you are seeing out there in the diesel market, both domestically and the export side?

And whether or not that has any particular concerns, as we look to the end of the year?

Roger, this is Scott again.

Over the quarter, we exported 210 a day of diesel.

And I'd say that's pretty flat with where we were in 1Q.

We still see continued global demand growth, and that's in that fuel.

So we feel pretty positive about our ability to export, number one.

And having those markets expert into, number two.

You did have a little bit of a hangover effect of the mild winter that Europe had, which really, particularly, kept German stocks from drawing down.

But those stocks are coming back more in line, and those guys look like they're going to need to be building, going into the winter.

So, we fully expect that these export rates that we've had to continue out into 3Q and 4Q.

Okay.

And then, something that got beat up on last year -- we keep waiting for the EPA to give us the official numbers.

Can you give us an idea of what you're seeing in the RINs market?

We all know where the prices are.

But what you've been doing about buying RINs -- plans are if they make changes, presumably, an upwards revision to the ethanol and other biofuel requirements, as has been rumored in the press.

As we, maybe, get something next month.

Certainly hope to see something by the October, November period.

Well, we do, of course, keep our eye on the markets, and we are participants.

I think it'd probably put me at a competitive disadvantage if I said exactly what we were doing or what I planned on doing if we got an idea that they were actually going to raise to or above the blend wall, as Podesta and, potentially, Gina McCarthy have alluded to.

I think we have to sit back, just like everyone else, and wait for them to come out with their final decision on what the obligation is going to be.

Hopefully, it's sooner rather than later.

Because obviously, as the time horizon shrinks, that shrinks the time horizon for you to be able to go out there and procure the RINs that you're obligated to in arrears.

Yes.

I think the one thing that we do have going right now, though, is that there is probably as much ethanol being blended into the gasoline pool as could possibly be blended.

As a result, supply of RINs is there.

So, the economics are supporting it.

And the ethanol market, in general, is favorable to blends.

Right.

Unfortunately, it's not always an economic driven story, where RINs are concerned and ethanol.

One final question, as a follow-up on that.

Have we heard anything about 2015 volumes or adjustments or any of that?

Or, is the expectation that, that may come out with the revised 2014 numbers?

I think that with the expectation is, is that it comes out.

It'd be interesting to have 2014's and 2015's come out -- well, it'd be interesting to have 2015 come out in 2014.

I would think that hasn't been their past practice.

But I don't think there's anything that we've heard through the grapevine that's given us any indication of what 2015 might be.

Okay.

That's it for me.

Thank you.

Ed Westlake, Credit Suisse.

Just on -- a bigger picture, strategic question.

$1.5 billion of growth CapEx, of which, around 50% going into logistics.

You've got VLP out there -- $2.6 billion.

It's a relatively small MLP.

But Valero's market cap has got a currency of its own.

And obviously, you can drop down assets into VLP over time.

Just get a sense of the color of how big you see the organic suite of opportunities in logistics.

And then, maybe even, any comments on using your equity to be more assertive, perhaps, in the inorganic M&A space.

Okay.

Well, I think we've stated before that we, at Valero Energy, have about $800 million of EBITDA that could be dropped to VLP.

So, it's a very significant number.

We completed the first drop, here, at the beginning of the third quarter on July 1, I think it was.

That was $154 million transaction.

I think it's fair to expect that we're working the subsequent drop transactions as we go forward.

I think we recognize, very clearly, the value of the interrelationships of the two entities and the multiple pickup we get when we drop from Valero Energy down to VLP.

We have a lot of projects, as you mentioned, that are in our current growth capital that we're working on, which will be assets that would add to the base of assets that can be dropped.

Really, the question that we're working through, is the pace and the timing on those.

We said we're going to grow VLP's distribution to 20% plus a year.

We still are intending to do that.

And so our drop schedule, at a minimum, would be able to accommodate that growth rate.

It just seems like there's a large opportunity for companies in your space who have the skills to be very large and successful infrastructure companies, against the shell revolution to continue to shift assertively into that direction, given the relative multiples.

Appreciate you might be going through the planning process now.

But any thoughts about the direction you want to take the Company?

Yes.

No.

I think we're looking at a host of different logistics projects that are in development and will allow us to take advantage of what you've described.

There's great opportunity with the shale plays.

But I don't have anything specifically to share with you right now.

Okay.

Then, maybe a question for runs, just on crude.

Obviously, LLS spiked last year, and then LLS collapsed in the fourth quarter.

The spike is -- let's hope its history.

And let's focus on the future, where we could see, perhaps, a repeat of what we saw the fourth quarter.

A couple of things seemed to happen last year.

Obviously, we built gasoline for a hurricane that didn't happen.

There were lots of imports during the period.

There was a rapid rise in inventories, seasonally.

You folks and others in the industry were trying to reduced inventories for the usual year-end planning purposes.

So I'm just -- the question.

You mentioned BridgeTex earlier.

But is there anything different that you see happening this year?

Or do think this is sort of a new seasonality that's going to set in for the Gulf Coast crude prices?

Yes.

Thanks for that.

I think the biggest difference that I see, is that crude runs are so much higher than what they've been, as of late.

Which, we go through some seasonal turnarounds as we head into Q3, Q4.

So my thought is that this thing will get back to normal.

And as we're seeing September contract trade today, and we've seen LLS back down $2 to $3 under Brent.

And (inaudible) $7 under Brent.

So things are starting to look more normalized.

Yes.

And then, maybe, one tiny follow-on.

Obviously, in winter, there's a difficulty pushing gasoline into the US market.

And so you try and export the product into other markets.

How are we, in terms of the ability for you to say, maintenance aside, run at a higher utilization than you would have done in the past?

Because of the ability to export more product and out-compete other refineries around the world?

Any color, there?

This is Scott, again.

As you noted, those gasoline exports are seasonal.

We do export less in 2Q and tend to export more in 3Q and 4Q, especially as we have more availability and butane works itself back into the pool.

I think that we are going to be cost advantaged.

And we do see plenty of opportunities with growth in markets in Central, South, and Central America, South America, and in Mexico.

We still see plenty of opportunity to put barrels down in those regions.

We still feel pretty good about our position to export and keep refinery rates high in our system, as a result of those exports.

This is Lane.

What I'll comment -- one last thing I'll add was, as Scott just said, to your point, the US Gulf Coast capacity is the most competitive capacity of the world.

So, we can chase any market.

We have the low natural gas prices, we have an efficient label for us, and we're well-positioned to maintain our assets as high utilization as we can [find].

We're not really up against any export logistics, per se.

We don't really see that being a limit.

Thank you.

Evan Calio, Morgan Stanley.

Maybe a more specific follow-up on Ed's question.

I know you're not providing 2015 CapEx guidance, at this point.

It was asked and answered.

Yet, given you had the MLP and given midstream spending has increased percentage of CapEx, how do MLP drop downs relate to your consideration of CapEx?

As it would appear to me, that they're direct offsets and potential distributable cash flows.

And I have a follow-up.

Thanks.

Well, that's the million-dollar question right there, isn't it?

Mm-hmm.

The subsequent question -- that is, at what point in time do we start doing these logistics projects in VLP itself and not in Valero Energy for drop down?

Mm-hmm.

We have a lot of good projects that we're looking at.

And we're trying to understand this whole notion around, if you look at a gross capital or net capital number, to be quite honest with you.

Mm-hmm.

We have a very good feel for, I believe, what we are going to be spending on the refining side of the business.

The wild card, here, is how much do we spend on the logistics side?

I know you'd love to have a number.

And there will be a point where we give it to you.

But I'm just not prepared to share it today.

Mm-hmm.

Let me ask you a question.

When you're evaluating midstream projects and what ultimately goes into the EBITDA that you're characterize as MLP-able EBITDA, do you consider the relative cap rate versus the MLP drop rate in the overall calculation of the IRR?

[For instance, they're very different.]

And more color there, I think, would help us.

I'm just curious if that's an element of your evaluation of what to proceed on.

Yes.

I believe it is.

Mm-hmm.

Maybe lastly, then, for me.

Any update on the timing -- we're keeping a midstream focus here -- but any update on the timing of potential methanol facility decision?

And given Westlake Chemical Partners MLP IPO that uses a fixed-rate structure versus variable?

And is -- I think it's up 25% this morning -- well through the range.

How does a structure like that factor into that project consideration, which I know is under review?

And I'll leave it at that.

Thanks.

Honestly, we mentioned earlier that we continue to take a look at the project, and we're advancing the engineering.

Lane and his team are trying to get our arms around [exactly] what the scope of the project is.

Mm-hmm.

[I haven't had a chance, yet,] to look at the transaction you mentioned to know the impact of it.

So we'll take a look, and, perhaps, we can loop back with you and have Ashley involved -- [and John].

Okay.

Specifically, we are in Phase 2. We're doing all the engineering, the major equipment, so we can nail down the cost estimate.

And we'll have that reviewed in the fourth quarter.

That's where we are in the process.

Okay.

And that's the process prior to -- [because it's going to reach an FID].

Is that accurate?

It's the process -- I'm sorry -- can you say that again?

I'm sorry.

Is that the step -- after that phase is complete, is that when you then decide whether or not to go to a final investment decision?

That phase, we'll make a decision whether we feel so good about it that we'll go ahead and order [all the] equipment, which would expedite the project.

That's really the critical decision that we'll make (inaudible).

Great.

All right, guys.

Appreciate the information.

Thanks.

Alan Good, Morningstar.

I want to try to come back to the export question and, maybe, get your longer-term outlook.

There seems to be a lot of changes underfoot there, with a lot of the refining capacity additions in Asia and the Middle East -- potential improvement in European competitiveness, given exports of, maybe, heavy crude over there, maybe even light crude.

I think you have a bunch of peers increasing exports, as well.

Could you talk about your long-term outlook there?

And how you think the export market for US refineries and Valero, particularly, will develop?

Alan, this is Scott again.

I think that we're a bit ahead of the curve versus Europe, of course, on running those price advantaged crude.

So depending upon how long that takes to work its way in, you can still see more closures in Europe.

And clearly, Europe's at a pinch point between the United States and -- mostly, the US and Russia.

Like I said before, I still feel pretty good about our ability to export into these markets.

A lot was made about (inaudible) coming online.

So far, you can see a sprinkling of cargos go here and there.

But so far, what we've seen is those cargos from (inaudible) has mostly gone into internal demand.

And stayed on the East Coast of Africa.

So, sure, going forward, there's more refineries that are going to come online.

And by way of China, there's going to be more capacity in the US.

But you should see that tempered with refinery closures, especially those ones that are marginal.

As we said before, we still see the prospect of world demand growth for diesel.

Okay.

Switching to the condensate export question -- just looking at your recent investment presentation, and you have some notes in there saying that at the end of the day, less condensates in the crude stream could ultimately be beneficial for Valero, given some of the utilization rates and yields.

Have you been able to quantify, exactly, what the loss on utilization or yields may have been over the past couple of years, as those crude streams did get lighter with additional condensates?

This is Lane.

I don't know -- I'm not sure I can give you exactly the loss.

It hasn't been large.

We're very careful, in terms of how we articulate the quality of those suppliers.

We have [deducts,] and we can't give you numbers.

But we have standard deductions, as API gravity goes up, to try to offset any financial penalty we might have.

As refiners, we personally would like to see the condensate out of the blended crude.

But that's going to take a considerable infrastructure build out to try to get the condensate, in whatever location, pushed (inaudible).

We're not necessarily opposed to condensate being segregated to other crude strengths.

But today, we haven't had any real major constraints, based on these gravities.

The way we purchase our crude, we certainly attempt to offset it.

Just a follow-up from an earlier comment regarding that.

You're not interested in making any of those investments that would separate the two?

Again, our crude units have a capacity to -- we've designed them for 50 API.

We can certainly run them at slightly reduced capacity.

We can run even more.

I think [when we have benefits] from the way we do things, we'll compare condensate versus our alternative crude economics.

And that will determine how much we're going to run.

I think what I was trying to pose earlier was, the industry and everybody making this stream -- we're just going to have to find a market.

Whether it's slightly altered condensate, processed condensate, [new] condensate.

I'm not sure.

It has to find a home somewhere.

Our assessment was it's going to be the Far East.

But we will certainly [arb] that relationship of condensate to crude down as it becomes more available.

Okay.

Great.

Thank you.

Faisel Khan, Citigroup.

Just a couple of small questions.

First one, with the Cushing inventory reaching bottom, is there any impact to McKee and Ardmore for you guys?

Or do you have enough inventory within the refining gate to, basically, not be impacted by lower inventories at Cushing?

Faisel, this is Randy, again.

At McKee, specifically, it's mostly a Midland market, which is flush with crude oil at the moment.

And similarly, Ardmore also takes some barrels out of that market, as well.

So we're really not seeing any impact on supply -- the source barrels.

Is it fair to say that, because of where production is, that you don't need the inventory levels?

Because you've got enough growth in production to offset the balancing impact of having storage in place in previous years?

I think definitely the market (inaudible).

So there's no incentive for people to hold barrels there.

Okay.

Fair enough.

Last question on -- actually two more questions.

On the Corpus Christi dock, could that dock be used for condensate exports?

Have you guys looked at that?

This is Rich Lashway.

Yes.

We looked at that, and it could be used for condensate.

Okay.

Fair enough.

The last question is on getting barrels into Louisiana from Houston.

Are you guys having any issues, or are you pretty much able to get as much crude from the western side of Houston into Louisiana?

Any constraints that you guys are seeing?

No.

This is Randy, again.

No real constraints.

It's moving via pipe on the Ho-Ho and barging and shipped in through Louisville.

All that does satisfy -- and the rails continue to come down, as well, from the Bakken.

So [St.

James] is well-supplied.

Great.

Thanks a lot, guys.

Appreciate the time.

Sure, Faisel.

Thanks, Faisel.

Thanks, Sylvia.

I think with that, we appreciate everyone calling in and those listening to our call today.

If you have additional questions, please contact our IR department.

Thank you.

Thank you, ladies and gentlemen.

This concludes today's conference.

Thank you for participating.

You may now disconnect.