瓦萊羅能源 (VLO) 2013 Q1 法說會逐字稿

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

My 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 would like to turn the call over to Mr. Ashley Smith.

Mr. Smith, you may begin.

Thank you, John.

Good morning.

Welcome to our first quarter conference call.

With me today are Bill Klesse, our Chairman and CEO, Mike Ciskowski, our CFO, Joe Gorder, our President and COO, Gene Edwards, our Chief Development Officer, Kim Bowers, Chairman and CEO of CST Brands, Clay Killinger, CFO of CST Brands, and several other members of Valero's senior management team.

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

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

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

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

In summary, it says that statements in the press release and on this conference call that state the Company's or management's expectations or predictions of the future are forward-looking statement and tended 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 describe in our filings with the SEC.

As noted in the release, we reported first-quarter 2013 earnings of $654 million or $1.18 per share.

First quarter operating income was $1.1 billion versus operating loss of $244 million in the first quarter of 2012, or adjusted operating income of $367 million, excluding a $611 million non-cash asset impairment loss taken in the first quarter of 2012.

The increase was mainly due to higher refining margins in the US Gulf Coast, US Mid-Continent, and North Atlantic regions, plus lower refining operating expenses.

Our first quarter refining throughput margin of $10.59 per barrel increased about $3.00 versus the first-quarter 2012 margin of $7.71 per barrel.

The increase in refining throughput margin was partly driven by higher diesel and jet fuel margins in all regions.

For example, the ultra low sulfur diesel margin versus Brent crude oil increased by $2.73 per barrel in the US Gulf Coast from the first quarter of 2012 to the first quarter of 2013.

In addition, the refining throughput margin was favorably impacted by wider discounts on some crude oil and feedstocks and the operation of our new hydrocracker at the Port Arthur refinery.

Our first quarter 2013 refining throughput volume averaged 2.57 million barrels per day for an increase of 11,000 barrels per day from the first quarter of 2012.

Both quarters had significant turnaround maintenance and repair activity.

Refining cash operating expenses in the first quarter of 2013 were $3.79 per barrel, which was below first quarter of 2012, due mainly to lower reliability expenses and lower operating costs at the Aruba refinery which was shut down in the first quarter of 2012.

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

The new hydrocracker at Port Arthur contributed meaningfully in the first quarter but experienced some issues that limited the throughput and conversion rate in late February and early March.

Those issues were addressed and the unit has been running near planned rates since mid-March.

In the first quarter, we estimate the new hydrocracker at Port Arthur contributed approximately $94 million of EBITDA.

We estimate the unit would have earned an additional $22 million of EBITDA, or $116 million in total EBITDA, had the operating issues not occurred.

Assuming market prices in the first quarter of 2013 were similar to full-year 2012 prices, and that volumes were at planned rates of 57,000 barrels per day, we estimate the new hydrocracker would have generated approximately $127 million of EBITDA, which is consistent with our previously disclosed earnings potential of that unit.

We are continuing to work on the new hydrocracker at our St.

Charles refinery.

We expect to complete that unit and begin the startup process at the end of June.

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

Also, at the St.

Charles refinery, start up of the Diamond Green Diesel project is planned for the end of June.

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

The renewable diesel will qualify as a biomass-based biodiesel, which is a difficult specification to achieve under the federal Renewable Fuel Standard.

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

My last point on our refinery operations is that in April, our Quebec refinery processed its first cargo of Eagle Ford crude oil which we shipped from Texas on a cost-advantaged foreign flag ship.

Preliminary results indicate that the crude oil worked very well in our refinery.

Our retail segment reported first quarter 2013 operating income of $42 million, an increase of $2 million versus the first quarter of 2012.

US retail operating income increased from $11 million in the first quarter of 2012 to $18 million in the first quarter of 2013, while Canadian retail decreased from $29 million in the first quarter of 2012 to $24 million in the first quarter of 2013.

Our plan to spin off our retail business and unlock value for our shareholders is progressing well.

Valero has received its requested private letter ruling from the Internal Revenue Service and clearance from the Securities and Exchange Commission for the transaction.

On Wednesday, May 1, Valero will distribute 80% of the shares in CST Brands to Valero shareholders as of the April 19 record date.

Those shareholders will receive one share of CST Brands common stock for every nine shares of Valero common stock.

CST Brands common stock will begin regular-way trading on the New York Stock Exchange under ticker symbol, CST, beginning on Thursday, May 2. Since April 17, CST Brands has been trading on the when-issued market under the ticker symbol CST WI and will continue trading there through May 1st.

As part of the transaction, Valero will retain 20% of CST Brands outstanding shares and also receive approximately $500 million in net cash.

This net cash amount consists of $1.05 billion from CST Brands' new debt which is offset by the retention by CST Brands of approximately $50 million of cash and approximately $280 million from a working capital benefit, primarily as a result of the payment terms in the product supply agreements.

Valero will also incur a tax liability of approximately $220 million, mainly for Canadian taxes on the transaction which is mostly payable in the first half of 2014.

Valero expects to liquidate its remaining 20% of CST Brands outstanding shares within 18 months of this distribution.

Our ethanol segment reported operating income of $14 million for an increase of $5 million from the first quarter of 2012, mainly due to higher gross margins per gallon which were somewhat offset by lower production.

Production averaged 2.7 million gallons per day in the first quarter of 2013 for a decline of about 770,000 gallons per day compared to the first quarter of 2012.

As industry supplies of ethanol declined throughout the first quarter, ethanol plant margins improved and have remained healthy so far into the second quarter.

As a result of the improved margins, we restarted three of our previously shut down ethanol plants during the first quarter and all 10 of our ethanol plants are currently operating near capacity.

In the first quarter of 2013, general and administrative expenses, excluding corporate depreciation, were $176 million and net interest expense was $83 million.

Total depreciation and amortization expense was $430 million and the effective tax rate was 34% in the first quarter.

Regarding cash flows in the first quarter, capital expenditures were $864 million including $287 million for turnarounds and catalyst and including $34 million for retail.

In the first quarter, we paid $111 million in cash dividends to our shareholders, which reflected the increase of $0.025 per share per quarter that we announced in January.

Also in the first quarter, we purchased 6.9 million shares of Valero stock for $304 million in cash.

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

So far in the second quarter, we have purchased another 2.8 million shares of Valero stock for $118 million in cash.

That brings our year-to-date stock buybacks to 9.7 million shares for $422 million and adding dividends, that makes our year-to-date total cash return to shareholders over $530 million.

Regarding other uses of cash, we retired $180 million worth of 6.7% senior notes that matured in mid-January and we expect to retire $300 million of maturing notes later this quarter.

With respect to our balance sheet at the end of the quarter, total debt was $6.9 billion, cash was $1.9 billion, and our debt-to-capitalization ratio, net of cash, was 21.4%.

At the end of the quarter, we had nearly $5.4 billion of available liquidity in addition to cash.

Valero expects full-year 2013 capital expenditures to be approximately $2.85 billion, which includes turnarounds and catalysts, and also includes approximately $60 million of spending for CST Brands through April.

Our 2013 estimate increased approximately $140 million from previous guidance, mainly due to the addition or acceleration of growth projects, including new logistics assets and hydrocracker expansions.

Given the competitive advantages provided by the increasing supply of cost-advantaged crude oil and natural gas, our growth spending is strategically focused in three main areas, logistics, processing cost-advantaged crude oil, and distillates-focused hydrocracking.

Within these areas we are pursuing multiple opportunities to create long-term shareholder value.

However, we are clearly balancing our growth investments with significant return of cash to shareholders as well as debt reductions to strengthen our balance sheet.

For modeling our second quarter operations, you should expect refinery throughput volumes to fall within the following ranges, Gulf Coast at 1.45 million to 1.5 million barrels per day, Mid-Continent at 400,000 to 420,000 barrels per day, West Coast at 270,000 to 280,000 barrels per day, and North Atlantic at 350,000 to 370,000 barrels per day.

These throughput volumes reflect a turnaround [in] maintenance activity planned at the McKee, Quebec City, and Meraux refineries.

Although we're only a third of the way into the second quarter, I want to highlight changes in the key drivers of our refining throughput margins versus the first quarter.

Gasoline and diesel cracks are mixed with some of our regions higher and other regions flat to down versus the first quarter.

Crude discounts have generally narrowed versus the first quarter, particularly for light crude oil discounts, such as WTI versus Brent, and heavy sour discounts.

In addition, the price of natural gas, a key driver for our energy costs in hydrogen feedstocks, has increased versus the first quarter.

As our investors should note, these key drivers are volatile and can change substantially within a quarter.

We expect refining cash operating expenses in the second quarter to be around $4.00 per barrel.

For our ethanol operations in the second quarter, we expect total throughput volumes of 3.4 million gallons per day and operating expenses should average $0.37 per gallon, including $0.03 per gallon for non-cash costs such as depreciation and amortization.

Also, in the second quarter, we expect G&A expense excluding depreciation to be around $160 million and net interest expense should be about $75 million.

Total depreciation and amortization expense in the second quarter should be around $405 million and our effective tax rate in the second quarter should be approximately 35%.

John, we have concluded our opening remarks.

We will now open the call to questions.

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

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

Thank you.

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

(Operator Instructions)

Our first question comes from Doug Leggate from Bank of America Merrill Lynch.

Thanks, everybody.

I'm going to take my two, if I may.

Can I ask you to clarify the $2.00 cost, the transportation cost to Quebec that you mentioned?

Is that sustainable?

Is it (inaudible) for gathering and processing on the Gulf Coast?

And can you just help us, to make it simple for us, what is the advantage when you (inaudible) in Quebec versus your prior feedstock.

And I've got a follow-up, please.

Okay, Doug.

The $2.00 we're talking about is the transportation cost.

It's really the foreign flag ship to take the crude from the port in Corpus up into Quebec.

And I'm trying to remember what the advantage was on a per-barrel basis, for running that oil.

I think at the time we moved it was fairly even with the alternative but I think what the guys found, and Lane can speak to this, what the guys found when they ran the oil in that plant was it cracked very well and it was a strong yields.

That's right.

That's exactly right.

It had better yield than we had anticipated.

All right.

Thanks for that.

I guess my follow-up is a related question.

We saw Tesoro move some facilities in place over time to move crude to the West Coast.

I'm just curious if you guys have got similar things in the works and if you could put into context of how you see your deliberations over an MLP and ultimately how you would invest in infrastructure and maybe follow suit?

(inaudible) Thanks.

Well, Doug, relative to supply on the West Coast, we continue to look at the economics of moving pipeline barrels across.

The dilemma that we have is if you're going to move those barrels into a US port and put it on a US-flagged vessel, a Jones Act vessel, the cost for the shipping becomes very high.

And so the alternative that we're pursuing -- and granted we continue to look at that -- but the alternative that we're pursuing is to go ahead and do the rail economics.

That's why we've got the train activity.

We bought all the rail cars and we're looking at rail terminals in Benicia and also down in Wilmington.

And we find that taking it directly into the refinery we have, it's good, if not better, economics than we would taking it across in a pipe to the West Coast and putting it on a US-flagged vessel.

Okay.

Those qualify for potential MLP dropdowns over time?

Yes, they would.

All right.

Great stuff, guys.

Thank you.

Thanks, Doug.

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

Good morning.

Good morning, Jeff.

Congratulations on the progress on CST and rapidly approaching the distribution.

I had a question on the potential for an MLP.

You've obviously got a lot of growth capital focused in the logistics area with Quebec and then an additional $200 million of logistics projects in the rail cars and rail and loading facilities.

Could you talk a little bit about the existing base of MLP qualifying assets and how realistic a potential MLP might be?

Jeff, this is Klesse.

We have said consistently here that once we finished with retail spend that we would look at the MLP, and that's what we intend to do.

And I have given in the past that we had an EBITDA base of $50 million to $100 million so I think at this point in time that's where we're going to stay.

All right.

I understand.

I was curious, if I could have a quick follow-up, if you're seeing pricing differentials for domestic crudes in Houston, given Seaway and rapidly approaching Permian pipelines coming into the Houston area.

Are you seeing those crudes trade at a discount to Louisiana, and by how much?

Doug, it's anywhere from $1.00 to $2.00 but we are seeing the crudes traded below [LLS].

In fact, I don't think we're running a light sweet crude in the system.

Certainly in the Gulf, it's not trading at a discount to LLS.

Are you expecting bottlenecks at Houston as these Permian pipes and then ultimately Keystone comes into the market?

I think that you're certainly going to have ample supply of these crudes in the Gulf.

As far as the bottlenecks, I think, they're working very hard to alleviate that now.

I guess we've got a Longhorn startup that's going to bring 75 a day and up to 225 here very soon.

Seaway is working on resolving their issues and the host of other alternatives.

I do think we're going to see ample supplies, though, of this heavy sour crude in the Houston market.

Thanks, Bill.

Thanks, Joe.

Our next question comes from Robert Kessler from Tudor Pickering.

Morning, guys.

One quick follow-up to that prior question, in terms of the price, average price, delivered in the Corpus relative to Houston or relative to LLS, is Corpus still below Houston?

And if so, by how much?

It is, and it's basically by transportation cost over there.

So another $1.50, $2.00?

Or more than that?

Yes.

And then looking a big longer term at Quebec City after you come out from the turnaround and maybe on in through the end of 2013, assuming the price differentials and relative yields for the Eagle Ford crude justify replacement with the alternate supplies, how big could that be?

What portion of throughput at Quebec City could you be running from, say, Texas-based crudes by the end of the year?

Well, our license that we got was for 90,000 barrels a day.

So that's the existing license that we have.

But the crude, as Lane said, ran very well in the refinery.

I would say to you, though, because obviously we're involved in Line 9 reversal that that refinery will be on all North American crude oil here within a year or so.

Got you.

And then last one for me, just coming back the MLP-able CapEx.

If I look at your 2013 budget, would it be fair to say that about $400 million at least of that would be MLP-able spend?

What kind of number would you throw out there?

It's between $500 million and $600 million, is what we have in our '13 spend.

Okay.

Thank you.

Our next question comes from Roger Read from Wells Fargo.

Good morning.

Good morning, Roger.

I guess I'd like to first hit you on the operating cost, the $4.00.

You mentioned, obviously, higher natural gas.

I wanted to confirm, is that effectively the natural gas cost?

Or is there something else going through?

Because obviously with the higher throughput expected in Q2, we could, on a per-barrel basis, maybe see that maybe a little lower than Q1.

Yes, that's a key part of that increase.

And this is Lane Riggs.

One of the other parts of that is Quebec, which is one of our lower operating cost refineries, is in a big turnaround but you have their capacity at lower operating cost for [Q1].

Okay.

All right.

That's helpful.

Understood that -- and very helpful that the light crudes you're running on the Gulf Coast are discounted to LLS -- I was wondering if you could help us understand some of what has been moving around the light-heavy spread more or less from the beginning of this year, through early April.

It compressed and it's widened a little bit since then.

We've heard different stories, Saudis were in and out of the market, Venezuelan crudes.

I was just wondering what you all have seen along that line.

Yes, all right.

You're look at Maya pricing when you're talking about the heavy sour.

But WTS strengthened with the Longhorn startup and essentially WTS realigning itself with WTI.

You'll remember last year, we had the huge discount of TS to TI and that certainly helped to expand that Maya discount.

The other thing we have had is WTI has strengthened relative to Brent.

As that's come in, you've had the whole heavy sour complex come in and draw closer to a WTI priced crude.

Then you're got the final factor, that the K factor has lagged.

Pemex uses that to adjust the price of their crude to keep it at a market parity with alternatives and they've lagged.

And they're limited as to how much they can move it in a month without going before the government to get approvals and so they just lag.

Now, we know we're going to get an improvement next month so this discount will improve further.

Those are the three primary factors that affected the heavy sours.

The medium sours have improved just recently as really a result, I think, of a lot more Middle Eastern crudes being in the Gulf.

Our guys estimated anywhere from 8 million to 10 million additional barrels were in the Gulf during the quarter so that's helped that.

If you look longer term, I think there's certain refiners in the Gulf that are going to end up running a lot more Arab crude than they would a Mars crude or domestic medium sour crude and that's going to put more of it back in the market.

As a more general statement, any time you end up with more crude in a particular market it's going to put pressure on the entire complex because you'll look at substituting.

To the extent that we move Midland barrels into the Gulf and they're accessible to Houston refiners, and other refiners, you're going to see additional pressure on both the medium and the heavy sours.

Okay.

Thank you.

Our next question comes from Paul Cheng from Barclays.

Good morning.

Two quick questions.

One is a simple accounting question for Mike.

After the 80% spin off of the CST, the remaining 20%, are you going to report them in terms of the P&L on the equity accounting?

Or are you going to report it as cost and only report P&L if you receive any dividend?

It'll be on an equity and earnings basis.

An equity and earning basis.

For the next several years, I think previously you guys were talking about somewhere in the $2 billion to $2.5 billion [tie off] of CapEx and this year is higher.

On a going-forward basis with some of the [new growth projects], should we assume that you're going to be higher than that range now?

Paul, this is Klesse.

We're higher this year because we do have quite a few logistics projects that we discussed a few minutes ago and they will carry over into next year, some of them.

But the guidance I have only given is to next year in the $2.5 billion range.

Except for some carryover of these type of projects, we'll be in that $2 billion to $2.5 billion range with some carryover of logistics projects.

The whole business today is about location, location, location and if you don't have the location, you have to have the logistics.

Totally understand.

A final one on -- maybe this is for Lane -- butane and naphtha.

There is a lot of concern in the market, the debate is going to become increasingly abundant and as a result be really cheap.

The question is that do you guys already at this point max out in terms of how much you can [blend]?

I presume butane is going to be restrict by the [RVP].

And naphtha, I don't know if there is anything you can do in terms of increasing your [net blending wall in] if the price is attractive.

So the question is the naphtha length that all refiners are seeing, and that is correct.

And you're seeing more of what I'll call low-octane blend stocks coming towards the refiner from the NGL piece.

So for us in particular, yes, we are blending the naphtha where we have enough octane.

Also what is happening is, as the price of naphtha which we expect what you said to occur as well, you will go ahead and restart or increase your runs through your reformers.

So even though you want to make hydrogen from natural gas, the facts are, because of the naphtha pricing you may go ahead and run your reformer as well.

So we're doing that and looking at that.

Then it depends on what severity you actually run at your reformer.

Then, of course, the last option is that naphtha could potentially be exported.

As everybody else in our industry, we will look at all of those numbers and pick the best course.

And that's what we're doing, and I'm sure everybody else is.

Is there any rule of thumb you can provide, under what circumstances that you would choose one option, or is that's too many moving parts that can't really give one rule of thumb?

You really have to run it through your models, to be honest with you but I suspect, first option is the blend.

The second option will be to run your reformer and run it at different severities and then the third option is, meaning you just can't get rid of it internally, that the option will be to export it.

Thank you.

That's how I'd rank them.

Our next question comes from Sam Margolin from Cowen.

Good morning.

Thanks for the time.

You touched on Maya.

I want to revisit this for a second.

It looks like the composition is really outmoded here, given the fact that all the components have dislocated from each other.

In the past, you've had a lot of success pricing heavy barrels in the Gulf away from that benchmark and you touched on it a little bit with the pipeline capacity going into the Gulf, maybe devoted a little more to the heavy side.

I was wondering if you could provide a little bit more color on the opportunity set for heavy crudes, underneath what we're seeing on the Maya side.

Well, we are seeing heavy crudes move South, right?

We're moving them by barge.

We will be moving it by rail into St.

Charles and we're seeing some come down Seaway that gets consumed.

Then you go back to the more traditional, there is going to be more there from the US and actually from North America.

Then you look in towards South America and the traditional sources and we continue to be a large purchaser of crude from South American producers and even though those crudes have a Maya basis, there's agreements that we have in place that vary the price on that.

We've been able to continue to get heavy sour crudes priced in and Maya prices are better.

Maybe I'll add a little more for you.

When you look at the Mississippi River, we're doing what others are doing.

We are barging heavy crude down, and also we're looking at rail facilities to bring it into our St.

Charles and those refineries.

If you start to move west, of course Keystone pipeline is being built, the Southern leg, and that's where Joe's speaking of seeing more heavy crude come down.

We expect to see heavy crude come into Port Arthur as well as more into Houston through all the other pipelines and, of course, Keystone.

Then you jump back and then there's foreign imports, you have to look to Venezuela and what actually happens in Venezuela as we go forward.

And when they have had, and this is the truth, when they have operating issues with some of the upgraders, things like that, we get to see more of this type of oil that we can process in our hardware available.

So you have all of these moving parts but, generally speaking, Valero wants more heavy sour crude oil on the US Gulf Coast because we are a big buyer.

Okay.

Thanks so much for the color.

And just as a follow-up.

Keystone potentially facing another delay here but as a lot of investment moves into the rail side, and that seems to be taking up a bigger and bigger share of uptake and these disadvantaged basins.

I was wondering if you had done any planning or thought about the raw bitumen element as well, moving away from WCS and getting it in as a raw material, particularly if there's any local blending opportunities for you around your Gulf Coast system?

Of course.

I'll try to answer part of this.

Of course, we have.

We still believe Keystone.

I'll just deal with the Northern leg, XL, we still believe that will be approved and it will be built.

It's a pipeline.

This has nothing to do with the pipeline.

It's all about the oil sands.

And just a little trivia here.

The greenhouse gas emissions from producing California heavy crude are actually higher than it is for the oil sands and one cold power plant produces like 25% of the greenhouse gas emissions from the oil sands.

This is all just a ridiculous conversation that's going on.

But part of the rail cars that we have purchased are insulated and coiled so that we can move the raw bitumen just as other companies are trying to balance between WCS and Bakken and those types of crudes, as well as the pure bitumen.

We've tried to estimate how we will supply our refineries down the road and purchase our rail cars accordingly and those rail cars will be delivered to us really through the end of '14.

So they come to us every month.

All right.

Thanks so much, everyone.

Have a great day.

Thanks, Sam.

Our next question comes from Evan Calio from Morgan Stanley.

Yes, good morning, guys.

Good morning, Evan.

Sorry if I missed some of the opening comments, but can you provide any additional color on the hydrocracker issue at Port Arthur in the quarter, and whether it rolled over into the second quarter, and just confirm you remain on track for the St.

Charles startup?

Hi, Evan.

This is Lane.

What we had to do is we had an emergency shutdown valve that wasn't working properly so we had to remove it and had it shipped off.

We found there was a manufacturing error in the valve.

We actual were able to take the one from St.

Charles projects, which are essentially carbon copies of one another, and put it in place.

In Ashley's notes, this was really a March conversation.

So, no, we're running fine and don't expect this to have any implications for the second quarter.

And we also lost a seal on a compressor when we had a power failure or something.

Yes, the initiating event for this, we had a [recycle] compressor trip on a loss seal and that caused this emergency shutdown valve to close and then it wouldn't open.

So those have been repaired and that part of the project is going just fine, as Ashley said.

And at St.

Charles it's going to be late, late second quarter.

We'll get some oil in the unit, but we'll really be starting up in July.

We are having, in a sense, difficulties getting this job done but it's not through lack of effort.

Got it.

I know you guys quantified potential RIN exposure year-on-year.

I was just curious if there was any strategy to mitigate that number?

I notice that Diamond Green startup is obviously going to give you incremental more valuable diesel RINs, building new terminals to blend.

Anything else that you're doing that could mitigate that potential cost?

Thanks.

Evan, we are looking throughout the system just to find every opportunity that we can to blend more.

We continue to look at the economics on every export cargo to decide if [the arb] is better to keep it here, to go ahead and put it on the water, considering the cost of the RIN.

We've adjusted products yields throughout the quarter and we will continue to do that.

For example, we produced more jet when it was economic to do that but the economics don't favor that today, so we moved back.

And then we've got a very aggressive effort to try to support change to the regulations as they are and you may want to talk more about that, those activities.

We're working those issues every way we can just to try to make this problem less of a problem for us.

I think we're still very comfortable with the estimates we've given you for this year, in that $500 million to $750 million range.

But the squeeze that we've had that's driven the prices up where they are is going to be with us unless we get some kind of relief.

I think what I would add is, the way Joe is describing this is what RINs have become is part of our cost to manufacture and then in our decision-making.

So if you have a $0.60 RIN or whatever it is, $0.56 to $0.70 today, it gets into our cost to manufacture and then it works through all our modeling so that helps you drive your LP economics.

And that's really the point here.

It gives you more of an incentive, for instance, to make jet fuel than diesel, or whatever.

And that's how it works through the modeling.

Great.

And lastly, if I could, I know you had benefited from some distressed [Vin] cargos that were in the market the last couple quarters.

Are you still seeing some volume there?

Or have they been pulled back given [Mace's] back up and running?

Yes.

I think be continue to see them from time to time and it's certainly not rateable, Evan so it's really hard to say whether it's more or less than it has been, or when that might change but they're still available.

Got it.

Appreciate it, guys.

Our next question comes from Blake Fernandez from Howard Weil.

I had a balance sheet question for you, I suppose.

Ashley mentioned the debt reduction of $300 million in notes later this quarter.

Obviously, you have some cash coming in, about $850 million or so from the retail spin.

Bill, I know you talked about maintaining a more flexible balance sheet post the spinoff of retail.

Can you give us a sense of once we get the cash in hand and then pay off the notes that you referenced, how should we think about additional debt reduction from here?

Well, for just the question on debt reduction, this is all the debt that we are maturing this year so that will leave Valero with about $6.6 billion of long-term debt.

Next year we have about $200 million of maturing debt.

I would assume we're going to pay that off.

The year after that, we have $500 million, right?

$500 million in next year that, at least today I would tell you, we would pay off so that takes you out quite a few years.

And that's the maturing debt.

As far as calling debt, we do not have any debt that it is economic for the Company to call.

To your question, I think you're asking me a little broader question, and that is, I don't know where you came in the call, but so far this year we've bought over 9 million shares of our stock.

We have been out of the market, obviously, the last few weeks, as we have to be.

We'll be out of the market for a while here while this settles out with CST but we think our stock is still undervalued and we, as Ashley said in his comments, we're returning cash to our shareholders.

Perfect.

Thank you on that.

The follow-up question I had for you, on the incremental hydrocracking expansions, I'm just trying to see if I can get a sense of how that may potentially impact the overall Company-wide yield.

I know you guys had some charts in your slide pack showing the changes in distillate yield over time.

I am trying to get a sense, does this have a order of magnitude impact to change the overall yield?

Yes.

The numbers that we've shown you in our presentations after the two hydrocrackers would take us up to about 39% of the total distillate yield.

And I've mentioned in the past that when we finish these expansions and do our conversion at Meraux, we will be into the low 40s.

I have [used this] 42%, 43% of our yield.

And really for Valero, we're unique then at that point because we'll have a gas-to-distillate ratio of about 1 to 1, which is very unusual for a US refining company.

Perfect.

Thank you, Bill.

Our next question comes from Chi Chow from Macquarie Capital.

This may relate to Evan's prior question, but in the first quarter it looks like your realized margin capture rate in the Gulf Coast was strong again, even with the high levels of maintenance.

Did you realize the same dynamic in the fourth quarter with capturing these stranded heavy barrels?

Or was there something else that drove the capture rate?

Chi, the biggest driver, the single biggest driver is probably the addition of the new hydrocracker at Port Arthur.

That's just a high-margin unit.

After that we saw some nice discounts on some of the distressed heavies and some of the things we benefited from in the fourth quarter but the number-one by far was adding the hydrocracker.

Okay.

How much heavy Canadian crude did you bring down and process versus prior quarters?

It was about the same, Chi.

I'm going to tell you we were in the [45% to 50%] range on average.

Now, there were periods there that we had much higher volumes.

We are expecting those volumes to ramp up going forward.

But it wasn't materially different than fourth quarter.

Okay.

Thanks, Joe.

And then on the RIN issue, Bill, can you give us an update on any discussions that Valero or other industry groups have had that you are aware of with the EPA on any relief from the RFS mandate and how any of these lobbying efforts are going?

Well, I can give you some color.

I was in Washington last week with a group of other refiners and a couple of the majors.

Our industry is united here in trying to get awareness that the RINs issue, when it was $0.05 a RIN was one conversation, and when it rapidly increased to over $1.00 and has fallen back here, it's another whole issue.

As an industry here, we met with several Congressmen, some senators.

They all realize that the RFS is broken and needs to be fixed.

There is no cellulosic to speak of.

I think somebody is going to make a little this year.

The advanced is ludicrous that you're willing to buy Brazilian sugarcane ethanol and export corn-based ethanol.

It's a ludicrous thing here so people realize that.

As far as the White House and the EPA, they both realize as well, we met with them, that there is an issue but I am not going to say that anything is going to be solved here in the short run.

Okay.

Do you believe these discussions, when do they gain steam again?

Is it dependent on RIN price, cost inflation?

Is that what the next battle wages?

Or is it late this year when the EPA actually takes a look at obligations for next year?

Any sense on timing?

Theoretically, you don't hit the blend wall this year anyway, so this is more of a precursor of things to come.

You do hit the blend wall next year.

There is a realization that E15 is not the solution.

When the EPA tested E15, they really only tested emission systems.

The facts are on the API-ran tests, and out of the three major fuel pumps in cars today, one of them failed 11 out of 12 times.

So there is now this awareness.

AAA's come out that going to these higher ethanol percentages will not work in the car fleet.

I think 95% of the car fleet is not warranteed or so for a higher ethanol content.

I think what you have is an awareness that this has to be addressed.

There is going to be, or scheduled to be, hearings.

I think it's in the House Energy Committee here later this summer but it's like all things in life, squeaking wheel gets the grease.

And when something starts squeaking, whether it's high RIN price, high gasoline prices, high something, there will be a lot more attention.

Okay.

Just one question on the E15.

Does the EPA acknowledge that that is not a solution?

Or are they still of the mindset that their tests are valid that they conducted on the vehicles?

Any sense there?

I would not have an answer.

They're aware that the car manufacturers have not changed their warranties and they're aware of this fuel pump issue.

But I don't know if they have said anything else.

Okay.

Great.

Well, thanks, Bill.

Appreciate the comments.

Your next question comes from Paul Sankey from Deutsche Bank.

Bill, I hate the subject myself, believe me.

But it seems like we're going to have to get into 2014 before we get a resolution on this, and that's when the crisis -- it has to become a crisis, essentially, before we get a solution?

Well, I suppose that's right.

Now, I do say there are going to be hearings and there is an awareness that there is a problem brewing that is of significance.

So you do have awareness.

The rest of this is, I am just an engineer working in an oil company, refining company here.

You tell me about politics.

Well, as you know, we look to you as a spokesman of the industry, Bill, as regards to what Washington is going to do.

I think you've been quite clear on this.

I am worried that the EPA broadly, arguably, prefers high gasoline prices for efficiency reasons and the politicians aren't concerned because the gasoline price is relatively low.

Well, I would not disagree with the second part of that.

I would not put words into the EPA's mouth that they want high gasoline prices.

Okay.

Let's totally change the subject.

You're pursuing, obviously, the organic projects that you have.

Is there anything on M&A, asset market transactions -- obviously you have been busy with the CST thing -- but is there anything to say about any other potential changes to your asset base, Bill, at a refining level?

I know you've referenced pipelines and [trains].

Thanks.

Paul, this is Gene.

There's pretty slow activity in M&A right now.

I think the issue is, US refineries, almost everybody is making money now, or think they'll be making money in the future as these cheaper crudes become available so there is really not a lot on the market.

A couple that were on the market got pulled off, that you are probably aware of.

Then in Europe, there is some things for sale over there but you've got to look at the European situation as they become the [marginal] player in the world, without the cheap crude and without cheap natural gas.

You've got to be top tier, basically, to be a survivor in Europe.

There is limited activity, I would say, right now in the whole Western hemisphere.

Great stuff.

And then finally from me on exports, there's some concern that new capacity in the Middle East and other additional supply globally may threaten the distillate export story.

Do you guys have a view on that?

Well, I think as the Saudi refinery comes online, part of its products will clearly be directed to the eastern Mediterranean and into the Med.

Clearly, some of the Indian Reliance clients have moved that way as well as moving to Southeast Asia.

You also have some Chinese projects that are coming online.

But I think you have to come back to at least the US Gulf Coast capability here to be very, very competitive.

If you look at our natural gas cost relative to the other refiners, if you think about the crude and these, at least the differentials that Joe spoke to earlier against world markets, there's no doubt in our mind, even though we've had LLS above Brent and other things happening, that eventually LLS is going to go below Brent.

We really do believe that this is what's going to happen.

So our crude situation pricing is very strong.

Then you look to new refinery construction.

The Brazilian refinery that I guess is going to get done sometime here, they're now up to $16 billion to $20 billion for a 230,000-barrel a day refinery.

Those economies are growing, whether it's Mexico, Colombia, or Brazil.

Any of these guys that have talked about building a refinery like Ecuador, I find it personally extremely hard to believe that those countries will spend money to do that.

So I think that the US Gulf Coast can compete very well into those markets.

I think we'll still send distillate to Northern Europe so I think we're competitive.

I think the markets are there for us and the US still is a huge market that consumes product as well.

I think you have to have the export markets.

Otherwise, US refinery operating rate is going to drop significantly.

Yes, we tend to agree, Bill.

It's worth noting that the market cap of your Company is not that far from what that one refinery, the system is going to cost in Brazil.

Kind of crazy.

Anyway, thanks a lot.

You could build one, so we're not for sale.

But you could buy all of Valero for about one or one and a half refineries.

Crazy.

Yes.

Thanks, Bill.

Our next question comes from Faisal Kahn from Citigroup.

Just a quick question on the McKee turnaround.

When the turnaround is completed, is that going to result in any increase in your distillation processing capacity?

Is that still a second quarter '14 event, is that right?

Faisel, this is Lane.

Because the unit was not performing as best as we went into the turnaround, we'll gain some capacity back on crude distillation.

We are putting in this energy efficiency project, which will allow us to improve the yields of diesel off the unit.

But yes, the expansion that we've spoken about the last few calls and Investor Relations is really this event, is in 2014.

Okay.

We're waiting on the greenhouse gas permit.

We do not have the permit, is the reason here.

We have to wait for a permit.

What is the turnaround time for a permit?

When did you guys file and when would you expect to get a permit?

Well, I don't know when we filed.

But the way it's going now -- because Texas is not issuing the greenhouse gas permit because we have this dispute going on.

This is Texas.

I will tell you it's two years.

Okay.

Understood.

Just like California and just like the East Coast.

That's not true for some other states.

Our next question comes from Ed Westlake from Credit Suisse.

Two questions.

The first one is going to be around turnaround schedules and the second one's on your self-help.

Just on the turnarounds.

It feels as if you're still doing quite a heavy amount of turnarounds in the system, in the first half of this year.

Is 2013 characterized as a heavy year and then it gets a bit better for '14 or '15?

Give us some color potentially.

This is Lane again.

It is a little heavier than I would say our average year is.

And we don't have any really big turnarounds other than finishing this Quebec turnaround in June, really for the rest of the year.

Next year is a little bit more towards our average turnaround.

So to give you scope, we spend about $600 million a year, somewhere between $400 million and $600 million a year.

We're on the $600 million a year side.

We're a little bit lower than that next year for the range of turnaround work.

That's helpful.

On these crude topping facilities, $250 million I guess is the average.

Any idea of a payback period for those types of things?

And are they really looking at splitting off the light ends and then exporting the light ends or moving them around the system?

Well, do you know the payback?

Of course, it depends on your assumption as to the crude pricing.

They have IRRs in the over 30% area.

But it's based on our assumption, as to these discounts.

Then the second piece of your question, no, they are not.

The two that we're looking at are Corpus Christi and Houston.

Today, those two refineries are short crude fractionation.

We buy stuff.

So at Houston we have a very large cat cracker.

We buy feed for the cat cracker.

What we'll do in Houston is, by building this crude topper fractionator, we'll make our own feed for our conversion units downstream.

Historically, in the business, you didn't really make any money on crude fractionation.

You made money on conversion units.

We have a couple of refineries, including Wilmington, for instance, that has a lot of conversion, not a lot of crude fractionation because it was economic to buy feedstocks.

If you're in a world where you have depressed crude oil prices, relative to the feedstocks, you can see that there's an incentive to make your own feedstocks.

And that's what we're really doing at both plants.

And then doing some math, these hydrocrackers expansions, that's about another 50,000 barrels a day, slightly under the 0.5 billion you get from the current hydrocrackers.

You get the 30% payback on these crude [topping] facilities, some crude up in Quebec and then you've got the maybe $19 million depending on TI Brent for McKee.

It all adds up to another $750 million to $1 billion dollars of potential [EBITDA] improvement in, say, 2015 as the next round kicks off.

Is that a fair reading?

It's a fair reading in the sense of you have to make your own assumptions, but as to these differentials, making more distillate, what's the distillate crack, but these are why we're doing those projects.

We think they fit exactly with how the markets are shaping up.

Thanks, guys.

Our next question comes from Arjun Murti from Goldman Sachs.

Thanks.

In your release, you mentioned investing in certain refineries to increase the front-end flexibility to process more light sweet crude.

I apologize if I missed any of your remarks but any quantification of capital requirements in incremental light sweet crude runs from those efforts?

Yes, Arjun, this is what we were just talking about, these front-end -- the topping projects.

Yes.

This is at Corpus and at Houston.

Bill was explaining where crude's short versus [the] downstream.

They're $220 million to $280 million apiece.

And incremental crude is, I think Houston 90 a day and Corpus is --

70.

-- 70 a day.

70,000 barrels a day.

But we have other things going on just -- and I'm going to tell you just like everybody else -- where we're pushing out medium-type crude oils throughout our system to be able to handle more of the light crudes.

And so we can run in our system now, I think it's 680,000 barrels a day.

I know we have this.

Yes, you're right.

680,000 barrels a day of light, light or sweet crudes in our system, and we have other projects underway to de-bottleneck here, change an exchanger there, move some of the light ends over here, and we have quite an effort going on in our engineering groups because we believe this all is going to be [discount].

I guess the big thing was to ensure you don't lose on utilization and the op costs don't go crazy.

It sound like that's the purpose of these projects.

You can maintain utilization rates and the op costs will still look reasonable.

Well, the purpose is to make money.

Yes.

And so we'll run our LPs.

In other words, if we're making more money and our operating costs go up per-barrel basis, I guess I say so what.

Okay?

We wouldn't be focused on, we have to hit X op costs.

What we would want to do is make more money overall.

That makes sense.

Thank you so much.

Our next question comes from Allen Good from Morningstar.

Good morning.

Thanks for taking me here at the end.

I know we're running long.

A follow-up question as well on some of the indicated investment for the increase in the exportability as well.

Can you remind me of what your current export capability is now, and where you see that moving to over the next two or three years?

Yes.

I think if you looked at gasoline today you'd say we could accommodate 225,000 barrels a day and we'll be able to take that up to 250,000 or more going forward.

Diesel is 280,000 barrels a day and that goes up to 400,000 to 425,000 with some of the projects we've got underway.

The projects are really focused on tankage, some piping, some dock work.

The tankage would allow for additional segregations, which will enable us to keep higher quality distillate feeds segregated, and then we can capture the premium when we export them.

Okay.

Great.

And then I know a couple years ago when you did the Pembroke acquisition, you made mention of taking advantage of some Atlantic Basin opportunities and maybe even exporting back across the US.

Given all the changes that we've seen here in the crude supply here in North America and the potential for some of the light or discount crudes to move to the East Coast, do some of those export options in the Atlantic Basin still exist for Pembroke and does acquisition quite stack up now, compared to how it was a few years ago, given all the changes we've seen?

Your comments are fair.

But we're making money in Europe, in the UK, in our business.

We've been able to move gasoline into the East Coast.

We have moved gasoline to Quebec.

We shipped some gasoline to Brazil.

The distillate's going back still towards Europe.

So, yes, I think we have a very sound Atlantic Basin strategy when you consider Pembroke, our Quebec City refinery, and then our Gulf Coast operations.

Yes, the best place in the world to refine today is the US Gulf Coast and so that's got to be true.

But otherwise, I think our position is good.

Okay.

Great.

Thanks.

Our next question comes from Robert Kessler from Tudor Pickering.

Thanks for the follow-up.

Bill, just a friendly push on the heavy-light differential commentary.

I get your point about the probable near-term widening in the heavy-light spread and the K factor lag and everything.

Just push you a bit for color, that the spot spread today, between LLS and Maya, sub-$5.00.

You've mentioned in the past a 8% differential is needed to justify marginal coking economics.

Can we make a simple extrapolation and say some of your cokers are technically underwater for just that unit today?

Or can you correct me in that assertion?

Okay.

So the numbers you say are fine and I've said really 8% would be a floor.

You probably need 10% to 12%.

Part of it gets into what you're comparing it against, whether it's against Brent LLS or this.

Now, are cokers underwater?

They are at roughly break even.

If you have the ability to market asphalt versus an open coker, you'd be marketing asphalt today.

But versus fuel, you would coke [fuel] oil.

We're right there.

We're right at break even on the cokers.

So your observation is correct.

If the heavy light spread does not widen like you expect, would you consider reduced throughput at the cokers?

Sure.

Sure.

Maybe you couldn't hear him very well.

If we could make asphalt at some of our plants, like Corpus, you'd make asphalt.

Then if you have a spare coker we're looking -- now you have a spare coker, if you have optionality.

Then you look at the fuel oil economics so we would balance those, as well.

Sure.

Thank you.

Yes, you can spare your coker would be, yes, you're right.

Thank you very much.

Our last question comes from Paul Cheng from Barclays.

Hi, a really quick follow-up.

Do you have an estimate, what is the opportunity cost related to downtime in the first quarter for Benicia and Wilmington, as well as the Texas city, Corpus Christi, and Port Arthur, two different numbers?

You want the number for --

What is the opportunity cost related to downtime in your Gulf Coast system and in your West Coast system in the first quarter?

Yes.

Hang on.

We're going to get that.

Yes, hold on one second.

Including turnaround activity, yes, I'm going to have to break this out.

Paul, this is Lane.

On the West Coast, it was about $31 million of unplanned downtime.

On the Gulf Coast, it was about $30 million.

Do you have the turnaround numbers?

Lane, those are opportunity costs, right?

It's not the actual repair costs?

It's opportunity costs?

Right, that's what we call a [lock in] variant.

Yes, lost margins.

Okay.

And so that's just on the unplanned downtime.

Plus, you want the impact of turnarounds?

Yes, please.

We don't have that.

It's actually a pretty big number.

It looks like it's over -- for the Gulf Coast, over $200 million, and then West Coast is about $25 million.

So that means that in the West Coast is $25 million, right?

Gulf Coast is $200 million, you say?

In that ballpark, yes.

So that means that West Coast, the total downtime you estimate your opportunity cost is [variant] of $56 million and in the Gulf Coast is actually as high as $230 million?

That is a rough estimate based on market margins and impacts due to turnarounds and unclaimed outages.

Very good.

Thank you.

We have no further questions at this time.

Okay.

Thanks, John.

And thank you for joining our call today.

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

Thank you, ladies and gentlemen.

This concludes today's conference.

Thank you for participating.

You may now disconnect.