瓦萊羅能源 (VLO) 2011 Q3 法說會逐字稿

Welcome to the Valero Energy Corporation reports third quarter 2011 earnings conference call.

My name is John, and I'll be your operator for today's call.

At this time, all participants are in a listen-only mode.

Later we will conduct a question-and-answer session.

Please note that this conference is being recorded.

I will now turn the call over to Mr.

Ashley Smith, Vice President, Investor Relations.

Mr.

Smith, you may begin.

Thank you, John.

Good morning, and welcome to Valero Energy Corporation's third quarter 2011 earnings conference call.

With me today are Bill Klesse, our Chairman and CEO; Mike Ciskowski, our CFO; Gene Edwards, our Chief Development Officer; Kim Bowers Executive Vice President and General Counsel; and Jean Bernier, Executive Vice President.

If you have not received the earnings call -- the earnings release and would like a copy, you can find one on our website at valero.com.

Also attached to the earning release are tables that provide additional financial information on our business segments.

If you have 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 result to differ from our expectations, including those we described in our filings with the SEC.

Now I'll turn the call over to Mike.

Thanks, Ashley, and thank you for joining us today.

As noted in the release, we reported third quarter 2011 net income from continuing operations of $1.2 billion, or $2.11 per share, compared to $0.53 per share in the third quarter of 2010.

Our third quarter 2011 operating income was $2 billion, versus operating income of $590 million in the third quarter of 2010.

The third quarter refining throughput margin was $13.24 per barrel, which is a 63% increase over the third quarter of 2010.

The increase in throughput margins over the third quarter of 2010 was due to higher margins for diesel, jet fuel, and gasoline, plus wider discounts for heavy sour crude oil, residual feed stocks, and light sweet crude oils in the mid-continent and in south Texas.

In the third quarter of 2011, the Gulf Coast gasoline margins per barrel versus LLS increased 89% to $8.20 from $4.35 in the third quarter of '10.

The Gulf Coast ULSD versus LLS margins per barrel increased 56% from $9.12 in the third quarter of '10 to $14.19 per barrel in the third quarter of 2011.

So far in the fourth quarter, Gulf Coast margins have moved lower, averaging around $1 per barrel for gasoline and nearly $13 per barrel for ULSD.

The Maya heavy sour crude oil discounts versus LLS increased 22%, from $11 in the third quarter of '10 to $13.48 per barrel in the third quarter of '11.

The Maya discount has narrowed some in the fourth quarter, with the average down to around $12 per barrel.

These discounts are important in our Gulf Coast region, where we have significant capacity to process heavy sour crude oils.

Another benefit for Valero came from mid-continent and Eagle Ford crude's pricing at a substantial discount to LLS.

Over the last year, the WTI discount to LLS has increased by nearly $20 per barrel from $2.58 in the third quarter of '10 to $22.47 in the third quarter of '11.

The WTI discount significantly enhanced the profitability of our McKee and Ardmore Refineries, both of which processed WTI or cheaper crude oils.

The fourth quarter WTI discount to LLS has averaged around $25 per barrel, but recently the spread has narrowed, and yesterday closed at less than $19 per barrel.

We also continued to increase the use of the discounted Eagle Ford crude in our system.

During the third quarter, we processed an average of 46,000 barrels per day of Eagle Ford, primarily at Three Rivers, but also some at Corpus Christi.

That is an increase of 9,000 barrels per day over the second quarter and an increase of more than 40,000 barrels per day since 2010.

This local crude replaced more expensive imported sweet crude, saving Three Rivers and Corpus around $15 per barrel in the third quarter.

We also took delivery and ran discounted sweet crude's from the strategic petroleum reserve in the third quarter.

Valero purchased 6.9 million barrels at a discount of over $5 per barrel to LLS, providing $35 million in additional refinery throughput margin in the third quarter.

At our Aruba refinery, operational improvements combined with better commodity prices resulted in Aruba generating an operating profit in this quarter.

In the North Atlantic region, we had a smooth transition with the addition of the UK and Ireland businesses, including the Pembroke refinery.

The refinery has run well, and we continue to integrate the businesses into our operations.

On the west coast, our throughput margins versus benchmark cracks performed well, mainly on wider crude discounts and increasing the use of such crude's.

In addition, operational improvements at our west coast refineries helped to enhance our liquid volume yields.

One final comment on refining markets is that international demand, particularly in the developing markets, has been the key driver for growth in 2011 and helped to elevate the margins to the levels we have seen so far this year.

Our cost-efficient refining portfolio will continue to take advantage of both domestic and international opportunities available in the marketplace.

Our third-quarter 2011 refinery throughput volume averaged 2.6 million barrels per day, up 389,000 barrels per day from the third quarter of '10.

The increase in throughput volumes was due to a combination of economic incentive from stronger margins, the addition of capacity from the acquisition of the Pembroke refinery on August 1, and the restart of operations at the Aruba refinery.

Refining cash operating expenses in the third quarter of 2011 were $3.65 per barrel, which was lower than the second quarter of 2011 and our guidance, mainly due to higher throughput volumes.

Our ethanol segment reported record-setting quarterly earnings with $107 million in operating income in the third quarter, which was up $60 million from the third quarter of 2010, and up $43 million from the second quarter of this year on higher gross margins.

Our retail segment reported a solid third quarter with $97 million of operating income.

US retail had $59 million of operating income in the quarter, and the Canadian retail operation earned $38 million of operating income.

In the third quarter, general and administrative expenses, excluding corporate depreciation, were $161 million.

Depreciation and amortization expense was $390 million.

Net interest expense was $88 million, and the effective tax rate on continuing operations in the third quarter was 36.4%.

Regarding cash flows in the third quarter, capital spending was $684 million, which includes $69 million of turnaround in catalyst expenditures.

Also in the third quarter, we paid $28 million in dividends and $268 million to purchase 13.5 million shares of our common stock, or 2% of outstanding shares.

We also spent $1.6 billion to acquire the Pembroke refinery and related the marketing assets, which included approximately $900 million for working capital and other assets.

With respect to our balance sheet at the end of September, total debt was $7.6 billion.

Cash was $2.8 billion.

And our debt-to-capitalization ratio net of cash was 22.4%.

At the end of the third quarter, we also had over $4 billion of additional liquidity available.

And as referenced in the release on October 1, we acquired the Meraux Refinery and related logistics assets for $586 million in cash.

This payment included approximately $260 million for a preliminary estimate of inventories and other assets.

And we do expect to receive in the fourth quarter a favorable true-up adjustment that will reduce our price by approximately $40 million.

Our completed growth projects are beginning to add to our earnings power.

We realized the benefits from our St.

Charles FCC revamp project during the third quarter, its first full quarter of operation.

These benefits included improved liquid volume yield, lower energy costs, lower catalyst costs, and reliability benefits.

Using third quarter 2011 prices, we estimate the annualized EBITDA benefit from this project is approximately $150 million.

Our remaining growth projects remain on budget and on time to complete in 2012, and we expect these projects to generate significant earnings and cash flow growth when started up.

The hydrogen plants at Memphis and McKee should be completed by the end of 2011.

Our two Hydrocracker projects at Port Arthur and St.

Charles are set to finish in the second half of 2012, along with the Montreal products pipeline and the Diamond Green Diesel joint venture.

Most of the projects were designed to capitalize on high crude oil and low natural gas prices, while producing diesel and gasoline to meet the growing global demand.

In summary, we had an excellent third quarter.

We took the opportunity to return cash to our shareholders via stock buybacks, and last week our Board of Directors tripled our quarterly dividend rate to $0.15 per share.

These decisions are result of our strong financial performance, favorable industry conditions, and a significant contribution that we expect from our major growth projects that are scheduled for completion next year.

Regarding strategic activities, we added another quality asset to our portfolio and further improved our earnings power with the acquisition of the Meraux Refinery.

This is a flexible, high-quality asset with distillate focused conversion capacity, including a 34,000 barrel-per-day Hydrocracker.

This first quartile refinery fits well into our Gulf Coast system and has excellent potential for synergies with our nearby St.

Charles Refinery.

We have also restarted a formal process to seek strategic alternatives for our Aruba Refinery.

In conclusion, the significant contributions expected from our major growth projects, which are independent of the WTI-priced crude discounts, selective strategic acquisitions that improve earnings power, our strong financial position, and our investment-grade credit rating provide an excellent combination for future earnings and cash flow growth.

Now I'll turn it over to Ashley to cover the earnings model assumptions.

Okay, thanks, Mike.

For modeling our fourth-quarter operations, you should expect the refinery throughput volumes to fall within the following ranges.

The Gulf Coast should be somewhere between 1.52 million to 1.56 million barrels per day.

Immediate continent at 430,000 to 440,000 barrels per day.

The West Coast at 270,000 to 280,000 barrels per day.

And the North Atlantic at 440,000 to 460,000 barrels per day in the fourth quarter.

Refining cash operating expenses are expected to be around $3.85 per barrel in the fourth quarter.

Regarding our ethanol operations, we expect total throughput volumes of 3.4 million gallons per day, and operating expenses should average approximately $0.36 per gallon, including $0.04 per gallon for non cash costs, such as depreciation and amortization.

With respect to some of the other items for the fourth quarter, we expect G&A expense, excluding depreciation, to be around $175 million.

Net interest expense should be around $85 million.

Total depreciation and amortization expense should be around $390 million.

And our effective tax rate should be approximately 36%.

We'll now open the call for questions.

John?

Thank you.

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

(Operator Instructions).

And our first question comes from Doug Terreson from ISI Group.

Please go ahead.

Good morning, everybody, and congratulations on your great results.

Thanks, Doug.

Mike, you mentioned something just a second ago about some type of a strategic review process at Aruba.

I may have misunderstood, but I wanted to see if we could get clarification on what you said and also what you meant by that statement or that point.

Okay.

We have started a process of looking for strategic alternatives for our Aruba Refinery.

Okay.

Yes.

If I can add to this, Doug, our operations have improved a lot.

Our people are doing a fine job.

We have several excellent reduction, cost reduction efforts underway.

Okay.

For Valero, we use it really as we're looking at the refinery going forward, as a feedstock source to our big conversion operations along a large conversion operations along the Gulf Coast.

So in a way, it's a front end for us.

We're looking at some reconfiguration as to where we do hydrotrading, but the facts are, we're still very interested in finding a partner or some relationship that allows us to process very sour heavy crude or heavy tan crude, which the refinery can do.

Okay.

And Bill, you've been a leader for the industry on the regulatory front over the last several years.

And over the past -- maybe longer than that.

Over the past several month, there have been commentary on new rules for US gasoline for 2012, which I believe they're calling tier three, and resemble those in California, but for the entire United States.

My question is, do you have any insight into these new rules?

Specifically, whether this new movement appears to be significant?

And what if any implications there might be for Valero?

Well, I don't know if I have any insight.

But what's going on is under the Clean Air Act Amendments of 1990, there is a certain protocol passed by -- and the Clean Air Act was passed by Congress.

Sure.

So the EPA, it looks at ethanol being added to fuels and other primarily ethanol-reflected then and vapor pressure and the emissions feels like they need to drop the sulfur to honor the commitment of the Clean Air Act and drop it to 10 PPM average.

Right.

What is under debate still, well the whole issue is, but the ceiling as to whether it's going to be a 30 PPM max or an 80 PPM max.

Today we have an 80 PPM max, 30 PPM average.

And then tier three will have different numbers.

So it's all being discussed.

Our industry is against it.

It will raise the costs for the consumer.

And we think it is an extremely marginal benefit, if any benefit at all.

Okay.

Great.

Thanks a lot, guys.

Our next question comes from Paul Cheng from Barclays Capital.

Please go ahead.

Paul, your line is now open.

Hi.

Good morning, Paul.

Yes, good morning.

Sorry.

Just a number of quick questions.

Mike, can you give me what is the working capital, the mark of the inventory in excess of the bulk, and of the total debt, what is the long-term debt component?

Okay, sure.

Total current assets are $15.9 billion.

Total current liability is $11.7 billion.

Market value in excess of LIFO value is $7.1 billion.

Our long-term debt and capital leases is $7.6 billion.

And at the $15.9 billion current, I presume that's including cash, right?

Includes $2.8 billion of cash, yes.

Okay.

And Mike, in your results, is there any trading in your loss?

And also do you have any future hedging position?

The trading gain in the third quarter was very minimal.

It was about $3 million.

And any hedging position for the next several months?

No material positions.

And Bill, maybe can you share with us what is the major turnaround you guys are going to do in the first half of next year?

I'm going let Lane Riggs answer you.

Paul, this is Lane Riggs.

Our major turnarounds are in Wilmington, on the West Coast.

It's a crude [vac] (inaudible) hydrotreater CPR, so essentially half the refinery.

St.

Charles, in February, which is the crude (inaudible) diesel hydrotreater (inaudible) for diesel and SRE use, so again, similar-type turnaround excluding the SEC.

And in Houston, we have an SEC alki in February.

And then finally, we have in March, Memphis which is crude and diesel hydrotreater unit turnaround.

How many days are those --?

Let me -- let me add to this.

The February one at St.

Charles is a huge turnaround for us.

We're going to replace the coke drums.

Many of you that follow us know we've had this Coke drum issue at Port Arthur and at St.

Charles, which was an engineering design.

And what we're doing is replacing the coke drums.

We did it at Port Arthur this year.

And next year we're going to do it at St.

Charles.

To do this lift at St.

Charles extends this turnaround.

I think we released it this morning, and it's 70 days.

But it's a very large turnaround for us at St.

Charles.

But that will then put these issues we've had with the cokers, except for some vapor lines, behind us.

Perfect.

And for Wilmington and Houston, how many days are we talking about?

On Wilmington, it's about a month, and Memphis is also about a month.

Memphis is also a month.

How about Houston?

It's 37 days.

Okay, Houston is 37 days.

Mike will you be able to share with us how much you make in Europe for the two months in the quarter?

Let me just finish in the turnarounds.

We announced that this morning.

So the release went out as to our turnarounds in the schedule.

Yes.

You can -- if you're interested in looking at the details on the turnarounds and the timing, you can find those on our website.

Oh, perfect.

Thank you.

Mike?

Yes?

Will you be able to share with us that -- how much you make in Europe for the two months you're only in the quarter?

Yes.

We made a little over $53 million in the first two months.

And then a final one.

Bill, for the M&A market, can you share with us what you're seeing?

Is the pricing condition, in terms of acquiring us, the pricing conditions become better or become worse over the next -- last several months for you guys?

Or what you can see out there.

Well, I don't know if I can speak to the pricing conditions, but there's certainly several refineries for sale.

We believe we bought the two refineries we purchased here recently at very, very good numbers.

They fit into our portfolio, strategically, too.

We wanted to step out some, so we could have done that.

When you look at where Valero trades relative to what we purchased for these refineries, we actually paid for -- purchased them for less than what we trade.

Obviously there's quite a few assets on the market.

And then just anticipate the next question, because I can't speak to the pricing except that I've said a couple of times it's a buyer's market.

And it continues to be that way as a general statement.

In Valero's particular case, we're only interested in acquisitions that fits us strategically and that is accretive, and it has to be both.

If it's not fitting us strategically, we're not interested.

And there is no case I can think of that we would issue any equities on any situation that's out there.

You guys already did a new share buyback in the third quarter.

In terms of the cash you generated, the free cash, over the next several quarters, are you going to become more aggressive in your share buyback, given how cheap the stock may be?

Well, I think as you look at us, which is a general cash question, in the volatility we see in the markets today, we will hold more cash than we would have historically.

And I've said that consistently.

But when you have crude oil price move $5 to $8 in about a three-day span, we just think you have to do that today.

Now, what is happening with us is, obviously, we're having much better financial performance this year.

We think many of the things that contributed to this year's financial performance are going to continue next year, and so we're anticipating a good year next year, as well.

And then we have a very high capital spending.

But those strategic projects are coming to an end, and we can see the light at the end of the tunnel.

So when you begin to combine our performance, our cash balances, that our strategic projects will be completed, some, as Mike said right now, some, the big hydrocrackers next year, clearly we have more cash available.

And then you take the next step, and we've demonstrated it here just in this quarter and going into the fourth.

We expect to pay one of the highest dividends among our peer group going forward.

We will buy our stock periodically, especially as we think the stock is undervalued.

And we, as management, clearly think our stock is undervalued.

As a little side issue or side comment, the reliance discussion, this rumor that was out there, one of the benefits has been to point out to the investment community the earnings power of our portfolio and our Company, so that was actually a benefit here of a rumor.

But we have lots of earnings power.

Our projects are coming to an end.

And we think our stock is terribly undervalued.

Thank you.

All right.

Great, thanks, Paul.

Our next question comes from Thistle Khan from Citigroup.

Please go ahead.

Good morning, it's Faisal from Citi.

Hi, Faisal.

Back to the Aruba statement, if you can't find a strategic partner or an alternative for Aruba, what's the next option after that?

We'll, we continue to improve the operation.

We have several things that will reduce our costs.

But it is a very good front end of a refinery that can run very, as I said, heavy and high tan crudes.

And so we'll continue to improve the operation.

And it will be then -- that refinery when we run around 200,000 barrels a day makes about 70,000 barrels a day of VGO.

And we'll charge that to our hydrocrackers that come on next year.

So for us, we see improving its cost structure and using it as a front-end of a refinery.

There's 200,000 barrels a day of crude vacuum coking there that can feed our operations.

Okay, I understand that.

Going to your Memphis and McKee hydrogen plants, as those come on line at the end of this year, what should we expect from the uplift going into the first quarter of next year from those plants?

What is that going to do to the performance of those two plants?

So, they're completed by the end of the year, and then we'll start them up in the first quarter.

And we have a table we give you, and we're looking for it here.

Ashley?

Yes.

Faisal, depending which price deck you use, we've given pretty much every slide deck for the past nearly year.

We've given example economics, based on different price decks.

Okay.

If you use 2010 pricing, it's an extra $105 million a year of EBITDA.

If you use 2011 price, it includes the last couple months.

It's $150 million of EBITDA, and that's incremental.

And it's basically because you're making your hydrogen out of natural gas instead of destroying extensive oils to do so.

So, you'll see margin uplift.

It basically will drop down to EBITDA.

And that table's been in the appendix of our handouts.

Yes, our typical slide decks, which are publicly available to everyone and have been.

Okay, thanks.

I'll take a look at that.

And on the ethanol segment, you performed pretty well in ethanol, despite crush threats coming down over the quarter.

What caused margins to go up even though crush spreads came in?

Well, the crush spread isn't necessarily how you get to the EBITDA, because our margins are a little bit different when it comes to source grain and byproducts we make.

We look at our average margin on an EBITDA basis being about $0.35 a gallon over the quarter, for the entire quarter.

I think we just look at the financial -- the markers with corn, ethanol, and source it would have ben more like $0.30.

I think if corn prices dropped, we got a little bit extra benefit there on our corn position.

So that we made -- if you look at how many gallons we made and the number that Mike told you earlier, it was right about $0.35 a gallon.

And as the subsidy expires at the end of this year, what do you guys expect will take place with your operations going to next year?

Well, remember ethanol's still mandated.

We're blending ethanol in to about 91% of the total US gas scene right now.

I think that's going to continue.

Ethanol is trading above gasoline now for about probably the first time this year, as it turns out.

We're probably $0.35 a gallon over gasoline.

The worst case I look at it right now, if you go back to Perry gasoline, our current EBITDA on our plants is up $0.65 a gallon.

If we lost $0.35 of that, we'd still have a very positive margin.

It's driven by a mandate, so supply/demand exports have been strong into Brazil and to Europe, as well, so that's supporting the price.

I think the supply/demand says that all plants need to run right now, including some of the peripheral plants that don't have as good of corn logistics.

So we think that we'll have good margin at our plant because they're well situated on the corn supply.

Okay, great.

Right now, margins are just excellent, though.

Okay, thank.

Last question from me.

In theory if Libya continues to ramp up, do you have an outlook for the heavy-light spreads going into next year?

Yes, I think they're going to continue to be somewhat similar to this year.

Okay.

Great.

Thank you.

Our next question comes from Blake Fernandez from Howard Weil.

Please go ahead.

Good morning.

Congratulations on the results.

What I wanted to ask -- what is the current authorization on the share repurchase program?

Okay, we have a Board-approved program that is $3.46 billion of authorization.

Okay.

Secondly, I wanted to ask about Pembroke.

With so much capacity on the East Coast potentially at risk of closure, I guess my thought is that could be a direct benefit to Pembroke with the Trans-Atlantic arbitrage.

Am I thinking about that correctly?

I think you are.

This is Gene.

Obviously the European barrels do flow to US East Coast and having that capacity shutdown is going to create opportunity.

However, there's -- it's a whole Atlantic basin market.

And the marginal refineries are going to be under pressure just like they have been this year.

So -- but it does give an advantage to well-situated refineries in Europe.

We think Pembroke fits that category.

Okay, great.

And the last one for you.

I know the growth projects, it was hinted that they're all on budget and on time.

As I look at first-call estimates into 2012 and 2013, it does not really seem like the street is reflecting the incremental, call it $2 a share of incremental earnings from these projects.

Is there anything in the macro that you see today that puts at risk that number?

Are we still on track for an incremental $2 a share from all these projects?

Yes.

I think the main factor is just with crude in the $100 range and natural gas in the $4 range, it gives these projects a good uplift because it's basically a gas-to-liquids-type project as far as the majority of the benefit.

The distillate crack is secondary compared to the volume lift you get from natural gas.

Great.

Thank you very much.

Our next question comes from Doug Leggate from Banc of America.

Please go ahead.

Thank you.

Good morning, everybody.

Good morning, Doug.

Quick one, fellas, on Meraux.

Can you talk about exactly how you're operating that facility, how you plan to integrate it?

And I guess really -- are you trying to actually run the unit there or use the operating units?

I'll have a quick follow-up please.

Yes, this is Gene again.

We're basically operating how Murphy was operating before.

But we are starting to capture some synergies.

We've integrated in with our feedstock supply, so we've picked up synergies there.

We also -- the products, there are a lot of Murphy was using to supply their Florida business, we're just using and optimizing our overall system.

We find the (inaudible) of the diesel that's produced there off the hydrocracker, we're finding some synergies on blending that with St.

Charles' diesel.

Procurement side, I think we'll see some advantages on our purchasing power going forward.

So, net effect, we're running it as is today, pretty much the way (inaudible), just pick up on some of these synergies.

(Technical difficulties).

Doug, you must be on a cell phone and you're breaking up.

Any better?

Yes.

Much better.

Okay.

I'll just try one quick one, then.

Are you planning to change the feedstock at Meraux in terms of -- you've about Three Rivers and Eagle Ford and so on.

Is there anything you can do to actually change the feedstock there?

And I'll leave it at that.

Right now, we can run medium sour crude.

It runs about one-third of sweet crude.

So we will always try to optimize that based on where the light sweet spreads are.

We can go to 100% sour to sweeten up even more, if the economics say so.

Right now, we're pretty much in this two-thirds sour, one-third sweet still.

All right.

I'll leave it there.

Thank you.

Our next question comes from Mark Gilman from Benchmark.

Please go ahead.

Guys, good morning.

A couple things if I could.

Mike, did you book any goodwill on the Pembroke deal?

No, we did not.

Okay.

And the $56 -- the $53 million that you quoted previously in terms of the contribution in the quarter, I assume that that's an operating profit number.

Yes, operating income.

Operating profit, after DD&A.

Okay, how much of that buyback authorization is remaining?

The number that I gave you, this $3.46 million is what's remaining.

And then, in addition, to that, we can purchase dilution under our benefit plans.

Okay.

Just one more from me.

You made reference to discounted West Coast crude feed stocks, San Joaquin, Canadian Light, both be a little bit more specific if you could, please.

Yes, it's typical grades we run out there.

It's SJB, KLM, some South American grades like [Quariente], Napo, Astia.

All those things actually kept -- had better pricing versus A&S.

Versus A&S is the key there, Mark.

A&s is out of the market, and all those other crudes seem to be in the market, so it really discounted?

Well, if you compare it to A&S, yes.

It depends on what your benchmark is.

Okay.

Just let me sneak one more.

Byproduct benefits in the ethanol side, in terms of the grains, seems like they're very substantial.

Can you help over and above what Gene had to say a few minutes ago?

Well, the (inaudible) grains, you get only about two-thirds of your corn is converted.

About one-third of it ends up as distiller's grain, and that has been a pretty strong market.

I don't have the exact numbers in front of me.

That's the primary byproduct in producing.

Okay, guys.

Thank you very much.

Thanks, Mark.

Our next question comes from Rakesh Advani from Credit Suisse.

Please go ahead.

Thanks.

A quick question on Meraux.

Have you guys ever put out what EBITDA contribution you think can come from that facility?

We have not yet, Rakesh.

We have not yet disclosed; it's historical financials.

So we closed October 1, so probably that's a question for the first quarter.

Okay.

And just for the two hydrocracker projects that are coming on stream next year, can you guys talk about how much disruption there will be to tie in the two projects into your existing facilities, which quarters it will take place in?

Okay.

The Port Arthur hydrocracker will be finished mid-year.

So we're saying third quarter would start up then third, fourth quarter.

And the St.

Charles hydrocracker will be finished by year end, would start up then occurring then and then in the first quarter.

Okay.

So then like how many days would we assume for the facility to go down or to tie them in?

Would it be, should we use fiscal like 30 days or something like that?

We will not go down to tie up time in.

Everything will be wherever we have tie-ins, valves are hung or things are hung, wherever there are tie-ins.

Now if you're asking how long is startup, these are huge projects.

So --

Anywhere for two weeks to one month probably.

Okay, two weeks to a month.

The base operations are generally going to be unaffected.

Right.

Okay, perfect, thank you.

Not like taking a big turnaround or something.

It will be incremental.

Okay.

Thank you.

Sure.

Our next question comes from Jacques Rousseau from RBC.

Please go ahead.

Good morning.

Good morning Jacques.

Just wanted to ask if I heard correctly the guidance for the Midwest volumes for the quarter.

I believe you said 4.30 to 4.40?

That is correct.

I was just curious, that looked like a high number.

Probably the highest quarter since you had since 2008.

I guess if you could give a little color on what's improved there.

There's still economic incentive to run.

But also the last couple of quarters have either had turnarounds or other unplanned outages, like Memphis had some issues in the third quarter.

It would probably would have been up in that level.

That was the original guidance range until Memphis had the acquired that affected crude (inaudible) I believe.

Otherwise it's what we would've expected.

Great, so outside of the maintenance you talked about, this is a normal run rate going forward?

That's correct.

Okay.

Thank you.

Our next question comes from Jeff Dietert from Simmons & Company.

Please go ahead.

Good morning.

Good morning, Jeff.

I was wondering, you mentioned startup at Pembroke and gave some contributions for the quarter.

Could you talk about operations there, if there's anything that surprised you, anything that you're doing differently than the way you perceived Chevron from operating the plant?

I think many majors focus on maximizing throughput as far as -- rather than maximizing profitability.

Any comparisons you can make there?

I think we will put our own spin into the plant.

We are profit-focused.

We're in this business to make money.

But as far as a statement of we run different than Chevron, for instance, Chevron's a very well-run company.

So I would tell you just, you're going to see our spin because we intend to make money.

Great.

Any discussion on exports?

I know when we look at the DOE statistics, both gasoline and diesel exports were a record in the most recent months.

You're continuing to see gasoline and diesel exports increase, what those volumes look like in 3Q?

And are there any constraints to your ability to export both products?

Well we see the export market continuing to be very strong.

And Ashley's going to give you some numbers here.

Yes, in third quarter, we were up a little for gasoline versus prior quarters up around 75,000 versus 80,000 barrels a day.

And on diesel side it was, again, up from the second quarter up to about 165,000 barrels a day of diesel exports.

The gas has been going where it has been going pretty much, south of the border to Mexico or other parts of Latin America.

The diesel's been going, split between Europe and Latin America.

Jeff, this is Jean.

Obviously those are Valero's numbers, the industry is 500,000 barrels a day of gasoline if you look at the DOE numbers.

Any restrictions in your ability to export more if the market demand is there?

No, I -- like I mentioned earlier, we're finding some synergies with Meraux and St.

Charles, which typically in the past did not export European grade.

But by putting those streams together, we're finding out we're going to make an [even 590] or European specs, so we're looking to see what we can do there.

Thanks, guys.

Sure.

Our next question comes from Paul Sankey from Deutsch Bank.

Please go ahead.

Good morning, all.

We put a note earlier this week showing how tight pad one markets are for distillate.

Can you talk a bit about that from your point of view, and I'm thinking Pembroke, I'm thinking Colonial, and I'm thinking any other potential you have for going after that market.

And the analysis we were running was before we had the snow.

So I assume you'd agree that the market looks extremely tight.

I think, Paul, we don't understand your question.

I think we missed a word that must have been missed in the sentence.

Should I say the whole thing again?

Yes.

Right.

We must have missed a word.

Okay.

Perfect.

Perfect question asking I should say.

Okay.

So let's start again.

Pad one markets we've analyzed this week, looked very tight, northeast distillate markets particularly.

And I wondered if you generally agreed with that, and to the extent they are tight and to the extent the weather has -- is likely to increase that tightness, I was wondering how, from your point of view, you can address that?

And I'm thinking about the Colonial pipeline; I'm thinking about Pembroke and any other access you have if you like to that particular area.

Okay.

Thanks.

What we missed was the pad one.

Yes, that was an important bit.

I apologize.

It's okay.

Yes, pad on is tight on this distillate, but if you look at continental Europe, it's also very tight.

So I think you're going to continue to see the exports from the Gulf Coast going to Europe.

And Pad one distillate inventories, yes, they're dipping well below the five-year average and well below last year.

It was the refinery that's been recently shut down there, I think that market's going to be tight, which is going to require fairly high utilization rates throughout the winter to supply that market.

So I think it's going to be a pretty strong market for distillates going forward.

And volume will be shipped in as well as going to Europe and to the East Coast.

Yes.

So you can ship it obviously from the Gulf to the East Coast, because I'm assuming that pipeline capacity is limited for moving it in the other way?

Yes, I am sure Colonial will go under pro rate.

Right.

So, they're not going to effect -- I guess it's likely to be higher distillate margins on the Gulf Coast, as well?

Yes.

The whole Atlantic basin market.

Like I said, with the Europe tight and East Coast tight, I think there's going to be a demand for Gulf Coast barrels to go to both these markets.

Great.

Thanks.

And -- on the buyback, are you setting 20 as a floor below which you buy back stock, or are you thinking that you're going to -- you mentioned that the stock is undervalued in your opinion.

Is it just being the 20 floor recently, and one you may think about raising if you like under which you'll buy stock?

I'm not really looking at it that way.

It's much more opportunistic, but we did buy 13.5 million shares below 20.

And we manage our cash.

So it's the whole balance.

Okay.

So we can hope for more buyback going forward regardless of the stock price being above 20?

Clearly we think our stock is undervalued.

Okay, Bill.

I get it.

Thanks, guys, sorry for the misunderstanding.

Thanks, Paul.

Our next question comes from Chi Chow from MacQuarie Capital.

Please go ahead.

Great, thanks I'm going to go back out to the West Coast.

That was a pretty good result on realized margins, given where the crack spread trended in the quarter.

Was the improvement really just on the differentials you talked about earlier?

Did you change-up the crude slate at all during the quarter?

And Mike, you also mentioned the liquid volume yield improvements.

Were there operational improvements that you undertook at the plants out there, as well?

Operations?

This is Lane.

Operationally, we just came out of the turnaround in Benicia.

Its performance in terms of liquid volumes are improved versus prior to the turnaround.

But crude selection is essentially unchanged.

We haven't really changed what we're running on the West Coast.

Same crude.

But we operated better.

Right.

Okay, thanks.

California recently finalized their cap and trade regs.

Have you had a chance to dig into those details?

And how are you thinking about managing that program going forward?

Well, you can rest assured we dug into it.

We have a very good strategic position on the West Coast.

We have very good operations.

However, we think state policy, AV32, other fiscal policies, regulations, continued to adversely affect the economy.

They adversely affect jobs.

They adversely affect the consumer.

We think all these policies seem to turn their back on the negative economic impacts.

We are hopeful that the voters, which consumers will eventually realize that these policies are economically ruining the state.

AB-32 was a 12-page bill.

CARB has now spent over $100 million trying to develop regulations in five years.

It is a go-along policy.

The people of California are going to pay.

And as to us, we're looking at our options.

So do I take that as meaning that the long-term viability is potentially in question on operating refineries in that state?

We're looking at our options.

Okay.

Got it.

Okay.

Great.

Thanks for that, Bill.

One other question on the Eagle Ford.

We've noticed recently that the markers that we track, the pricing on the Eagle Ford crude has changed dramatically in mid-October.

It's moved to pricing off of Brent versus previously off of WTI.

Have you seen this pricing dynamic sin the market, and if so, has that impacted your decisions on crude slate down there?

This is Gene.

I think if you look ad Eagle Ford where it's pricing red, if it's already on the water area where it could be delivered and compete with a foreign barrel, with prices there, I think in the fields it's still priced at a discount.

Not at Perry and WTI, but still much less than Brent.

It's going to depend -- I guess the marginal barrel that's on the water, of course it's probably going to price like Brent at this point.

But if you're in the field, or if you have a refinery in the fields, and you cut deals, then you've got different pricing.

And that's how things worked.

So you're talking about Three Rivers versus Corpus then, is that the difference?

Absolutely.

Got it.

Clearly, your observation is correct.

Take-away capacity is being built in the Eagle Ford.

The crude is able to -- more of it's moving to the market.

We have raised our postings in order to keep it in the area.

But it's still discounted relative to the other crudes, and so it's still -- we think Three Rivers and the volume we're going to run at Corpus are going to be very economic crudes for us.

And remember, we used to run all foreign crude at Three Rivers.

Right.

Okay.

Great.

Thanks a lot.

Our next question comes from Sam Margolin from Global Hunter.

Please go ahead.

Good morning, guys.

How are you?

I don't think you've ever done this before, but can you break out Memphis from the mid-con group or give just maybe an assumptions of what the mid-con realized margin was ex that Memphis portion?

We haven't, and we really don't plan to, Sam.

Okay.

Well, in that vein, on the last quarter's call, you gave some indication that you were thinking about maybe a big capital project at McKee, an expansion, or something on that order.

Is there any progress with that line of thought, or still on the evaluative?

Yes, Sam, we have a project we've engineered at McKee.

It's less than $100 million project, but it does let us run more oil.

It's a little bit over the same lines that Ashley talked about, the Eagle Ford crude, where the refinery's in the field.

We're seeing more and more crude discovered and available to the McKee refinery.

So we have a project that would let us do that, and right now, we're anticipating doing that project.

However, it takes 18 months to 24 months to get a permit.

We're just about to file our permit application, or have filed our permit application.

So depending on how long that takes, which is a year-and-a-half, and then some construction period after that.

But the McKee refinery sits right there in the panhandle.

We're seeing more crude, and this is just a little debottlenecking, as I said, it's less than $100 million project.

All right.

Sounds good.

That's it for me.

Thanks so much.

Okay.

Our next question comes from Evan Calio from Morgan Stanley.

Please go ahead.

Good morning, guys.

Great quarter.

I think you could extend the distillate tightness commentary into China, beyond pad one in Europe.

My question is, it's a followup on Aruba, and if other than strategic partnerships on heavy sour crude, is it possible you could find a cheaper fuel source instead of burning 14% of crude there?

Is floating re-gas, FSRU, is that anything you guys have explored?

Yes.

We are working a project in conjunction with the government of Aruba in order to bring in LNG.

And that project has been under -- we've been working on it for many months, and we're down into the -- where we are getting solicitations on supply right now.

The engineering is largely done.

And yes, it has a very favorable economics, both for our refinery, including reliability.

And it also is very favorable to the people of Aruba because of their power costs.

So exactly correct, and we are working that project.

Then on top of that, a little longer term, I believe it's Repsol is looking at -- is putting a well there because they believe they're going to find natural gas there, as well, in the water.

So there's many things changing actually all over the world on this E&P side.

That's great.

That's good news.

Another question if I could.

Just lastly, the line nine reversal was announced at Ambridge analysts meeting.

Do you expect down the road you could get a lift into Quebec, and how do you think about that?

Have any partnership to move crude into that market to benefit that refinery?

Yes, we're interested in the line nine reversal, and obviously so is Petro-Canada and others.

That takes the crude oil to Montreal.

Then you have to have some agreement to get it to Portland, but yes.

Depends on the differentials between WTI and Brent now in this case.

But yes.

We would think it would give us some advantage if we could get that crude.

Appreciate it, guys.

That's it for me.

Our next question comes from Blake Fernandez from Howard Weil.

Please go ahead.

Hi, guys.

Sorry to reprompt back in.

Bill, I know you covered the share repurchases, but one final question on it.

Is there a specific goal or a target for the number of shares you're hoping to retire?

No, there is not.

Okay.

Thanks a lot.

Our last question comes from Alan Good from Morningstar.

Please go ahead.

Good morning, guys.

I was wondering if I could get your current thoughts on your appetite for acquisitions, or should we take the dividend increase, share repurchases and willingness to hold a high cash balance as a signal that you're done with acquisitions right now?

Well, I thought I was addressing it.

But we're a refining Company.

We also have a marketing operation, ethanol business.

Some of the assets are available for numbers that are attractive.

So if it's strategic, if it's accretive, Valero is still interested or is going to look.

The last two acquisitions that we have done, we purchased for less than where Valero was trading.

So we think we can add value.

On the other hand, we're extremely selective, and I've said there's no intent whatsoever of issuing equity.

Is Europe still an area of interest, or is it just a broad geographic area that you're looking at?

Yes, Europe is still of interest.

We've been very public in the fact that we now have established a position there, at least in the UK.

We had said there's a refinery nearby that Valero would be interested in.

Otherwise, we're not working on anything in Europe.

Okay.

Thanks for that.

We have no further questions at this time.

Okay.

Thanks, John.

I just want to thank our investors for listening to today's call.

If you have any questions, contact me or Matt in the Investor Relations Department.

Thank you.

Thank you, ladies and gentlemen.

This concludes today's conference.

Thank you for participating.

You may now disconnect.