瓦萊羅能源 (VLO) 2014 Q1 法說會逐字稿

Welcome to the Valero Energy Corporation reports 2014 first-quarter results.

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

(Operator Instructions)

Please note that this conference is being recorded.

I will now turn the call over to Mr. Ashley Smith.

Mr. Ashley Smith, you may begin.

Thank you, Bakiba.

Good morning, welcome to our call.

With me today are Bill Klesse, our Chairman and CEO, who will step down from the CEO position this Thursday; Joe Gorder, President and COO, who will become the CEO this Thursday; Mike Ciskowski, our CFO; Gene Edwards, and several other members of Valero's Senior Management team.

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

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

If you have any questions after reviewing these tables, please feel free to contact our Investor Relations team after the call.

Now, I would like to direct your attention to the forward-looking statement disclaimer contained in the press release.

In summary, it says that statements in the press release and on this conference call, that state the Company's or Management's expectations or predictions of the future, are forward-looking statements, intended to be covered by the Safe Harbor Provisions under Federal Securities Laws.

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

I have noted in the release we reported first-quarter 2014 earnings of $828 million or $1.54 per share.

First-quarter 2014 operating income improved over first-quarter 2013, with gains in the refining and ethanol segments, partly offset by a decrease in our former retail segment, due to the spin-off of CST brands in May 2013.

The refining segment throughput margin in the first quarter of 2014 was $10.90 per barrel, which is an increase of $0.31 per barrel versus the first quarter of 2013.

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

Also contributing to the higher throughput margin was our Quebec City refinery's increased consumption of cost-advantaged North American crudes in the first quarter.

North American grades comprised 45% of the refinery's feedstock diet, up from 28% in the fourth quarter of 2013, and 0% in the first quarter of 2013.

This shows execution of our strategy to process more volumes of these cost-advantaged North American crudes.

For color on crude pricing, the shifting of US Mid-Continent crude supplies from Cushing to the US Gulf Coast, as pipeline flow rates ramped up in the first quarter, drove WTI discounts versus Brent scenario by $9.15 per barrel, while LLS discounts to Brent widened by $5.39 per barrel, as crude inventories built in the US Gulf Coast between the first quarter of 2013 and the first quarter of 2014.

Gulf Coast sour crude oil differentials to Brent also widened from the first quarter of 2013 to the first quarter of 2014 in response to the increasing supply of light sweet crude.

The discounts for Mars and Maya relative to Brent increased by $4.10 per barrel and $8.76 per barrel respectively.

Refining throughput volumes averaged 2.7 million barrels per day in the first quarter of 2014, which is an increase of 135,000 barrels per day, versus the first quarter of 2013.

Refining volumes were higher, primarily due to less maintenance activity, which enabled the refineries to run at higher rates and capture margins.

Refining cash operating expenses in the first quarter of 2014 were $4 per barrel, which is $0.21 per barrel higher than the first quarter of 2013, due primarily to increased energy costs on higher natural gas prices.

I would like to highlight another item in our operations during the first quarter of 2014, the new hydrocrackers at Port Arthur and Saint Charles ran well, and had a combined feed rate of about 120,000 barrels per day, which is their stated capacity.

The new hydrocrackers also contributed to an increase at yields of gasoline and distillates, and a reduction in the yields of other lower value products.

The ethanol segment delivered record first-quarter earnings, generating $243 million of operating income, versus $14 million of operating income in the first quarter of 2013.

Increased gross margin was driven by weather-related supply disruptions, low industry ethanol inventories, low ethanol imports, and lower corn costs relative to the first quarter of 2013.

Ethanol production volumes averaged 3.1 million gallons per day in the first quarter of 2014, which is higher than first quarter 2013, but lower versus the fourth quarter of 2013, due to production slow downs, caused by weather-related rail congestion.

As noted in the earnings release, we acquired an idled 110 million gallons per year ethanol plant in Mount Vernon, Indiana for $34 million in March.

Efforts are underway to restart the facility, and production is expected to resume in the third quarter of this year.

Given the favorable ethanol margin environment, we like the returns potential for this new facility.

General and administrative expenses, excluding corporate depreciation, were $160 million in the first quarter of 2014.

Net interest expense was $100 million, and total depreciation and amortization expense was $420 million.

The effective tax rate was 33.9%.

With respect to our balance sheet at quarter end, total debt was $6.6 billion and cash and temporary cash investments were $3.6 billion, of which $384 million was held by Valero Energy Partners LP.

Valero's debt to capitalization ratio, net of cash, was 14.3%, excluding cash held by Valero Energy Partners.

Valero had approximately $5.4 billion, and Valero Energy Partners had $300 million of available liquidity, in addition to cash.

Given our financial strength and favorable outlook for refining margin conditions, last week, S&P affirmed our BBB investment credit rating and raised our outlook from negative to stable.

Cash flows in the first quarter included $517 million of capital expenditures, which included $129 million for turnarounds and catalysts.

In the first quarter, we returned $359 million in cash to our stockholders by paying $133 million in dividends and by purchasing approximately 4.3 million shares of Valero common stock for $226 million.

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

We expect stay in business capital to account for approximately 50% of total spending, and for the remainder to be allocated to strategic growth investments, which are primarily for logistics and light crude oil processing projects.

For modeling our second-quarter operations, you should expect refinery throughput volumes to fall in the following ranges: US Gulf Coast at 1.42 million to 1.47 million barrels per day, US Mid-Continent at 370,000 to 390,000 barrels per day, US West Coast at 260,000 to 280,000 barrels per day, and North Atlantic at 420,000 to 440,000 barrels per day.

We expect refining cash operating expenses in the second quarter to be around $4.20 per barrel.

For our ethanol operations in the second quarter, we expect total production volumes of 3.5 million gallons per day, and operating expenses should average $0.40 per gallon, which includes $0.04 per gallon for non-cash costs such as depreciation and amortization.

We expect G&A expense, excluding depreciation, for the second quarter to be around $160 million and net interest expense should be around $95 million.

Total depreciation and amortization expense in the second quarter should be approximately $410 million, and our effective tax rate should be around 35%.

Okay, Bakiba.

We have concluded our opening remarks.

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

Just want to remind our callers that during this segment, we'd like to limit you each turn to two questions.

You can always jump back into the queue for additional questions.

Okay, Bakiba.

We're ready.

(Operator Instructions)

And our first question is going to come from Paul Cheng from Barclays.

When I'm looking at your buyback in the first quarter, is $226 million.

In January, from your last conference call, you said $204 million.

So when we're looking at February and March, the decision to slow down the buyback, what's the -- can you help us understand what is the thinking?

What is the criteria, when you determine that, how much you want to buy back?

So this is Klesse.

We were basically out of the market in February and March because of our pending management change, which our legal advice was we could not be out buying our stock.

And then in March because of the earnings, the whole period of February, March, and then into April here, with the earnings.

So we've really just been, in a way, blacked out or locked out of the market.

There's no change in our strategy here.

Returning cash to the shareholders, and our dividend, which we raised in January, and then buying our shares.

Second question for you, statistically, how fast do you want to grow the LP EBITDA or distribution?

Where do you want to top during the initial years?

I think there's schools of thought among some of your peers.

One is that they want to grow the LP as quickly as they could, so that would can get to a size they can use their own balance sheet, to raise that to fund future growth.

The other school is that they want to be just in the high teens, what is the school of thought that you belong?

Hey, Paul, this is Joe.

If you look at you are or peer group in this, and we're really talking about the sponsored MLPs, we consider Phillips and Marathon to be the two, and Phillips has said publicly that they're going to grow their distribution to the 20% to 25% range.

Marathon is at a range slightly below that, we understand, and we tend to focus on the higher end of the range, so we're targeting 20% to 22%, 23%, distribution growth, annually, going forward.

And in our approach to do it, initially we have drop down assets that are the same type of assets that we did, when we did the initial assets, which are those with very ratable, stable cash flows, based on fee-based income.

So we're going to target the timing for our first drop to be early part of the second half of this year.

And then I would think, although we can't give that kind of direction, it should increase cash flows, and distribution increases should follow.

Joe, can we still assume that the MLP-able assets sitting in the C Corp today is somewhere in the $300 million to $400 million for you?

Paul, the range that we talk about is actually higher than that.

I would say we're in the $800 million EBITDA range that we believe we could drop.

Thank you.

And before I finish, Gene and Bill, congratulations on the retirement.

Thank you for all the years of your insight.

We appreciate.

And best of luck, and have a lot of fun.

Don't spend too much time in the [bidju ageppo].

Thanks, Paul.

Thank you.

And our next question is going to come from Roger Read from Wells Fargo.

Please go ahead, your line is open.

Could we talk a little bit about Gulf Coast volumes here in the second quarter, and then, within that broader expectation, generally speaking, volume has been better the last two quarters than I think -- or at the higher end of the range of expectations.

Could you walk us through what's happening in the Gulf Coast, and then maybe what could push that to the higher end of the range again?

This is Lane Riggs.

Are you asking in terms of our performance, or the overall industry for the Gulf Coast?

Specific to you.

Okay.

Specific to us, when you look at sort of quarter to quarter and year over year, our turnaround activity was lower.

In the first quarter, we sat a little bit higher than the second quarter.

In terms of our volumes, you'll see our second-quarter volumes will be a little bit lower in terms of Gulf Coast, as we have a bigger turnaround period.

In terms of the amount of North American crudes or light crude processing that we have versus our capacity, we still have about 165 a day versus our capacity that we could have run, and this was largely due to we have -- medium sours, and heavy sours, we were still quite competitive in the first quarter, versus our capacity, we can still run about 165.

Other than that, we are signaled to run full or near full, as our availability would allow.

Okay.

Could you walk us through what the turnarounds are in the Gulf oast in Q2, to the extent that you want to, the specific units or type of work that's being done.

We choose not to disclose that until after the turnarounds, until the following quarter when the turnarounds are complete.

The numbers are, in terms of the overall volume metric, they were actually initial, in terms of the guidance on the volume.

So what happened here is this is all legal advice, and some of the things that have happened in the markets.

We've changed our policy on this.

I think some of you have noticed, so we no longer announce our turnarounds ahead of time.

And so you just have to rely on the guidance that Ashley gives you, as the volumes we're looking at.

Okay.

Well, as long as we know who to blame if it doesn't go the way it was supposed to go.

Well, blame Ashley.

There you go.

Just the last question here, then.

Condensate, we're hearing a lot more about that becoming a bigger and bigger issue, and even in some parts of west Texas where it's being rejected.

I was wondering, what are you seeing along the Gulf Coast or any other part of your operation, in terms of condensate?

Are you having any rejection issues, in terms of what's being delivered to the units?

And then what your thoughts are on how Valero may deal with the condensate issue, not worrying so much about the industry with condensate splitters, et cetera?

Roger, this is Gary Simmons.

I would say in the gulf we haven't had too much of an issue with getting light material to our crude units.

We've taken a hard look at the condensate.

We don't really see that the discounts are wide enough to really warrant a capital investment, to be able to run a lot larger volumes of condensates in the Gulf Coast.

We are taking a heavy look at this in the Permian Basin in some regions, and getting with producers and seeing where they're seeing the production, to see if there is some opportunity, but right now we don't have anything planned.

Okay.

Thank you.

Thank you.

And then our next question is going to come from Evan Calio, from Morgan Stanley, go ahead.

Your line is open.

First congratulations to Bill and Gene on your careers and your retirement, and to Joe in the new role, come May.

My first question, really for Bill, and it's a more general and somewhat reflective question.

As you think about your 40-plus year career with Valero and its predecessors, and a lot has changed and how do you think about the current Valero and how it stacks up relative to your history?

And just your outlook today for the Company versus other periods of time?

Okay.

Well, the independents are a bigger segment of the business today than it used to be, for sure, and I think that will continue.

So that's one of the major changes in refining, is that the independent segment has far more weight, and I think we react quicker to market influences.

But Valero, we're a company that has put together a bunch of assets and a bunch of people.

Some of those assets were underinvested in.

Some were operated very poorly.

But we come together with one culture, and we have one goal, and it's really to perform with excellence.

We've improved our operations tremendously over the last few years.

We're a far more reliable operator, a much, much better operator, and that thanks goes to our people being very focused on excellence, respect for each other, hard work, safety, and teamwork.

Valero is one company, and knowing our history, you know all the acquisitions, but we're one company.

This business, though, it's going to continue to be volatile.

It will be seasonal.

But it's made up of very hardworking people, and I always like to point this out to people, this industry pays taxes, and we give a product to society that makes people's lives better.

The world needs the oil and gas, regardless of the rhetoric that people talk about.

Oil and gas is inexpensive, and it -- I mean, frankly, the developing world has to have oil and gas.

All the alternatives, and we know them all, and we know all the cost structures, and except for ethanol, that has been able to work in to the fuel mix, all the rest of these alternatives are too expensive, inefficient, and will do absolutely nothing to improve the environment.

And it's a waste of money.

Well, I think we're very competitive, we're very well or competitively positioned, and we add value to society.

And Valero has a very bright future, and no question that the crude oil and natural gas that's happening in North America is the biggest thing in my career, and I'm sure in Gene's as well, and it's having a tremendous influence on all manufacturing in the United States that people thought was really lost forever.

Because the jobs in our industry really do allow people to own their home, educate their kids, and retire with benefits.

That's great.

I have a second question.

There's a current debate regarding the impact of current PADD 3 crude inventories.

They're well above five-year highs and continuing heavy turnaround through the second quarter of this year.

And just how full the system might be, as it relates to Gulf Coast crude differentials.

I know PADD 3 is a big place.

I was wondering if you could comment on what you're seeing in the physical inventory market.

I know you talked on the condensate side, but how many tank tops or general inventory levels, that you're seeing in various Gulf Coast storage regions.

I'll leave it at that, thanks.

Evan, this is Gary Simmons.

If you look at the DOE stats from last week, we were at 209 million.

When we combined refinery tankage with third-party terminals, we would say that the working capacity in the gulf is somewhere in the 275 range.

That puts you about 76%, Evan, for all working capacity that's being utilized today.

We're not seeing problems in the gulf.

There are some areas that it does appear, starting to get pretty full, with the SPR release.

Loop seems pretty full.

One of the things that we're seeing is our barrels are showing up faster than they used to.

So the third-party terminal operators aren't sitting on inventory.

They're turning those barrels pretty fast, and they're showing up at our refinery sites a little bit faster than what we have seen in the past.

But no real issues that we've seen thus far.

Great.

Appreciate it.

Thank you.

And then our next question is going to come from Edward Westlake from Credit Suisse.

Please go ahead, your line is open.

And let me also say congratulations, $6.50 is the EPS consensus, so not quite the $8 you guys did in the boom times, but certainly Valero looks like in good shape.

Just a follow-on question on the MLP.

I mean, obviously, it's a great currency as well.

Not just for what you can drop down into it, trading at a 2% yield.

Maybe think a little bit more broadly about talking to us about what do you envisage the MLP to allow you to do over the next several years, potentially, [ex M&A], as well as the drop-downs?

Thank you.

Okay.

And this is Joe.

It's a good question.

I mean, obviously, the drop-downs are the primary focus for the strategy in the short-term.

We do realize that we have got a very competitive currency to use to do other transactions.

I think if you look at the logistics investment that Valero is making this year, and will continue to make next year in docks, we even have the rails, we have pipe investments that we're making and looking at.

We're going to continue to build the logistics portfolio at Valero Energy that will allow us to look to drops for an extended period of time, which really just eliminates the need to go into the market and pay a premium for assets.

We find that to be a great benefit to us.

But, we would not hesitate to look at what's available in the marketplace, and to consider those assets, and the need to acquire those assets, but we felt that they fit into the system, and they were really assets that Valero Energy felt good about being able to make commitments to that provided that sustainable, ratable, cash flow stream going forward.

Okay.

And then a specific question on the condensates being the theme so far with this call, but say you look at your sort of more mid continent refineries, the Ardmore and McKee, as you look at the crude that's coming into those refineries, presume, say, it's a WTI mix, a lot of refiners are starting to complain that WTI isn't the same WTI it used to be, because obviously, condensates are being spiked into it.

Do you have any color on how the sort of gravity of that WTI has changed over time, or where we are against the 42 API spec?

Yes, I'd say both at both Ardmore and McKee, we definitely see a trend toward the crude getting lighter, and it has caused some operating issues for us, some constraints where we have to cut rates, because the gravity of the crude is getting higher.

So we try to control that the best we can, with working with producers, to control the quality of the barrels that we're getting.

But we have seen issues with the barrels getting lighter.

I mean, I guess I lost the direct question I should have asked, which is, do you think there will be a point where the really light crude will need its own infrastructure rather than being blended into the TI stream?

Yes, I do.

I think, ultimately, we'll have to do that because the refineries can't reject the light ends.

But how that structure comes out remains to be seen.

I'm not necessarily sure you're going to see a gathering system, but you may see some type of fractionation that occurs that allows it to move from the field economically into these hubs, and then gets addressed at a hub before it then moves to the refiners.

There's a lot of, a distinct -- you wouldn't necessarily think you're going to have a whole pipeline network to handle this.

But you may have fractionation occur at different places in the system, including at the refinery.

Which would be an opportunity for you in the MLP.

That's right.

Okay.

Thank you.

Thank you, and then our next question is going to come from Jeff Dietert from Simmons.

Please go ahead, your line is open.

My congratulations to Bill and Gene, and appreciate all your education and knowledge, and being industry statesmen for the last many years.

I'd like to focus on some of the medium sour crudes on the Gulf Coast.

I think there's been a lot of discussion about light crudes coming in, and more competition between light and medium.

Yet, when you look at Mars, it's trading 5.5 under LLS, which is wider than average over the last 18 months.

And you look at Thunder Horse, Southern Green Canyon, some of the other medium sours, and they're trading at nice discounts as well.

Obviously, the 700 a day Keystone South pipeline has started up, and we have SPR putting medium crude into the market.

Could you talk about how significant these factors are, and maybe other considerations you believe are driving the wide discounts for medium crudes in the Gulf Coast, and maybe how sustainable that weakness will be?

Yes, I think we've been fairly consistent in our view that the medium sours and the heavy sours will have to trade at a quality-adjusted differentials to the light sweets, and as the light sweets are pressured down, the medium sours and the heavy sours are going to have to follow.

I agree with your comments certainly in the short-term, the medium sours, probably the SPR release pressured the medium sours down in the gulf a little bit more than what we had seen, especially in the first quarter.

But overall, I think we'll see that trend continuing.

And are your LPs arguing that you should run near maximum rates, given where discounts are, and crack spreads are, and just looking at the high levels of inventory, reasonable US demand and increasing product exports?

Yes, I think as Lane commented, the LPs are really pushing towards maximum utilization across the system.

Thanks for your comments.

Thank you.

And then our next question is going to come from Paul Sankey from Wolfe Research.

Please go ahead, Paul, your line is open.

Bill and Joe, congratulations indeed to both of you, and again, as others have said, thanks for being so much fun to deal with over the years, and so interesting to deal with.

Could we just talk a bit about Gulf Coast again?

Sorry to go back to this, but the throughput number, could you just remind me what that was, in terms of what you expect it to be in the second quarter?

Could you just repeat to make it easier what you did in the first quarter, and then could you also talk about what your capacity is now on the Gulf Coast, what you think your refining throughput capacity is overall?

Thanks.

Yes, Paul, in the first quarter, our throughput was 1.585 million barrels per day.

Our guidance, for the second quarter is 1.42 million to 1.47 million barrels per day, and -- hold on one second, I'm going to get an updated capacity.

Capacity is at around total throughput, just over 1.6 million barrels per day.

Yes, okay, so I have got that 1.6 million, and then I think it was officially 1.54 million last year, and sorry to be so detailed here, I think you gave a light sweet throughput capacity as well for that system?

Right, Paul.

This is Lane Riggs.

Just in the Gulf Coast is about 480,000 barrels a day.

For you guys?

Yes.

Okay.

That's interesting.

The outlook for that as we move forward.

First, I guess that's a turnaround number in Q4, that's the reason why you're so much lower, but then I suppose we're going to go back up to a much higher level of utilization through the rest of the year, Q3 and Q4.

And then when we move forward beyond that, is your capacity going to increase, let's say, into 2015, or do you think you've reached a steady state, firstly for the overall capacity, second for the light sweet?

Thanks for the detail.

Yes, Paul, this is Lane again, we have the two crude unit projects.

Everything you said is true.

But in terms of projects we have in terms of our pipeline of projects is our crude expansion, for both Corpus Christi and Houston, both of which would be similar finish toward the end of next year.

So the capacity of those 90,000 barrels a day at Houston and 70,000 barrels a day in Corpus in terms of our additional capacity, were on light sweet.

And they would be at the end of 2015?

Yes, we're calling early 2016.

So when those are operating.

Okay.

Great, and then the other question I had for you is just related to the further outlets, the light sweet crude in terms of exports, can you just, again, on a look-forward basis, talk about how much more oil you guys will be using in Canada?

I know that there's some line reversal stories as well as some shipping stories.

Thanks.

Yes, so you know what we have said is our Canadian refinery should be at a 100% domestic light sweet by the end of the year.

We're still on pace to complete that.

We're a little bit ahead of schedule.

We probably have about 130,000 barrels a day of capacity that we haven't utilized yet for the domestic light sweet.

So we could take Lane's number in the gulf of 165 in the gulf, plus 130 at Quebec here, and this 295 range of capacity that we still have to absorb light sweet crude, absent the capital program that we have.

And is that the limit on what you can do, absent the capital program?

I mean, the only crude that you'll take up there is for your own use in your own refinery?

I guess I don't understand what you're asking.

Well, you mean we can ship up there and sell it to one of the other refineries in Canada?

Yes, exactly.

Of course we can.

Our permit allows us to ship it to all four, I think Irving, and [Kombutche] and there's somebody else.

I think there's four anyway.

Okay.

Great, and if I could slip a final one in, Bill, because it's presumably your last call, do you want to talk about how things have changed, and what you think the outlook is in Washington, DC?

Particularly, I'm wondering if you think we'll be able to export condensate in relatively short order?

And then longer term, whether you feel that in due course, potentially if prices in the US get very low, we may be exporting crude as well?

And any other thoughts you have on what's going on in Washington?

Thanks.

Well, I do accept that the groundwork is being laid for condensates to be an issue.

And that's all a definition of what crude oil is, and then the question was asked earlier about infrastructure, which is absolutely correct.

So, condensates may need to get addressed at some point.

As far as exporting of crude, though, the industry is running the oil, the discounts we have in the marketplace today are really because of logistics in many of these markets, and we're doing things, and I'm sure every one of our peer group are doing things to be able to run more oil.

And then, we support the free markets, but you need to remember that this business isn't very free.

There's lots of restrictions from the Jones Act to the cartels, to everything else that goes with it.

So I think it remains to be seen, but under the law, there's a lot of flexibility.

You can re-export Canadian crude, you can get licenses for that.

As Gary just spoke, you have licenses to send US domestic crude to Canada.

There's also possibilities of exchanges, if it becomes so much.

But the thing I think that people need to remember is this is a windfall for North America and the United States as far as manufacturing, whether it's natural gas liquids, natural gas, or crude oil.

And we can have a manufacturing boom, the petrochemical industry can boom.

Where do you build petrochemical plants?

Resource advantaged; consumer advantaged.

The US is now resource advantaged.

So this is a huge opportunity for jobs.

We have a lot of rhetoric about jobs.

Here is a real area for jobs.

Job training, huge opportunities for welders, pipefitters, instrument techs, operators, that was not here just five years ago.

So this question of exports, and how our country should conduct themselves, especially when you see the turmoil in the world that we have going on, I think should take a lot of stuff.

And I think it will.

Great.

Thanks for your philosophy.

Thank you, guys.

Thank you, and our next question is going to come from Faisel Khan from Citigroup.

Please go ahead, your line is open.

If I could ask a question on the heavy oil consumption in the Gulf Coast, just with all the things going on in Venezuela, what are the risks to you guys, the volumes into your facilities from heavy crude, you're taking from Venezuela, and then to sort of counter that, can you give us an update on how much heavy crude you're bringing down from Canada, specifically through the pipeline, into Port Arthur as well?

Yes, so our heavy sour volumes were fairly consistent from the fourth quarter to the first quarter.

You brought up Venezuela; we did choose to allow our heavy sour inventories to creep up a little bit in the first quarter, in case we had a supply disruption from Venezuela.

But we haven't seen any changes that would indicate that we would have a risk of supply loss from Venezuela.

The Canadian values, our Canadian volumes were down in the first quarter, and that was mainly just a matter of pricing.

The Canadian production, the heavy Canadian production was down somewhat due to weather, and then demand was also a little higher with BP Whiting's coker coming online.

We didn't see the economic incentive to run the Canadians in the first quarter that we had seen, and the fourth quarter and [earlier].

That incentive is starting to come back, and so we are ramping the Canadians back in to Port Arthur here in April.

Understood.

And can you also give us an update on what your strategic thinking is with the California assets?

Has that changed at all, and is there a process going on, or how are you guys thinking about those particular assets?

Well, in California, obviously our financial performance is not that great.

It is our weakest group of assets now, financially.

Operationally, though, it's excellent.

We have very solid assets; they're operated very well.

We continue to make improvements on those assets.

And so when you look at the basic issue of supply and demand, where demand has not really recovered out there at all from pre-grade recession, although we're starting to see some improving economy and some uptick in demand, the focus that we have is to work on our crude costs, and to continue to work on the operating costs, and of course, adjusting our yields to fit the market.

So we view it as some of our competitors publicly have stated that in a way, it's an option value out there.

It's a huge market.

The LA basin is still absolutely a huge gasoline market, and so the market's there, we just need it to show a little bit of growth back to levels it was before.

Okay.

Understood.

And then last question for me, can you give us an update on the methanol plant and oxylation unit projects, and when you might think of sanctioning those projects?

This is Lane Riggs.

Where we are, we're in what we would call between our phase two and phase three process in terms of working on methanol, which means we're doing a more detailed engineering to get a better cost estimate, fine tune our economics.

We will bring the project forward for a phase 3 review around November of this year, and we'll probably have a go-no go on the project at that time, but so far the project has looked very favorable.

And so there's no show stoppers at this time, with respect to that project.

Okay.

Great, I appreciate the time.

Thank you.

And then our next question is going to come from Doug Leggate from Bank of America - Merrill Lynch.

Please go ahead, your line is open.

Bill, Joe, and everybody, congratulations, you've been a great educator, Bill, for the industry, and we'll miss you for sure.

Good luck to all of you.

My two questions, if I may, first of all on the Gulf Coast, I think Lane made a comment earlier about Valero's refinery utilization.

I would like to go to the industry utilization, we have seen this huge build in crude inventories, but we have also seen our step changing utilization rates, and as I look at it, if you want to characterize it as supply days of crude on the Gulf Coast, they're actually near the lowest level seasonally that we've seen in quite some time.

I'm wondering if you could comment on that, and what it means for working capital for the industry and for Valero specifically, as you move through utilization rates higher on the Gulf Coast.

I have got a follow-up, please.

This is Lane, I'll take a little bit of a shot at that.

The days of supply, I'll defer to my friend here to the left, Gary, but in terms of -- we absolutely have had a, if you look at our crude margins, from the LP guide, we have had a huge incentive to run through all of the first quarter and that's a little where the margins and refineries exist today.

If you aren't turnaround, or you aren't having any issues, you're trying to run crude.

And not only trying to run crude in your crude stills, for example, we are running crude in some of our LPCs, two or three of our LPCs where we have the ability to run resid, we're running crude in lieu of that.

So the industry is doing quite a bit in terms of trying to run more crude in, because that's where the economics are telling us to be I don't know if you want to comment, Gary.

Yes, the days of supply working capital in general, we generally see our domestic refineries that are taking ratable pipeline deliveries require less working capital than some of our Gulf Coast assets, and our view was, as we switch to more domestic barrels, it would drive down working capital.

I'm not sure.

I think it's a little too early to tell that.

And some of it is, we're not sure what the pipeline line-fill capacities are going to be on some of these new lines to be able to really give you guidance on that at this time.

Yes, I guess what I'm really trying to figure out is -- but all looking at the differential on the Gulf Coast, and there's been obviously a consensus, expectation, that it's going to blow out again, probably for LLS, and it hasn't, at least not in the magnitude in prior quarters, when we've had down time.

And I guess what I want to understand is are you guys seeing the same sort of indicators that we are, which is that days of supply for the system as a whole is actually still quite tight, given the higher utilization rates, or are you not seeing that at all?

It appears to me that the market in the gulf is well supplied today, so I don't know that I've actually looked at it, in terms of days supply, but the market seems well supplied.

Okay.

My follow-up, hopefully a quick one, more Valero specific.

The comment you made earlier about you're seeing a lightening of the crude slate for WTI specifically, and that's becoming more problematic, I guess, in terms of filling up some of your secondary units, can you talk about what that's doing to your capture rates, relative to the legacy capture rate of the system?

I guess what I'm trying to get to is we have seen capture rates drift a little lower versus indicators, and I'm wondering if that's got something to do with it, in terms of the incremental challenges you're having on running those crudes, and I'll leave it there.

It's difficult for me to comment exactly what that does, in terms of running lighter, in terms of where the capture rates go, we could look at that in more detail.

I'll take it offline, thanks.

Thank you.

And then our next question is going to come from Sam Margolin from Cowen and Company.

Please go ahead, your line is open.

I'll just echo the congrats to Bill, Gene and Joe, not a whole lot I can add, but I would be remiss if I didn't say thanks, and I think it's going to continue to be --

Hey, Sam, you might have to rejoin.

We're hearing some weird feedback coming through.

Is it better now?

Every time you do it it sounds like you're playing a video game.

Really?

Yes, yes, you might have to rejoin.

We'll wait for you.

Okay.

Thanks.

And our next question is going to come from Blake Fernandez from Howard Weil.

Please go ahead, your line is open.

Hopefully you can hear me better.

Sounds good.

Congrats also to Bill, Gene and Joe.

It was great working with all of you guys.

Two quick ones for you.

One, you mentioned the Quebec refinery, and potential reversal of line nine, and of course, I know you barge in Eagle Ford crude up there as well.

I'm curious if you could talk about how you see the economics unfolding.

I guess I have always viewed pipeline as more efficient than barging crude, although I believe you outlined about a $2 cost of margin on a non-Jones Act vessel.

I'm just curious, once the line comes on, do you think we'll reduce the amount of Eagle Ford barge crude up there?

Blake, this is Gary Simmons.

I guess the way we would see is it that the pipeline deliveries would be the most advantaged, and then second to that would be the barrels that we get over the water, and then finally, would be the tranche that we're currently taking by rail.

If barrels started to drop off, it would probably be the rail volume that you would see fall off before the volume that we're taking over the water.

Great.

The second one for you, quickly, there's press reports out there that the Milford Haven refinery will be closed next month.

Obviously you'll get a direct benefit at Pembroke, with those volumes being offline, but I'm just curious if there's any opportunity to maybe buy some units or specific assets from that facility that would enhance Pembroke's performance?

It's Klesse.

We're fully aware of what's going on there, and we're not sure how this is all going to work out, and if there is an opportunity for us to improve our situation at Pembroke, we'll take a look at it.

But as of today, we don't have anything going on.

Okay.

Fair enough.

Thank you.

Thank you.

And our next question is going to come from Chi Chow from Macquarie Capital.

Please go ahead, your line is open.

Thank you.

I want to go back to the Canadian strategy, and it's been reported you've got this application for a re-export license of Canadian crude.

First, have you received that permit yet, and then secondly, can you just discuss the strategy with the permit and what's the strategy on moving volumes out to either back up like us to Quebec or out to Pembroke?

From what I understand, that's part of the permit as well.

This is Gary Simmons, we do have the permit in place.

Some of that, why we went out and got that, actually, when we were having the weather problems, moving the Canadian barrels by rail to Quebec, we wanted to be able to shift that volume, and move the rail volume to the gulf and then be able to bring it up over the water to Quebec, and we weren't allowed to do that, so this permit will allow us to do that.

Certainly at some point in time, we could also look at taking volume to Pembroke, but today we don't have any plans to do that, at least in the short-term.

Does the permit allow you specifically to move to Pembroke only, or is it open to destinations within Europe or the UK?

I'm not sure on the specifics for that.

I think in the permit, you actually identify, and I believe we have nine different places we're allowed to take it in the permit.

And you actually have to specify, and so you asked the philosophy or strategy question, the strategy is to have flexibility.

We have the assets going in place with rail at the US Gulf Coast that allows us to keep the crude oil neat, and that will allow us then to go ahead and keep it segregated, and then if the economics are there, we have flexibility in our system.

Okay.

Bill, the nine different places, are they all within your own facilities at Valero?

No, they're not.

I'm just wondering, isn't it in your best interest to keep as much crude in the gulf as possible?

And at what point would you look to execute on this permit and move the crude out?

It's all flexibility and this is about economics, and we would do exactly what you're leading to, is all this in our self-interest for our shareholder?

Okay.

Thanks.

And I guess second question, can you give us the product export volumes in the first quarter, and what the capacity is for both gas and diesel at this point?

Sure.

This is Gary Simmons again, and in the first quarter, we exported 208,000 barrels of distillate.

We would say that our capacity today is close to 325,000.

We have some capital projects in the work that will bring that up to 425,000.

And the gasoline side, we exported 124,000 barrels a day of gasoline in the first quarter.

And that capacity is probably in the 225,000 range.

It will also go up to about 250,000 with some of the dock work we have going on.

Thanks, Gary.

Any timing on the increase in the capacity on both products?

Yes, so the dock work is probably a year to two years away from being complete.

Okay.

And then one final question on the exports, have you noticed any impact from some of the new refineries that have come into the market, and most notably, the Jubail plant in Saudi Arabia?

We still see a margin today, a good margin to export, when you take the RIN into account, and we're finding plenty of homes to take the barrels, so I don't say that -- I can't say that we've seen a big impact from that.

Okay.

Great.

Thanks a lot.

Thank you.

And our next question is going to come from Sam Margolin from Cowen and Company.

Please go ahead, your line is open.

Hey, coming through okay?

Sounds good.

Great.

Okay.

Thanks for letting me back.

I'll keep it tight.

I wanted to -- I think it was brought up earlier, the connection between utilization and capture rate, I think one of the moving parts there might be intermediate feedstock costs?

It seems to be one of the last remaining structural challenges.

I bring it up because you guys are addressing it with the crude units, and I was just curious if any of those economics are changing, if there's an opportunity at this stage to make them bigger, or add another one, or even drop them down and put a toll on it, because the commodity structure is looking more favorable?

Sam, this is Lane Riggs.

Our crude -- both crude units that we did were as big -- as large as they could be, and under the greenhouse gas permit.

We don't have the opportunity to make them larger at this point in time without going through the process of getting a greenhouse gas permit.

Okay.

And then, I guess I'll just bring up Maya Brent spreads have been pretty favorable.

I think some of that has to do with WTS, and the Midland, I guess, leakage of the prices locations there, and when the pipeline and infrastructures start to come online out of West Texas, and maybe Midland normalizes closer to other benchmarks and WTS comes with it, if you guys are expecting any kind of weird price action in Maya maybe in the third quarter, and if there's something we should prepare for, or try to bake in ahead of time to our estimates.

I think with the Maya formula, there's always that risk that if Midland comes into Cushing, that it could affect the Maya formula in the short-term, but we believe they're trying to price their crude so it can be competitive with Mars, and so that even if Midland comes in, they will eventually adjust the K to keep their crude competitive with the medium sour alternative.

Thanks so much.

Have a good one.

Thank you.

And then our next question is going to come from Cory Garcia, from Raymond James.

Please go ahead, Cory, your line is open.

I want to echo everyone's thoughts and best wishes going forward for Bill and Gene.

Most of my questions have already been answered.

As a follow-up to Faisel's earlier, Lane, do we have any sort of no -- go-no go time line on the Alky unit that you guys have talked about?

Obviously a little bit lower scope and scale of a project, but just wondering if you have a similar sort of thing for us to at least keep an eye out for?

It's always on a similar time line.

We'll have the same sort of review in the fourth quarter with Management, and make a similar decision.

Okay.

Perfect, thank you.

Thank you.

And we have no further questions at this time.

So listen, for those of you still on the call, and it was mentioned several times, but this is Gene and my last call with you all, and I just want to -- and Gene and I both want to tell you guys, thank you very much for the interest you've shown in Valero, and we wish all of you all the best going forward.

So thank you very much for that.

Okay.

Thank you, Bill.

Thank you, Bakiba.

And we appreciate everyone calling in and listening to the call today.

If you have additional questions, please contact our investor relations department.

Thank you.

Thank you.

Ladies and gentlemen, this concludes today's conference.

Thank you for participating.

You may now disconnect.