瓦萊羅能源 (VLO) 2011 Q4 法說會逐字稿

Welcome to the Valero Energy Corporation Reports Fourth Quarter and Annual 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 with me today are Bill Klesse, our Chairman and CEO; Mike Ciskowski, our CFO; Gene Edwards, our Chief Development Officer; Joe Gorder, Executive Vice President and President of European Operations; Kim Bowers, Executive Vice President and General Counsel; and Jean Bernier, Executive Vice President.

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

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

If you have any questions after reviewing these tables, please feel free to contact me after the call.

Before we get started, I would like to direct your attention to the forward-looking statement disclaimer contained in the press release.

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

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

Now I'll turn the call over to Mike.

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

As noted in the release, we reported fourth-quarter 2011 income from continuing operations of $45 million, or $0.08 per share.

This number includes an after-tax benefit of approximately $161 million, or $0.29 per share from a year-end LIFO inventory decrement.

Our fourth-quarter 2011 operating income was $167 million, versus operating income of $378 million in the fourth quarter of 2010.

Our fourth quarter refining throughput margin was $5.46 per barrel, which is a 25% decrease compared to the fourth quarter of 2010.

The decrease in throughput margins compared to the fourth quarter of 2010 was due to lower margins for gasoline and petrochemical feed stocks, plus reduced discounts for medium and heavy sour feed stocks such as Mars and Maya crude oils.

These declines were partially offset by higher margins for diesel.

In the fourth quarter of 2011, Gulf Coast gasoline margins per barrel versus LLS decreased 185%, to a negative $2.05 from a positive $2.42 in the fourth quarter of 2010.

Gulf Coast ULSD margins per barrel versus LLS increased 39%, from $9.88 in the fourth quarter of 2010, to $13.71 in the fourth quarter of 2011.

So far in the first quarter of 2012, Gulf Coast margins have moved higher, averaging over $5.50 per barrel for gasoline, and about $16 per barrel for ULSD.

The Maya-heavy sour crude oil discounts versus LLS decreased 44% from $12.75 in the fourth quarter of 2010 to $7.19 per barrel in the fourth quarter of 2011.

The Maya discount has narrowed some in the first quarter, with the average down to around $4.50 per barrel.

The WTI crude discount versus LLS increased over $13 per barrel, from $3.34 per barrel in the fourth quarter of 2010 to $16.70 per barrel in the fourth quarter of 2011, which helped improve throughput margins in our mid-continent region from the fourth quarter of 2010 to the fourth quarter of 2011.

Our fourth-quarter 2011 refinery throughput volume averaged 2.7 million barrels per day, up 523,000 barrels per day from the fourth quarter of 2010.

The increase in throughput volumes was mainly the addition of capacity from the acquisition of Pembroke and Meraux refineries, plus operating the Aruba refinery, which was not in operation during the fourth quarter of 2010.

Refining cash operating expenses in the fourth quarter of 2011 were $3.92 per barrel, which was higher than the third quarter of 2011, and our guidance, mainly due to costs of a legal settlement, plus higher regulatory and tax expense.

Our ethanol segment reported its best quarter on record, with $181 million of operating income, which was up $111 million from the fourth quarter of 2010, and up $74 million from the third quarter of 2011, mainly due to much higher gross margins.

For the full-year 2011, our ethanol segment reported operating income of $396 million, its best year ever.

In addition, since we bought the first plants in 2009 through the end of 2011, we estimate that in less than three years, our ethanol business has generated cumulative pre-tax cash flow exceeding the purchase price, and recovering our $750 million investment.

As good as the fourth quarter was for ethanol, I should point out though, that ethanol margins declined significantly in December, and have remained low so far in the first quarter.

Our retail segment reported fourth quarter operating income of $83 million, consisting of $48 million in the US and $35 million in Canada.

For the full-year 2011, our retail segment reported their most profitable year ever, with $381 million in operating income, which includes a record high from our Canadian retail, with $168 million in operating income.

In the fourth quarter, general and administrative expenses, excluding corporate depreciation, were $129 million, which was below third-quarter 2011 and our guidance, mainly due to favorable legal settlement.

Depreciation and amortization expense was $393 million, and net interest expense was $89 million.

The effective tax rate on continuing operations in the fourth quarter was 52%, which is higher than our guidance rate of 36%, due to the combination of year-end tax adjustments and low pre-tax income.

Regarding cash flows in the fourth quarter, capital spending was $899 million, which includes $128 million of turnaround and catalyst expenditures.

For the full-year 2011, Valero's total capital spending, including turnaround and catalyst expenditures, was $3 billion, or $200 million below the previous guidance of $3.2 billion.

Our expected capital spending for 2012 is consistent with previous guidance, at around $3.4 billion.

Also in the fourth quarter, we paid $84 million in dividends, and $79 million to purchase 3.5 million shares of our common stock.

We also spent $547 million to acquire the Meraux refinery and related logistics assets, which included approximately $219 million for inventory.

With respect to our balance sheet at the end of December, total debt was $7.7 billion, cash was $1 billion, and our debt to capitalization ratio, net of cash, was 29%.

At the end of the fourth quarter, we also had nearly $4.5 billion of additional liquidity available.

As to our refining operations, in the fourth quarter we completed the hydrogen plants at Memphis and McKee, which were two of our key economic projects.

Start-up is underway at Memphis, and we are planning to start up the McKee plant in February.

These projects are designed to take advantage of the large spread between natural gas and crude oil prices, which is very valuable, given that natural gas is only trading at 15% to 20% of the price of oil on an energy equivalent basis.

Our two hydrocracker projects at Port Arthur and St.

Charles remain on budget and on time for a completion in the second half of 2012.

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

And now I'll turn the call over to Ashley to cover the earnings model assumptions.

Thanks, Mike.

For modeling our first quarter operations, you should expect the refinery throughput volumes to fall within the following ranges -- the Gulf Coast at 1.38 million to 1.42 million barrels per day; the Mid-Continent at 390,000 to 400,000 barrels per day; the West Coast at 220,000 to 230,000 barrels per day; and the North Atlantic at 450,000 to 460,000 barrels per day.

The lower throughput volumes in our Gulf Coast and West Coast regions are due to substantial turnaround activities planned for this quarter, particularly at our St.

Charles and Wilmington refineries.

A listing of our planned turnaround activities was posted this morning to our website under the Newsroom.

Refining cash operating expenses in the first quarter are expected to be around $4.50 per barrel, which is higher than last quarter due mainly to lower throughput volumes and some higher maintenance costs related to the turnaround activity.

Regarding our ethanol operations in the first quarter, we expect total throughput volumes of 3.5 million gallons per day, and operating expenses should average approximately $0.34 per gallon, including $0.03 per gallon for non-cash costs such as depreciation and amortization.

With respect to some of the other items for the first quarter, we expect G&A expense, excluding depreciation, to be around $160 million; net interest expense should be around $85 million; total depreciation and amortization expense should be around $400 million; and our effective tax rate should be approximately 36%.

Okay John, that concludes our opening statements.

We will now open the call for questions.

Thank you.

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

(Operator Instructions)

Doug Terreson, ISI.

Good morning, guys.

Good morning, Doug.

Mike mentioned in his opening remarks that refining margins have improved versus Q4, and on this point I wanted to see if you could provide your view on product balances in the Atlantic basin over the immediate term.

Meaning, while demand has not been great and capacity growth was pretty significant during the second half of 2011, the next couple of quarters appear to be more promising, especially with the closures announced in recent months.

I just wanted to see if you'd provide your perspective on the demand and the supply sides of the equation for the basin in coming quarters, and also update us on the status of Aruba too?

Okay.

Well, Doug, this is Joe.

Hi, Joe.

I'll speak for a minute to the gasoline piece and then somebody else can speak to Aruba.

Obviously with what's happened in the marketplace from a supply perspective, things look encouraging.

You've got plant closures in the northeast US.

You've got the situation with Petroplus in Europe.

We have Hovensa making announcements, Isla still is running well.

From a supply perspective, products tend to be a bit tighter than they have been.

Sure.

If you look at US gasoline demand, of course, it's not particularly strong.

But the real story in gasoline continues to be the export markets where year-to-date through December, we exported 511,000 barrels of day of gasoline, which is up 175,000 from the previous year.

So that continues to look good.

Now, will it continue?

I think it probably will.

You've got Latin America growing and they continue to import.

Venezuela still has issues at their domestic refineries and then they're involved of course with Isla and Hovensa.

Mexico gasoline imports were up to 405,000 barrels a day, and Petrobras continues to pull gasoline.

If you look at the gasoline markets in general, I think that we're going to continue to see very strong demand, and our export business should continue to be strong.

On the distillate side again, you had average distillate markets here in the US, but their exports were also very strong.

The industry exported almost 850,000 barrels a day, so that continues and the same refinery issues that are affecting gasoline are out there for diesel also.

The Europe, which was closed a little bit earlier this year, is now open again and so we're seeing barrels move that way.

Our exports for the quarter were 65,000 barrels a day of gasoline and slightly over 180,000 barrels a day of diesel fuel, so that continues to be good for us.

I hope that answers your question.

That's a good answer, Joe, thanks.

Concerning Aruba, Doug, we continue to look at our strategic alternatives, but we're in the same boat as was announced by one of our competitors operating in the Caribbean.

So, we intend to have a decision here very shortly here within the first quarter.

Jeff Dietert, Simmons & Company.

Good morning.

Good morning, Jeff.

My question evolves around heavy sour discounts and Maya -- you talked about Maya premiums being -- or discounts being soft in the first quarter.

Lots of things influencing that, the K factor's moving around, resid inventories are low, which is propping up Maya pricing.

You've got Hovensa coming out of the market and eventually Seaway deliveries coming later in June.

Could you talk about your expectation for Maya and heavy sours as we look through 2012?

Jeff, I mean, this is Joe again.

I think you cited on so many of the facts that are going to affect this market.

Right now, the discounts are weak.

As you said, resid is very tight.

We also had the compression of the WTI Brent spread which WTS moves with.

As that came in, as did the relative prices of WTS, so 80% of the Maya formula was affected by those two components.

Then as you mentioned the K factor, we saw the Mexicans adjust the K by $1.90 a month the last two months and we expect them to continue to move that going forward.

Although the discounts are weak today I think our expectation is that we'll see discounts somewhere close to last year's levels or slightly below as the year moves on.

Thank you.

Secondly, you guys have been supporters of TransCanada's Keystone pipeline and that's experienced some government delays.

Are you free to pursue whatever options are best in moving Canadian crude down to the Gulf Coast?

Are you considering both TransCanada to Keystone in Enbridge or are you focused on one or the other more intently?

Jeff, we continue to be big supporters of Keystone.

We think it's a great project and we're committed to that pipeline.

That being said, we have a strong appetite for heavy sour crudes in the Gulf Coast, and we're watching the other projects as they develop.

Obviously, we've got Enbridge and Enterprise that have one project in place.

We've got an open season now on another pipeline that would parallel the Seaway project.

It runs from Flanagan south to Cushing and then on down to the Gulf Coast.

We support all of these projects that would bring additional crudes into the Gulf.

Thanks for your comments, Joe.

You bet.

Ed Westlake, Credit Suisse.

Hi, yes, good morning everyone.

I guess on the call signaling higher payouts of and rising free cash flow.

Maybe just give some color about your thoughts about shareholder distributions?

And then I have a follow-up.

Thank you.

We increased our dividend last year, and we bought shares in the fourth quarter.

There's a few shares that carried over into the first quarter that we purchased because of settlement date.

But clearly we'll look at increasing our dividend, buying some of our shares as we complete our projects.

Now, first we're going to maintain our investment grade rating.

Then we have the Port Arthur hydro cracker should be done at the end of the second quarter, starting up in the third.

And then the fourth quarter, we finish the one in St.

Charles.

So as these projects are getting completed, we'll look at how we manage our cash.

The other thing that we have said when we've spoken to you all, as we look into 2013 we expect our capital spending to fall from our $3.4 billion where we are today for 2012, down into $2.5 billion to low $2 billion for next year.

Very helpful.

Just a follow-on, separate area.

You're actually making money in the north Atlantic, even as everyone else closes around you.

Given that you are able to make money from the assets that you've chosen to invest in, are you tempted to add more to the European refining portfolio, if you can find a similar advantaged asset as Pembroke?

We have a very good base in the UK in Ireland.

With all the noise that's going on with some of the refineries that are available, yes, we would take a look at things.

We say that about everything anyhow.

But if you actually look at it, we want a very strong, strategic fit.

It needs to be compatible in the sense of moving streams between refineries.

It needs to bring marketing or at least support our trading in the Atlantic basin, and then the exports that Joe spoke about.

So, it has to have strategic or synergy value to us in fitting into an overall system.

But obviously we read the news and we see what's going on as well.

We have a good base there that we didn't have prior to our acquisition of Chevron's business.

And my interpretation of good base -- is this correct -- is that you could just stick with your current assets and therefore the bar for any further acquisitions would have to be that much higher?

That would be absolutely right.

Doug Leggate, Bank of America.

Thank you.

Good morning, everybody.

Good morning.

Going to try a couple of questions also, if I may.

The first one, Bill, when you talk about your strategic options for Aruba and obviously you've brought in Europe to the discussion as well, can I ask you to bring us up-to-date with your thoughts on the West Coast, particularly as it was to the free cash flow in the West Coast, as opposed to the earnings.

Specifically if you have continued requirements for regulatory spending, does that remain a core area in the perhaps redesigned portfolio as you move forward?

And I have a follow-up, please.

As of today, the West Coast is a very key part of our business.

So, you used the word core; it is a core asset for us.

We have a good position there.

We have very good operations.

We have had to spend a lot of money at our Benecia refinery here for environmental.

That is true.

But the thing that you cannot forget on the West Coast is they're still in a recession or a depression.

They have unemployment headline number of 11%, little over that, which means under-employment is probably twice that.

[CAR] is absolutely out of control.

They do not work for the common good, and they're hurting the economy in the West Coast.

But for us now, we continue to work on our cost structure.

We're attacking that.

The refinery operations are reducing costs in that business, and we're in a competitive position.

I mean, we're well-positioned there.

But the macro is the problem, and it needs to be solved.

Thanks, Bill.

My follow-up is really more of a micro question on gasoline.

We see how strong distillate cracks are, gasoline less so.

You announced your turnaround program, which if I'm not mistaken, looks like it's relatively heavy by historical standards.

Could you maybe characterize, how do you see the outlook for cleaning up gasoline inventories, the overhang that we have right now?

And perhaps if you have a view as to how industry maintenance could perhaps help that over the next couple months, that would be great.

I'll leave it there.

Thanks.

Well, for us, these turnarounds have been scheduled.

The one in St.

Charles that Ashley said, we put our turnaround schedule on the web page, but these have been scheduled turnarounds.

So St.

Charles will be down for 66 days.

In April, McKee goes down to do work on the [CAT] cracker, which will reduce gasoline production up in the Texas Panhandle.

So ours have been scheduled.

Now, there's no question that gasoline is sloppy, although quite frankly the cracks have improved significantly here just in the last couple of weeks.

But part of the issue, again, is in North America and in Europe we have growing but -- at least in North America -- growing but very slow economy.

Europe, Western Europe, I don't know if they're technically in recession today or not, but you combine the uncertainty we have economically, we do have higher prices.

We have in the US this housing overhang.

And remember, we sell fuels to everybody.

There's a large segment of our customer base who either is unemployed or facing economic uncertainty.

So to me, we have to have people getting back to work and economic activity picking up and we'll see demand recover.

I think we'll see higher demand this year than we had last year.

The turnarounds, when we're down, obviously reduce production, just as all the shutdowns that have been announced are doing.

But I'm optimistic that gasoline's going to be fine this year, but we do need to get people back to work.

Distillates is still doing just fine, and as Joe said, the [yard is] open again in Europe.

Economies around us are growing, and from our US Gulf Coast business, we'll continue to export.

Thanks, Bill.

I'll leave it there.

Paul Cheng, Barclays Capital.

Good morning, guys.

Mike, can I ask some balance sheet data?

In terms of working capital, the long-term debt out of the total debt component and the inventory market value in excess of LIFO?

Sure, Paul.

On our total current assets at the end of the year was at $16 billion.

Total current liabilities was $12.7 billion, so our net working capital was $3.3 billion.

Our market value in excess of LIFO was about $6.8 billion.

Total debt is at the end of the year was $7.7 billion.

And our stockholders' equity was $16.4 billion

Mike, out of the $7.7 billion in total debt, how much is long-term debt?

Pretty much almost all of that is long-term debt.

We did have $250 million that was under our AR program.

Included in those numbers is about $45 million of capitalized leases.

Okay, perfect.

Bill or maybe both Bill and Mike, you're talking about raising the dividend, and maybe doing a bit of the share buy-back and returning cash.

With next year your budget is at $2 billion, $2.5 billion, and that locking on with that, there's generally a pretty substantial sum of free cash with your DD&A already in the $1.7 billion, $1.8 billion.

How are you looking at that?

Historically I think in a rising cash flow environment, that you tend to spend more as a percentage into share buy-back than dividend.

Going forward, that, how you look at yet with a recent Barron article talking about the 4% yield, which for you guys at current share price is about $1 per share.

Do you think the volatility in your business is still way to high, therefore you're trying to search for that kind of a yield?

Well, I've said that once we get through this spending that we're doing, which we think are very good projects.

So, you're asking me how do I look at this?

We have said that we want to pay one of the highest dividends among our peer group and that is what we're going to do.

And then when I try to match it up between dividend and stock buy-back, if we don't have better projects that add shareholder value, then we're going to have our dividend that's high or one of the highest of our peer group, and then we'll use the rest of our cash to maintain our investment grade ratings.

So we may buy back some of our debt, or redeem it, and at the same time retire some of our shares.

Bill, do you have a target ratio between -- in terms of the cash returned to shareholders -- say 40/60 between dividend and share buy-back, 30/70, or any kind of target?

No, I do not.

But I will go ahead and add, we as a Company do not see benefits of special dividends.

So we would tend to act in a more regular manner in the sense of what I just said, paying a dividend that's one of the highest of our peer group and at the same time then, buying our shares.

That's great.

Bill, in the past you have said you've been in discussion with Murphy on Milford Haven.

Can you update us whether you are still in discussion on that?

And also that you have laid out some of the criteria when you're looking at all that.

Wondering whether BP Texas City would fit into your criteria, in general.

Okay.

So there's always confidentiality agreements associated when we look at things, but I have said our Pembroke refinery is right across the haven from Milford, Milford Haven.

We -- and I have also said there would be some advantages.

However, we are not talking to Murphy.

You're not talking to Murphy now?

That's correct.

Okay.

Then as far as Texas City, we have said in the past we've looked at that, but there's confidentiality agreements and nothing seems to be happening.

I see.

Thank you.

Thanks, Paul.

Blake Fernandez, Howard Weil.

Guys, good morning.

Couple questions for you.

One, as I understand it, the results in the quarter were negatively impacted from your long-haul crude purchases that were kind of tied to the WTI Brent spread which compressed.

I'm just curious if there's any way to one, quantify that and then secondly, is there any discussions of maybe changing the way that you structure the purchasing going forward?

Okay.

Yes, Blake, we have estimated what that impact we believe was in the fourth quarter, and the number is about $200 million.

Okay.

And as far as how you -- we have an estimate of the number of barrels that we had WTI exposure on.

We have been transitioning away from purchasing some of our crudes and hedging away from WTI and reducing that exposure.

Joe, do you want to--?

No, you're exactly right.

During the quarter, we looked at the market.

We saw the spread had blown out to where it was, and we didn't think it was sustainable.

It was affected by Libyan oil being out of the market and then coming back in.

Then the announcement of the Seaway reversal, of course, had a significant effect on it also.

So, we anticipated that it would come back in, and so we started shifting as Mike said to different bases for our hedging and acquisitions.

Okay.

But it's fair to think that is not really going to be prevalent in the first quarter?

Right.

Okay.

Then secondly, Joe, I know you already pretty much covered the export dynamics, but if you don't mind, as I understand it Valero is increasing their export capacity this year, and I was just curious if you could give us some timing of when that occurs?

Is there really incremental demand as it stands right now to actually increase the amount of exports from your system?

That's a good question, Blake.

We're working on multiple things that are going to facilitate our ability to export more effectively in the future.

Some logistics projects, but the two hydro cracker projects will be a big plus for that.

We will be able to produce diesel fuels that are of a high quality, that will allow us to move them anywhere.

The European spec is a more stringent spec than just the generic grade, and so we'll be able to move more barrels that direction.

Then it all goes to demand.

I'm telling you, we're going to have the ability to export, then it goes to demand.

With what we're seeing in our industry now with refinery closures and shutdowns and reduced run rates, I think we're going to see strong demand.

Plus you have growth in these markets, as Bill said earlier.

You've got growth in South America, Latin America.

You have growth in Mexico, and so in addition to supply being constrained, you're going to have higher demand, and we're going to be the beneficiaries of that.

We always forget how efficient the Gulf Coast refining system is globally, but it is very efficient, and I think we can compete with anybody.

Okay.

That's great.

I'll leave it there.

Thank you.

Sam Margolin, Global Hunter Securities.

Good morning.

I have a question, it's somewhat related to the WTI linked long-haul barrels.

It's regarding the buy/sell contract mechanics in the Gulf Coast, which presumably also had an impact in 4Q.

Are there any initiatives under way, or talks with producers here domestically in the Gulf about using a different kind of contract in that mechanism during the delivery leg?

I guess we would rather not tell you.

Okay.

It's a fair question, but we would rather not tell you specifically what we're doing relative to our crude acquisitions.

I mean, I think we had a pretty good feel for the market.

We made some good decisions and I would rather just kind of stop there.

But I will add, so you have some feel for it, that what you typically are doing is locking in the differentials.

You can do that with WTI.

You can do that with Brent.

You can do it with a lot of things.

How we manage that really becomes a Company's internal decision, and that's why Joe is saying, to us it's doing our business every day and it is a competitive world.

But it's really locking in the diffs, and obviously we had some diffs locked in on Brent, right, or we would have lost more money.

Okay.

Well, here's one that should be less controversial.

On the retail numbers, the same-store sales were flat year-over-year.

That stands in pretty stark contrast to the DOE demand figures.

It looks like there's some kind of error in that data set, just based on the massiveness of the drop-off.

Your retail numbers, is that reflective of a broader picture of better-than-expected demand, or is that just your location and exposure, and Company-specific?

This is Jean Bernier.

No, you are right, our fourth-quarter volume when compared to the same quarter last year was better in the fourth quarter than our year-to-date trends.

Overall, we're up about 1.5% in the fourth quarter, versus a drop of 0.5% year-to-date.

On a same-store basis we have a similar trend.

We did better in the fourth quarter compared to last year, and some regions did better, and Texas in particular was a good market for us.

Okay.

Yes, it's just noteworthy because the weekly DOE numbers have been -- were putting actually a strain on the exchange-traded commodity prices for most of the fourth quarter, and this rebound might reflect some changes in the understanding of that demand picture, so I was just curious if it was a national thing?

Sam, you just have to remember where our stores are located.

They tend to be in the Southwest, with most of them in Texas.

Texas has a good economy.

And then in Canada.

Same thing in our Canadian.

Yes, the Canadian volumes are a bit softer when you look at the overall volumes.

But that is mainly from our heating and carte blanche segments.

If you look at our retail gasoline we were about flat to last year.

Okay.

Thanks very much, guys.

Paul Sankey, Deutsche Bank.

Hi, good morning everyone.

There's quite a significant union issue, today I believe is the deadline, Bill.

Can you talk a little about any potential impacts that we may have, what you expect to happen, what's happened in the past, and also if you could widen that out from a not only a Valero impact, potentially, but also to a wider industry impact, I'd be grateful, thanks?

Paul, I'll first speak to Valero.

We had two refineries that have agreements that terminate tonight, and we continue to negotiate, and I have the expectation that we will have an agreement.

At Port Arthur, we have actually five agreements, and we've tentatively reached agreement on four, so really there's just one agreement.

Now, we were served with notice that they -- I guess it's a notice that says they can strike or will strike if we don't have an agreement here at Port Arthur.

At Port Arthur, we intend to operate if that's the case.

Now, as to other companies in the industry, I don't -- some companies were served.

We've heard there were two companies that were notified that they could have a strike.

Remember, we're part of the pattern.

Valero is a member of this group that negotiates.

Shell has the lead, and is negotiating the pattern.

So we'll see what happens today.

But we expect that we're going to have an agreement, so we'll see what happens.

Thanks, Bill.

I think Memphis is the other affected refinery for you guys?

Memphis for us is -- agreement does expire tonight.

At Memphis, we have negotiated with the union an orderly shutdown, and so if they decided to strike, we will shut down at Memphis.

But on balance you expect an agreement?

Yes, we expect an agreement.

That's great.

Thank you, that's very helpful.

We're a great Company to work for.

Yes, I knew that, Bill.

I knew that, but worth repeating.

Yes, maybe there's a job for you here.

Yes, I might need one if Wall Street keeps going the way it's going.

(laughter) The other question I had was on ethanol.

There's been a significant change between Q4 and Q1 in Washington.

I wondered if you could just -- I know you had a record quarter.

I believe things are pretty poor right now, and if you could just talk to the way ethanol has shifted, and whether we're now in a secular change actually, because of what happened in Washington on the credits and stuff.

Thanks.

Paul, this is Gene.

Our margins in the fourth quarter averaged about $0.56 a gallon on EBITDA basis, which is the strongest quarter we ever had, obviously.

The year averaged about $0.35 a gallon.

Since then, the margins have come off.

Right now in January we're somewhere between break-even to $0.05 a gallon, pretty weak.

Remember last year at this time we were pretty weak as well.

I think what, to let you know what's happening, we lost the blenders credit, but I don't think that itself has had much to do with the margins, because ethanol today is about $0.60 a gallon under gasoline on the east coast.

So it's still a big margin for blenders to blend, regardless of whether there's credits there or not.

I think more what's going on is just the supply/demand.

Demand in kind of the fall was around 850,000 barrels a day, plus we were exporting 100,000, 120,000 barrels a day.

So, you add those together, you needed the supply, and supply ramped up from 900,000 barrels a day to about 950,000, so it was a very tight market.

What's happened in December, January, just a seasonal reduction in gasoline demand has reduced ethanol blending down to around 750,000, 760,000 barrels a day.

Everybody was still running this 940,000 barrels a day, so we've been building inventories.

The exports haven't been enough to consume all that with the seasonal drop-off in demand.

Going forward, I think what's going to happen, these poor margins we're seeing -- remember, these that are even in our plants located in the corn belt.

Plants that are outside the corn belt are negative cash flow right now, so we'll see production fall off.

At the same time, remember, the mandate this year is 860,000 barrels a day, so we're blending below the mandate.

People are probably using credits right now to blend, to solve the difference.

But at some point in the near term, we're going to have to see ethanol blending move higher, until it averages 860,000 barrels a day for the year.

You factor in exports which have been strong into Brazil, Canada, Europe, I think they're going to stay in this 100,000, 120,000 barrels a day range.

I think the markets are going to tighten back up.

We're just going through a soft period right now.

Understood, that's a great answer.

Thanks, guys.

I see the time's okay now, so I'm going to throw in a third.

It might be a little bit of a question I should know the answer to.

I believe that Gulf margins right now are pretty much an all-time record for January, and we've talked about weak gasoline demand.

Obviously we know the export story.

Could you just make any observations you've got on just what's driving that strength?

It does seem very impressive.

Thanks.

One thing, this is Gene again.

One thing we're seeing on gasoline, the exports have gone up over 600,000 barrels a day.

Joe mentioned the numbers earlier, 500,000, that was for the year.

Just on a weekly basis, the numbers continue to look quite good.

We talked about Hovensa shutting down and the Petroplus issues, and some of the east coast refineries shutting down.

I think all those things just kind of are tightening up the projections for a stronger spring.

Great.

And if--

And let me add, we don't see the issue, per se on supply, in the sense that supply is in reasonably good balance for this time of year.

It's been a demand conversation, and we're like a lot of people, we see the economy starting to recover.

We think that demand will be better as we get into the summer.

As Gene said, when you think about how the supply side has been affected here, that actually we see good margins as we go into summer.

Great, and then just to finalize on that.

Is there anything strange or unusual about the capture that you're achieving of the current margins?

Is there anything we should be aware of as we work through Q1?

That will be it from me.

Thank you.

I would say no.

Our answer is no, there should be nothing that's acute or aware.

Thank you.

Evan Calio, Morgan Stanley.

Good morning.

Good morning, Evan.

Follow up on the Atlantic basin.

I see the clear benefits on supply for from Atlantic basin tightness and closures.

Yet where do you see the volume limitations on colonial product into the east coast?

Do you see a potential to move more product out of the Gulf Coast into the east coast?

Clearly, you'd think our bob would be a lot tighter this summer into that market, ex Hovensa and the two assets that shuttered in November?

Right.

On Colonial, we'll see it prorated, right?

It's going to stay full all the time.

A lot of barrels are moving out of the Gulf to Florida.

They can also move around to the east coast.

It always becomes, from our perspective, an arbitrage opportunity.

Where can you supply the east coast demand that we have most efficiently.

Is it out of the Gulf or is it out of Quebec, or is it out of Pembroke?

That's the way we would view this.

But as far as the Atlantic basin goes, I mean, there's just volume coming off from a refining perspective, as we've talked about now, everywhere.

It's making it a much more attractive market for the refiner that can move effectively.

We look at our supply opportunities, they're significant.

The issue, in trying to determine the ultimate net-back that you're looking at comes down to shipping often times.

Foreign-flag vessels moving from Quebec and from Pembroke into New York harbor are advantaged.

Right.

What's the kind of barge arbitrage out of the Gulf Coast?

Is that the widest of those three, obviously Pembroke and Montreal being easier?

I'm sorry, I'm not sure what you're asking.

I mean, is that the -- does the arbitrage have to be the widest in order to justify barging product from the Gulf Coast into -- out, around Florida to the east coast or is that --?

No, not always.

It comes down to just being sure that you're efficient in the supply, and there are factors within the refinery that will affect your decision to move one way or the other.

Okay, in addition to the margin.

But generally we're trying to optimize the margin.

I have a follow-up question, it relates to differentials.

First, with Maya, I guess we're constructive on that spread.

What is your ability, or what's the spread that incensed Valero to (technical difficulty) away from Maya and into LLS, as LLS is trading under Brent.

You have a lot of issues.

There's a lot of different differentials there.

Curious what that price was, or if you were incented in the 4Q to shift away from Maya runs.

Then conversely, to the West Coast, where crudes are relatively bid into Asian refining startup capacity, kind of the converse of the Atlantic basin, are you seeing most crude options pricing in the same direction of ANS, which is a tricky marker to follow?

This is Gene, let me turn to the Gulf Coast first.

I think what we're seeing with Maya prices where they are today, we're more advantaged running medium-sour crude, as opposed to Maya, so we're shifting some there.

Also, the LLS is cheaper, much cheaper than foreign sweets, so we're.

some of our refineries like Houston can run sweet like (inaudible) our crude site, a little bit there.

I think the Maya will widen back out.

If there is competition, it's more Venezuelan crude coming on.

There's still lots of barrels come out of Columbia.

I think you'll reach more of a equilibrium, so we don't want to just completely go off Maya and heavy crudes.

Short-term, we do have the ability to flex a little bit.

As far as the West Coast, Joe, do you --?

Well, I don't think that ANS is behaving any differently than the other crudes out there.

Okay.

So it's reasonably indicative of kind of what you would be realizing?

Yes.

Really you go to -- the only crude that's out of step with the rest of the market is WTI.

LLS, frankly now, we're starting to see it move away from Brent, and you'll see that number.

I guess LLS is $1.62 below dated Brent today, which is a change from where it was last year.

It's weakening, and it's weakening because you're seeing more sweet barrels push in to the Gulf Coast.

It goes to the thesis that I think Bill and Gene have shared with you guys in the past that ultimately, domestic sweet crude pushing to the Gulf Coast is going to put pressure on LLS margin.

It will put pressure on foreign sweet pricing, and ultimately you could see foreign sweet crudes completely backed out of the market, which is going to be a benefit to the Gulf Coast refiners.

I mean, we run sweet crude at Moreau.

We run sweet crude in Houston, as Gene said.

If you back the foreign sweets out of the Gulf, you're going to benefit Pembroke and Quebec also, as those prices come down.

That's a -- that's probably a four- or five-year conversation, but we would say in the US Gulf Coast, on what we see on the production and the capability to move the oil to the Gulf Coast, that the industry may push out all the sweet crude imports into the Gulf Coast, not the east coast.

But would you think that would change your diet of Maya, I guess is what I'm saying?

Especially if Maya was supported on resid tightness?

Well, I think Gene told you today we're better off running medium sours in some of our plants than the heavy sours.

Right.

So what that tells you is into a -- you're not going to build new coking today, and into a sunk coker there's not probably a lot of fun.

If I could slip in one last one if I could.

I know you mentioned you're supporting other various pipelines.

Are you seeking nominations on COA to commit to a potentially advantaged crude source?

I think on that one, we probably -- we will decline to answer, except go back to what Joe said earlier.

We want the heavy crudes in the Gulf Coast, and so we're very public on Keystone, but he also said that we're in a way talking to all of these companies.

Got it.

Appreciate it, guys.

Mark Gilman, Benchmark Company.

Hi, guys.

Good morning.

Couple quick ones if I could.

Aruba, cash positive in the fourth quarter?

Absolutely no.

Was that a negative.

I'm sorry, didn't catch it.

Yes.

No, we're not cash positive.

We're not.

Okay.

Could you update us a little bit on the Eagle Ford crude takes at Corpus and Three Rivers in the fourth and -- fourth quarter and where you expect to be in the first.

Yes Mark, this is Joe.

We ran about 60 in the quarter.

We're running 80 today.

We expect by the end of the second quarter to be running 100.

Joe, how does that split out between the two plants?

The bulk of it, certainly in the fourth quarter, I would tell you 55 to 60 went to Three Rivers.

I think we're going to -- and I don't have it specifically, Mark, but I think we're going to be running 30 of the 80 in Corpus today, and then about that same range in the first quarter.

Okay.

The 100 that you mentioned, that end of first quarter or second?

End of -- it will be during the second quarter.

Okay.

Any specific plans in place for diesel yield enhancement at Pembroke?

Mark, this is Lane.

We're currently looking at different ways to re-optimize their [FCC] Catalyst and trying to get to a more distillate-selective sort of riser conditions with Catalyst, and obviously we're looking at their distillations, to make sure the right molecules are in the right place.

We don't have a project, per se, right now lined up to increase their diesel production, though.

Okay.

I'm a little bit confused as to what Mike's $200 million number represented in discussing the long-haul crudes.

Is that pre-tax, after tax?

Does that encompass what I believe would have been a very negative crude roll impact in the mid-con?

And if you could identify roughly what that might have been in the fourth quarter, I'd appreciate it?

Okay.

What that does represent, it's a pre-tax number.

The volumes, I don't think I can disclose due to --

It's a pre-tax number, and it is -- the question was that we answered on the long-haul crudes, which basically are the crudes that we had exposed to WTI as we set our differentials and lock those crudes in.

That is 200.

Okay.

Now, the other piece if you're asking is yes, this negatively impacted our performance when it went from $25 to $10 at McKee and Ardmore, for sure.

We still made money at those refineries, but now we have a $10 diff instead of a $25 diff.

So with the volumes we run at those plants, the difference between in a way $25 down to $10 is about another $200 million.

But we were still profitable at those refineries.

Obviously there's a $10 advantage.

Okay.

That $200 million, Bill, that you just mentioned, that's also a pre-tax number, I assume.

Yes, we're giving you everything in like an operating profit.

Yes.

Okay, one more real quick one because I've got to jump.

The decision to participate in both cellulosic ethanol as well as biodiesel, sounds to me as if you're willing to put a reasonable amount of money on the table here?

I can answer you, Mark.

We think that in the United States we are going to have the continuation of the mandates, to use it.

So we have this renewable volume obligation, and when you look at it, it is a large number for us.

Even though we manage these in the sense of profit centers, when you look at the overall Company, we want to control some of our destiny.

Now, even if we have a new Congress or whatever, we still think those mandates are going to continue.

So the answer is last year for rens for we spent how much?

100 and --?

55.

$155 million for rens.

Does that include the diesel rens?

Yes.

So that's our total.

We spent $155 million buying rens Our estimate for this year is nearly twice that for rens, when you count diesel and cellulosic and regular.

So, yes, your answer is right.

We think it's part of the fuel mix, and we have a good project on biodiesel or renewable diesel.

We have a good partner, so we're going to run that like a refining project.

The Ken Ross project that's been announced with Wood we think is a good opportunity to get our toe in.

Thanks, Bill.

That helps a lot.

Chi Chow, Macquarie Research.

Great, thank you.

Back on the crude hedging loss in the fourth quarter.

I'm assuming that you had also a pretty sizable hedging gain then in the first quarter through the third quarter of last year.

Could you -- Mike, could you quantify what those gains might have been?

Your question is because we're -- I'm asking you -- because we're buying crude that we set the differentials against WTI, then we benefited just like every other mid-continent refiner on that.

Is that your question?

Yes, I'm assuming that you used NYMEX TI contracts to hedge long haul.

When the spread blew out from $3 to $28 in the first three quarters, I'm assuming there was a hedging gain in the first three quarters, then?

All right, so there was.

We're going to answer you for the long-haul barrels.

Okay, Mike?

Yes, that should be -- that number's estimated to be a little bit over $700 million benefit.

Do you have that broken out by quarter?

I do.

It's roughly about $250 million in the first quarter, $210 million second, $250 million third.

Okay, great.

On all these contracts, is there a particular region that's hitting?

Is it all in the Gulf Coast, or is it spread out between West Coast and Gulf.

Our volume is so skewed to the Gulf, that's where you're going to have the biggest effect.

Okay.

Great, thanks.

Mike, in 2012 here, your debt maturities, do you just have the one, the 6.875% notes coming due?

Well, that's correct.

We have $750 million that comes due in April, and then if you look at our balance sheet when you see it, it will show 250 of current maturities associated with our AR program.

But that renews annually, and we anticipate renewing that.

Right.

Okay.

Then in the fourth quarter did you have a -- what sort of working capital impact did you have flowing through cash flow?

Actually, we had about -- it was about a $700 million requirement, cash requirement associated with working capital.

So when you -- what makes that up is our receivables payables net increase, that was about a little over $300 million.

We had an increase in our income tax receivable of about $200 million.

Then we also had some pre-payments on crude.

It's more of a timing deal from January to December, and that was another roughly $200 million.

Okay.

These items reverse out here in the first quarter?

I'm not exactly sure the timing on the income tax receivable.

On the payables, the receivables/payables net, I'm not -- that should reverse over time, yes.

Okay.

Great.

Thank you.

Cory Garcia, Raymond James.

Good morning, fellows.

One quick question out of me, sort of switching up the export angle a bit.

Are you guys sending any gasoline or diesel off the California coast, and maybe quickly your views on the West Coast export trend.

We are not and my views on the export trend, have you got a view out of West Coast?

Well, we think that there's eventually could be an opportunity there.

We need to have that capability, that's one reason we're working our cost structure so that we can compete, and that would be into the West Coast of South America.

Might have a freight advantage of not going through the Panama Canal.

Also, there's action going on in refining capacity in Hawaii, as you know.

We haven't done anything as of yet, but we're looking at this type of optionality, because we believe a key part for all refiners in the United States is having the ability to export.

All right, makes sense.

Thank you.

Harry Mateer, Barclays Capital.

Just a quick one.

Given the rate of spending this year, you do have a $750 million maturity coming up in April.

Can you just tell us what your plans are with respect to that?

As of right now, we will go ahead and redeem that, but we're actually looking at how our cash flow goes for the next month or two from operations, and our projects look like they're on budget and on time, and so we'll make a decision here in February, latter part of February, on how we're going to address that, whether we're just going to redeem it or whether we'll need to issue something.

Okay.

Thanks very much.

That's a Board item for us, so we'll go back to our Board, and explain to our Board how we're going to do it.

Great.

Thank you.

We have no further questions at this time.

Okay.

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Thank you, ladies and gentlemen, this concludes today's conference.

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