瓦萊羅能源 (VLO) 2018 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Q1 2018 Valero Energy Corporation Earnings Conference Call.

(Operator Instructions)

And I would like to introduce your host for today's conference, Mr. John Locke.

Sir, you may begin.

Good morning.

Welcome to Valero Energy Corporation's First Quarter 2018 Earnings Conference Call.

With me today are Joe Gorder, our Chairman, President and Chief Executive Officer; Mike Ciskowski, our Executive Vice President and CFO; Lane Riggs, our Executive Vice President and COO; Jay Browning, our Executive Vice President and General Counsel; and several other members of Valero's senior management team.

If you've 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.

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

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

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

Now I'll turn the call over to Joe for opening remarks.

Well, thanks, John, and good morning, everyone.

We started the year with bullish fundamentals, healthy product demand and days of supply for total light products below the 5-year range.

However, as the quarter progressed, winter storms, fog along the Gulf coast and strong refinery utilization delayed seasonal product draws, creating some margin headwinds.

But despite these challenges, Valero performed well and delivered solid financial results.

As you know, we've been investing growth capital in logistics projects.

An excellent example of this is the Diamond Pipeline, which is running well and enabling us to capture additional margin into our refining system.

We increased pipeline throughput during the quarter, which provided our Memphis refinery with greater access to Cushing and Midland crudes that are cost advantage versus LLS.

We made additional investments in logistics to further reduce secondary costs and increase margin capture.

We acquired the SemLogistics Milford Haven fuels storage facility in Wales.

We also entered into a joint ownership agreement with Sunrise Pipeline LLC, a new pipeline connecting Midland and Wichita Falls, Texas.

Construction also continues on the Central Texas pipelines and terminals and the Pasadena products terminal.

We expect these investments to improve flexibility and product and feedstock supply in our refineries when completed in 2019 and 2020.

Turning to our refining investments.

Work remains on track for the Diamond Green Diesel capacity expansion and the Houston and St.

Charles alkylation units.

These projects should start up between the third quarter of this year and 2020.

In addition, our Board of Directors approved the construction of a 45-megawatt cogeneration plant at the Pembroke refinery.

We expect to see lower operating costs and improved electricity and steam supply reliability when the project is completed in 2020.

Turning to cash returns to stockholders.

We paid out 57% of our first quarter adjusted net cash provided by operating activities.

And we continue to target an annual payout ratio of between 40% to 50%.

In closing, we remain optimistic about the margin environment for the year.

Global economies are growing.

Product demand is strong, particularly in Latin America.

And days of supply for refined light product inventories are below 5-year averages.

With our highly reliable and flexible refining system, we are well positioned to capture margin tailwinds arising from these positive trends.

And with that, John, I'll hand the call back to you.

Thank you, Joe.

For the first quarter, net income attributable to Valero stockholders was $469 million or $1.09 per share compared to $305 million or $0.68 per share in the first quarter of 2017.

First quarter 2018 adjusted net income attributable to Valero stockholders was $431 million or $1 per share.

For reconciliations of actual to adjusted amounts, please refer to the financial tables that accompany this release.

Operating income for the refining segment in the first quarter of 2018 was $922 million compared to $640 million for the first quarter of 2017.

Excluding $170 million benefit from the retroactive Blender's Tax Credit and $10 million of expenses primarily related to ongoing repairs at certain of our refineries to address damage resulting from Hurricane Harvey in 2017 and other increment weather conditions in the first quarter of 2018, operating income for the first quarter of 2018 was $762 million.

The increase from 2017 is attributed primarily to higher distillate margins, which were partially offset by narrower discounts for medium and heavy sour crudes versus Brent.

Refinery throughput volumes averaged 2.9 million barrels per day, which was 93,000 barrels per day higher than the first quarter of 2017.

Throughput capacity utilization was 94% in the first quarter of 2018.

Refining cash operating expenses of $3.78 per barrel were $0.09 per barrel lower than the first quarter of 2017, mainly due to higher throughput in the first quarter of 2018.

The ethanol segment generated $45 million of operating income in the first quarter of 2018 compared to $22 million in the first quarter of 2017.

The increase from 2017 was primarily due to stronger distillers gain prices.

Operating income for the VLP segment in the first quarter of 2018 was $84 million compared to $70 million in the first quarter of 2017.

The increase from 2017 was attributed mainly to contributions from the Port Arthur terminal assets and Parkway Pipeline, which were acquired in November of 2017.

For the first quarter of 2018, general and administrative expenses were $238 million and net interest expense was $121 million.

Depreciation and amortization expense was $498 million, and the effective tax rate, excluding the retroactive Blender's Tax Credit, was 22% in the first quarter of 2018.

With respect to our balance sheet at quarter end, total debt was $9 billion and cash and temporary cash investments were $4.7 billion, of which $71 million was held by VLP.

Valero's debt-to-capitalization ratio, net of $2 billion in cash, was 24%.

At the end of March, we have $5.4 billion of available liquidity, excluding cash, of which $750 million was available for only VLP.

We generated $138 million of net cash from operating activities in the first quarter.

Included in this amount is $1.1 billion use of cash to fund working capital.

Excluding working capital, net cash provided by operating activities was approximately $1.2 billion.

Moving to investing activities, we made $631 million of growth and sustaining capital investments, of which $448 million was for expenditures to sustain the business, including $220 million for turnaround and catalyst costs.

The balance of capital invested in the quarter was for growth.

With regard to financing activities, we returned $665 million to our stockholders in the first quarter.

$345 million was paid as dividends with the balance used to purchase 3.5 million shares of Valero common stock.

As of March 31, we have approximately $3.5 billion of share repurchase authorization remaining.

Capital investments for 2018 are expected to total $2.7 billion with about $1.7 billion allocated to sustaining the business and $1 billion to growth.

Included in the total are turnarounds, catalysts and joint venture investments.

For modeling our second quarter operations, we expect throughput volumes to fall within the following ranges: U.S. Gulf Coast at 1.61 million to 1.66 million barrels per day; U.S. Mid-Continent at 460,000 to 480,000 barrels per day; U.S. West Coast at 280,000 to 300,000 barrels per day; and North Atlantic at 355,000 to 375,000 barrels per day.

We expect refining cash operating expenses in the second quarter to be approximately $3.85 per barrel.

Our ethanol segment is expected to produce a total of 4 million gallons per day in the second quarter.

Operating expenses should average $0.37 per gallon, which includes $0.05 per gallon for noncash costs such as depreciation and amortization.

For 2018, we continue to expect the annual effective tax rate to be about 22%.

For the second quarter, we expect G&A expenses, excluding corporate depreciation, to be approximately $180 million.

Net interest expense is estimated at $120 million.

And total depreciation and amortization expense should be approximately $520 million.

Lastly, we expect RINs expense for the year to be between $500 million and $600 million, which is approximately $200 million lower than previous guidance, primarily due to lower RINs prices.

That concludes our opening remarks.

(Operator Instructions)

(Operator Instructions) Our first question comes from the line of Doug Terreson with Evercore ISI.

So first, I want to say congratulations to Mike and I have enjoyed working with you over the years and good luck in the future.

First of all.

Thanks, Doug.

And my question is on IMO 2020 and specifically how you guys are thinking about the type of products that are likely to be provided to the market as it seems that many fields are still in the design phase and there is a lot of uncertainty in that area?

And on marine field blends, how challenging the issues of compatibility, stability and availability of supply along these marine field networks are likely to be as the market goes through the transition in coming years?

So 2 questions on IMO 2020.

Yes, Doug, this is Gary.

I think, well, I'll start with the latter part of it.

I think you really hit the nail on the head with -- in terms of the challenges on IMO and the field quality.

A lot of these blends, it's about stability of the fuel.

And so we are certainly doing a lot of work in that area to understand some of these blends and things that can be done to be able to produce the 0.5 wt% spec.

But because of lot of those challenges, certainly the industry today is pointing more towards a lot more ULSD in the marine bunker business and that's the reason it's the stability of the fuel.

And our next question comes from the line of Brad Heffern with RBC Capital Market.

Joe, on the repurchase front, obviously, the stock is up almost 70% over the past year.

At some point, is there a change in the calculation there where some of the cash looks more attracted to M&A or maybe to the dividend or some other use rather than the repurchase or is it really just a flywheel for excess capital?

Yes.

It's the latter.

And the capital allocation framework we've used now for several years just remains in place.

We'll continue to invest for growth.

We'll continue to maintain our commitment to the dividend.

And we'll use surplus cash for cash -- share repurchases.

That being said, if we saw a transaction out there that we thought was excellent and that provided synergies for the company, we wouldn't hesitate to approach it.

But that's been part of the model, the framework now for several years.

So I don't expect anything really to change going forward.

Okay.

And then maybe for Gary, I'll ask another IMO question.

Obviously, we're all consumed with all the positive potential benefits from that.

Are there any offsets that you guys are thinking about?

I'm particularly thinking about if industry runs, move up a lot in order to meet the -- that is flip side of the equation, are we going to see weakness in gasoline?

But any other thoughts along those lines will be helpful.

No, I think that we're -- we actually feel that IMO will be supported in the gasoline cracks as well, and the reason for that is a lot of the low-sulfur feedstocks that are going to cat crackers today to produce gasoline, you want to pull those into make the low-sulfur marine bunker oil spec.

So I think, overall, IMO is very supported to both gasoline and distillate.

And our next question comes from the line of Neil Mehta with Goldman Sachs.

I just wanted to start with a big thank you to Cisko.

You came into the role 15 years ago.

We look this morning, the stock is up 1,300%, over 4x the market, before even looking at the dividends.

We know the right hasn't been linear, but it's been a great one and we appreciate your steady hand at the helm of financial ship.

Neal, Don has got a high bar to jump over.

Well, guys, the questions I had here were all in the crude differential, you guys have unique perspective on this.

And first one, start on the light side.

So we've seen WTI Midland really widen out here in 2018.

You guys have a good perspective on this, especially now with your involvement with Sunrise and with very new -- few new pipelines coming into, let's call it, the back half of 2019, there is investor concern, certainly, on the producer side that these differentials really could widen out towards trucking economics.

So want to get your perspective on what's going on in the Midland?

Is there sufficient trucks to ultimately move the crude from West Texas down to the refining centers at Corpus Christi?

Is there -- are there constraints?

And how does this all kind of play out?

And then have a follow-up on the heavy side.

Okay, Neil, this is Gary.

I think when you look at kind of what's happened to the Midland market over the last 6 months.

November, we had the Enterprise Sealy -- Midland-to-Sealy pipeline come on with 450,000 barrels a day of takeaway capacity.

As that started up, the Midland-Cushing spread came in fairly narrow.

And then we continue to see production ramp-up, which as production ramped up, pretty much all the pipeline capacity at either Cushing or to the Gulf Coast was again being consumed.

And then in the first quarter, I think, compound all that, you had some refinery maintenance in the Mid-Continent.

And so some of the demand for some of those Midland barrels, it's typically there, went away.

And so the Midland-Cushing spread really widened out.

I think we see -- what we see is that as refining capacity comes back on in the Mid-Continent, that Midland-Cushing spread will come back in some.

But as you get out later this year and early into '19, it does look like once again production will ramp up to the point where logistics will be a limit and will be in for a period where that Midland-Cushing spread will be relatively wide until the next pipeline project come online.

And do you've a view, Gary, in terms of how much it'll cost a truck crude from West Texas down to the Gulf Cost assuming that is the marginal barrel?

We did a little bit of that when the differential blew out several years ago, and I don't remember what the numbers are, Neil, but it's expensive to move by truck.

All right.

Great.

And then follow-up questions on the heavy side.

We've seen these Canadian differentials tighten up here.

It's going to be a big turnaround season in May and June.

But production looks like it's going to keep on ramping towards the end of the year.

So just thoughts on Western Canada?

And then also LLS Maya, which has increased despite some of these Venezuela issues would be helpful.

Okay.

I will start on Canada.

Yes, I think we saw Canadian differentials really blow out and then have since come in some.

We had the Fort Hills production come online.

And so increase in production, you were definitely limited on the logistics to be able to crude the barrel.

Some of it was increase in production, but we also had -- Keystone had a pressure restriction, which derated that line.

And then a lot of issues around the rail, both weather-related issues around rail and also the lack of locomotives.

So then as we moved further in the quarter, we saw some seasonal maintenance being occurring up in Western Canada, which lowered production.

At the same time, Keystone was able to restore their capacity.

We've seen some improvement in the rail.

So those differentials have come back in some.

But ultimately, I think we view that production in Western Canada will outpace the ability to clear that barrel until one of the cross-border pipelines comes on, which is more a 2020 discussion.

I think you'll see relatively wide discounts in Western Canada on those barrels.

At the Maya LLS, I think when you look at Maya and the Maya formula, you know a lot of the components of the Maya formula contributed to Maya moving weaker.

WTS moved weaker.

Fuel oil moved weaker.

And the Brent TI arb widening out, all contributed to Maya moving weaker.

And certainly, they can correct that with adjustments to the K, but what we saw in the first quarter was a lot of their demand was down due to U.S. Gulf Coast refinery maintenance.

And so they were actually long production.

And with them being in a position of having linked, I think they were reluctant to change the K. And so we saw Maya very competitively priced during the quarter.

And our next question comes from the line of Paul Cheng with Barclays.

First, I want to really say congratulations to Mike and wish you a wonderful time on the retirement, but are you sure that you are so young that you want to retire or you're going to do this all the time?

Yes, Paul -- I think Paul, we're little late for that, but -- yes, I appreciate it.

Thank you very much.

Has been a fun ride for all these years that I was not following the sector as long as you have been in the sector, but has been a fun ride?

So thank you for all the help throughout the years.

Thank you.

You're welcome.

I guess, I have 2 questions.

First for Gary.

It seems that people are talking about the IMO 2020.

I'm just curious that have you guys heard anything we needed to the low-sulfur resid.

Would that have any unexpected consequences in terms of the machine?

How they're going to run?

And all that (inaudible)?

And also that have you heard any -- because I heard someone talking about a cheaper new technology, maybe able to directly convert high-sulfur resid to the low-sulfur bunker field without going through the hydrocracker or the cooking technology.

Wondering if you heard anything about that.

So that's the first question.

Second question that how much is the Midland crude you currently will be able to run in McKee and the rest of your system?

And that -- how much more that you think you may be able to get for the pipeline you said?

Do you have any additional arrangement?

Okay, I'll start.

So I think your first question was the impact that running a lower sulfur fuel may have on the ship engines.

I think that we see a lot of the ships today when they get into these areas next to the shoreline, they're burning diesel anyway, and so they have some history on burning low-sulfur fuels.

And I'm not aware of any negative impact that's had on engine wear.

The second part of that question in terms of technology to convert resid to lower-sulfur resid.

I'll let Lane answer.

I mean, I guess, our view is that, I mean our grass roots was pretty expensive to do.

I mean, somebody had to go and try to build something like this and just some where you have to have all the infrastructure.

So one of these looks a whole lot like maybe it's not a resid crack, but it's a resid hydrotreater, we have some experience with those.

They're best used, would be put into an existing refinery.

I don't know if anybody is seriously looking at this.

At this time, I hear a lot of talk about it, but I guess, I'll leave it there.

Okay.

So you're a bit skeptical about the change that this brand -- I mean, I heard someone talking about this brand-new technology may be much cheaper, a 1/4 of the corresponding hydrocracking solution.

So just curious that you guys have any thought on that.

Yes.

I think what I would say is, skepticism is maybe overstating it a bit, I'm just saying, no matter what it would be, it'd be pretty expensive and it would have to be a refiner that would probably have to be able to do this.

And I think everybody wants to -- I think people want to see the market evolve before they commit that much money particularly to a new technology that people aren't familiar with.

Okay.

Very good.

And then, on your Midland question, I guess, Paul, really our capacity to run Midland is, we could run as much of Midland, 1.6 million barrels a day of light sweet capacity we have could be all Midland.

I'm sure what you're getting at is how much of that could we get is actually priced at Midland-type values.

Today, a lot of the crude we run at Ardmore and McKee is priced off of Midland.

We don't devote a number in some of the regions for that is that pricing contracts are negotiable and up all the time.

So that number floats a little bit.

But we run a lot of Midland price crude at both McKee and Ardmore.

And then we recently announced the Sunrise project, which will give us another 100,000 barrels a day of Midland price crude that we can take into Ardmore and McKee.

In addition to that, we're certainly looking at all these pipeline projects from the Permian to the Gulf and evaluating opportunities to get more Midland price crude, both our Gulf Coast system and to the export refineries.

Gary, when Sunrise's up and running will be?

First quarter of '19.

Yes, first quarter of '19.

And our next question comes from the line of Roger Read with Wells Fargo.

And Mike, enjoy it.

You don't have to listen to us, Wall Streeters, too much anymore.

That's great.

I might have detected a little too much enthusiasm in that response.

Shifting gears a little bit here, guys.

Crude's been running up, wholesale price has been moving up, cracks look good.

First time in several years, we're looking at retail gasoline closing in on $3.

What is your thought on where we might see a demand response and kind of how do you -- what experience gives you maybe that confidence?

Roger, I don't know that we have an exact number.

We certainly haven't seen a negative reaction to the street price yet in terms of the demand response.

In our view as always been, certainly, where crude got to be over $100 a barrel there with certainly demand destruction that took place there.

But somewhere, I think, between the $80 and $100 range is when you start to see some demand destruction start to take place if crude gets that high.

It's always muted though.

I mean, if you look at what's really happened and you look at the type of vehicles that are being purchased today, I think Ford has announced that they are not going to make cars, so many cars anymore, and it's because of the demand for light trucks and SUVs.

So Roger, from a practical standpoint, either with the higher price, it'd be difficult for people to moderate their consumption that much based on the vehicles that they're buying today.

Yes, absolutely.

Just always good to get -- somebody's got their hands a little closer to it than the rest of us.

The other question I had, Latin America has been a nice area for margin growth, market share growth for you.

I was just curious, Venezuela from our refining standpoint is, I guess, now finally shut down.

What beyond them backing out of the market have you seen in growth?

In other words, what do you think is probably a true growth rate out of Latin America that we should think about maybe from this point forward, given that, I guess, you would caught a normalized activity level from refining in Latin America from this point forward?

Yes, Roger.

I don't know if I can give you an absolute number.

We can give what here -- what John did give you what that figure is.

But the way we look at it is we kind of looked at a reasonable ramp-up and refinery utilization rates, and we're confident that demand growth in the region outpaces any kind of reasonable ramp up in the refinery utilization.

It's kind of the way we've looked at that market.

But in terms of absolute growth, I'm not sure, I can give you a number what we planned on.

And our next question comes from the line of Manav Gupta with Crédit Suisse.

My first question is last year, Mexico did approach you for a possible help with fixing their assets and offered a percentage ownership.

You did decline the offer.

Can you talk a little bit about what you saw on those refineries because of which you decided not to go ahead with it?

And second one is, I may be wrong on this, but you have a coker project at Port Arthur.

Can you just add some more color about it?

I'm not looking for an EBITDA guidance, but generally some specifics around the project.

Yes, so Manav, let's go ahead, and I'll let Lane talk a little bit about.

Not -- it is not specific just to Mexico, but it's specific to what it would take to turn around a challenged refinery because you know we have tons of experience with that.

So Lane, you want to share your thoughts?

Yes.

To Joe's point, I mean, really all of Latin America has some more or less exposure to the sort of having a lack of, I would say, maintenance capital.

So over time, their operations and their reliability have eroded.

Largely probably because of the flat price in crude, they can't really fund -- they can't fund their operations.

And so depending on how long and how deep that -- sort of that story goes, it takes a long time to recover.

I mean, like some conversations that we've had with some of these counterparties in the past was, it's at least 2 turnaround cycles.

And you really have to -- you have to stare at your management a long time.

There is a lot of work involved in this.

A lot of time, if you think about 2 turnaround cycles whether that's 6 years or 10 years, that typically -- that sort of is a longer duration than a lot of the sort of the political types or certainly the -- given some of the management involvement trying to get this done.

So it's a very, very, very difficult thing to turnaround a refining complex when it's gotten in the state many of these Latin American refineries are in.

(inaudible)

Oh, I'm sorry.

I'll stay.

Well said.

Port Arthur coker, we're still working with all sort of the stakeholders in Port Arthur community, along with the TECQ to get that permit moved forward.

We fully expect to get a permit sometime this year on it.

And our next question comes from the line of Benny Wong with Morgan Stanley.

I just wanted to get your view.

One of the things being proposed is making higher octane level and gasoline standard in the U.S. and as a potential replacement for RFS.

Just wondering if you could share your views on the merits of that proposal and any color how it's being received by the side and what do you think is maybe just sticking points of making it happen?

Yes, so why don't we let Jason talk about maybe the process here a little bit.

And then if Gary or Lane want to talk about what it takes, that would be great.

Yes, Benny, this is Jason.

You're right.

It is something that's been talked about in the context of the legislative long-term reform of RFS.

Moving to higher efficiency, higher tank fuel standard, and AFPM is working on this with the autos for around a year now and the conversations have expanded recently to include the retailers on the ethanol, and we do think this would be a win all around for everybody.

It helped the autos enable them to make more efficient vehicles.

So it could hit the CAFÉ standards easier.

It'd be a win for ethanol because ethanol is an excellent low-cost source of octane.

So increased demand for ethanol.

And we would all benefit by making internal combustion engine and more competitive longer-term against EVs.

So we do think it's something that at least we looked at.

Any comment on gasoline blending to get there or...

Well -- so this is Lane.

From a gasoline blending perspective, clean, high-octane components like alkylate will help in this process.

They help dilute out some of the other sort of the aromatics-based octane that are in the gasoline pull.

And like Jason alluded to, it will require a certain amount of ethanol.

I mean, the industry has gotten used to ethanol blends and it is the source of octane.

And so that -- it definitely is going to be a part of the blend.

I think on balance, what you'll have to deal with is the light naphtha, some light naphtha assuming reformers are full is going to have to find its way somewhere else, whether it goes into the olefins -- you know the olefin crackers or somewhere else, but that's a strain that we'll -- that the industry will be trying to fall between high octane components to blend it off and just getting it out of the pool.

And do you guys have any color if ethanol and corn side is open to this?

Or they have any opposition?

This is Jason, again.

I think they're still trying to get their arms around it, but their initial indications from some of the larger ethanol producers are, they acknowledged kind of this 95 RON type of level or, I think they called it, 91 AKI, which is roughly equivalent is something that makes sense for the market.

Appreciate that.

And just if I -- have a follow-up, if I may.

And apologies if you guys have touched on in your prepared remarks.

Just, is there an update on the status of the Texas City refinery?

Sorry, Benny, this is Lane.

And no, we haven't said anything yet.

So I think I just talked to you on the last, I don't know, the Friday of the Valero Texas Open, but we are based on the (inaudible).

We're going to bring forth the FCC alky turnaround.

We had scheduled Texas City this past fall.

We're just bringing it forward and we are going to execute it now.

And our next question comes from the line of Prashant Rao with Citi Group.

Wanted to turn the focus to the West Coast because this quarter you're in the black, better 1Q performance than last year.

And we did have some concerns in the market about West Coast operating conditions in general for the industry earlier in 1Q.

Just kind of wanted to get your thoughts on outlook for the remainder of the year, maybe addressing where we are now versus where, I think, the market might have been concerned about, maybe, a month or 2 ago.

Does it seem like a turning point from last year?

And it's a stronger starting point, so just want to sort of get a read dynamically how we should be thinking about that as we progress through the year?

Yes, so I think what we saw on the West Coast is certainly the inventory draw we saw this week and getting below that 30 million-barrel threshold, I think, provided a lot of support for the market.

Overall, we still believe that the West Coast is long refining capacity.

And so as long as all the refineries are running at high utilization rates, their market can't -- really can't absorb all the production.

But when refinery goes down, you see spikes in the market and the market becomes short.

I think longer term, the things I look to can help that market, is really the opening up and deregulation in Mexico.

I think you'll see exports from the West Coast that will go to the west side of Mexico.

And then you'll also see as some of the cross border sales ramp up in markets like El Paso, you'll start to see some more West Coast barrels serving the Arizona market, which will help bring that market back into balance.

Okay.

That's helpful.

And then just a quick question on -- I think we talked about this earlier about medium sour availability being a little bit more difficult in the current environment.

Just wanted to get your sense of long-term thoughts in addressing that where there might be sourcing there.

Or is that something that we should just be sort of expecting intermediate term to still be a little bit scarcer and then maybe coming back next year.

Just wanted to get your read dynamically on the market?

Yes.

So I think there is not a problem really with availability of medium sour crude product system.

It's just not priced to where we show an economic incentive to maximize those barrels.

However, they're, certainly, interrelated.

I think we see that medium sours will continue to price at a level where we wouldn't expect to run a high-volume medium sour crude until the OPEC production comes back online, whenever that is, if it's later this year, early next year.

But I think if the OPEC production comes back online and you get that additional supply in the market, you'll see those medium discounts widen, and we'll bring them back into our system.

And our next question comes from the line of Justin Jenkins with Raymond James.

I guess, I'll start maybe with the corollary to Roger's gasoline question, but more on the diesel front.

You've got Inventories as low as they've been since 2014 here in the U.S. and obviously, IMO on the horizon.

So if prices on diesel continue to move higher as maybe we'd all expect, does that start to impact the demand equation there and maybe even the broader economy or how should we think about that one?

Yes.

I think we see diesel demand is very strong.

And as you mentioned, 28 million barrels below where we were last year, we had good heating oil demand with little colder weather in the Northeast.

And then we're seeing very strong rack demand.

I think some of its economic growth and then a lot of it's just the increase in the upstream activity.

But the big thing to us is as we started to get out of typical heating oil season, you could see in the stats, we actually had record exports.

And we're seeing just overall -- what appeared to be an overall global short of distillate barrels available.

So I think we feel like that the distillate market's going to be remain very strong throughout this year and then you certainly, as you've alluded to, will start to see an IMO impact that affects this on the distillate side as well.

When that starts to kick in, I'm not sure.

But we certainly feel that we're in for a very good year in terms of the diesel fundamentals.

Perfect.

Appreciate that.

And maybe on the midstream side, Gary, you alluded to the potential for pipeline participation towards your Gulf Coast assets.

But I'm curious, Joe or even Gary, how you think about getting closer to the wellhead in the Permian to gather crude and maybe control that further?

Yes.

So I think any of these projects that come online reach last way in my group, certainly, evaluate all of them.

And it's for a couple of reasons.

One is to lowered our deliver cost of crude and then also it allows us better control over the quality of the barrel that we're running in our refining system.

So for those reasons, we're involved in all these processes on the new lines coming on.

And certainly look to participate if it make sense for us to do so.

And our next question comes from the line of Blake Fernandez with Scotia Howard Weil.

Mike, I will certainly miss the opportunity to catch up with you over in West Texas.

It's been a good run and congrats to you, man.

Thanks, Blake.

I wanted to go back.

I know you've kind of addressed, Gary, some of the, I guess, the mediums and likes, but a lot of the inbound questions we've been getting from clients recently has been on where we stand with regard to maxing out light suite processing.

I think you had mentioned to me last week that you're backing out mediums and going to max light suite and heavy, but can you say -- I mean, have you fully exhausted your capability of running light sweet at this point?

Pretty much, Blake.

If you look at where we were in the first quarter, we say that we've 1.6 million barrels a day of light sweet crude processing capacity, although it wasn't fully utilized.

A lot of the capacity that wasn't used, it was because we had maintenance going on at couple of our refineries that backed out some of that light suite crude processing capacity.

But we pretty much -- our economics signals are pointing us to maximize light sweet pretty much everywhere we can.

Okay.

The second question, your utilization rates along with the industry have been pretty well above what historical norms would suggest and above expectations.

And I'm just curious if you have any thoughts around, maybe, what's driving that in the sustainability of that?

Is that just kind of capacity creep maybe to where the nameplate numbers are a little bit stale?

Or is it just reliability improving or any thoughts you have there?

I think when I go back and look at the trend in refinery utilization, some of it is tied to the trend in running lighter group.

So as the API -- average API gravity of the crude slate has gone up throughout the industry, utilization has gone up with it.

So we certainly see some of our refineries as we run a lighter diet, it enables us to run higher rates.

So with that, you would expect it as the crude quality discounts widen and the slate gets heavier, maybe there is a chance utilization falls back off if that occurs.

Blake, I'll take one of those things.

I think one of the things you've seen over the last few years is different than maybe historically.

So there has been a call on crude capacity signals that's pretty much been the most economic unit in the refinery.

So all refiners will do everything to make sure that capacity is always well utilized.

I mean, feedstocks were in front of it.

You might even incur demurrage to make sure that, in fact, you don't lose capacity.

So I mean, that's clearly been part of what's going on with respect to the utilization because that number is the crude unit capacity, it's not buying intermediates and other things.

And our next question comes from the line of Phil Gresh with JPMorgan.

First one is just on LLS discounts to Brent.

We've started to see those widen out a bit here, this year, certainly creep higher towards the Houston side.

I presume some of that's DAPL and Diamond and dock-on effects.

But just curious how you think about LLS discounts moving forward, say, relative to Houston?

Yes, Phil, I think to some degree, we're starting to view LLS as somewhat of a stranded crude marker.

I think especially, since we exited that market when we started up the Diamond Pipeline, there is just not a lot of liquidity around LLS anymore.

And so to us, a more relevant marker to look for the U.S. Gulf Coast light suite is that in the H marker.

And that's the one we tend to look at more heavily than LLS.

Okay.

Got it.

That makes sense.

Second question is just around the California refining market.

I want to get your latest thoughts on Wilmington and hydrofluoric acid state of discussions.

I know there is a committee meeting coming up this weekend.

There were some slides published in advance to that meeting, talking about potentially phasing out HFA altogether, which I know would be a fairly costly endeavor.

So I just want to get your viewpoint on this HFA phaseout, particularly given the cost relative to the size of the refinery?

Yes.

This is Lane.

We just really continue to work with the community and the SCAQMD out there and then the other stakeholders really derive -- what we think will ultimately be a reasonable solution.

We're just -- that's sort of what we have been stating in all the calls and all the conferences and that's still what we believe.

So just to clarify, I mean, you wouldn't, at this point, say a phase out of HFA would be a nonstarter for you guys?

Say that, again?

The idea that HFA would be phased out for sulfuric or some other solution, is that a nonstarter from a cost perspective?

Well, it would absolutely.

We're building an alkylation unit at our Houston refinery and at our St.

Charles.

So you're talking about something on the order of $0.5 billion.

It's in fact, we've built a sulfuric acid and then that it would be in California, so it'd probably be even more.

So we've very, very, very expensive endeavor if there is a short fuse on a phaseout in the West Coast.

And our next question comes from the line of Doug Leggate with Bank of America Merrill Lynch.

This is Kalei on for Doug.

A lot of things have been touched here.

So I just want to get your thoughts on Latin America.

Obviously, the underperformance in that refining system has played a big role in creating the opportunity to ramp U.S. product exports.

Just want to know what the prognosis is today?

And if there are any upside risks to crude runs that you guys are watching out for?

I don't think we see anything that causes us a pause for what we're doing in Latin America.

We still see very good product demand pulls, both for gasoline and distillate.

I don't think we see anything on horizon that's going to change that.

And our next question comes from the line of Ryan Todd with Deutsche Bank.

Maybe a follow-up question.

You addressed your view on overall kind of Canadian heavy and heavy differences earlier.

But can you talk about within your system and how much Canadian heavy are you able to run right now?

What are the -- I realize it's going to be difficult until the cross-border pipelines potentially in 2020.

But are there any -- is there possibility of you being able to increase your heavy crude runs over the next couple of years?

And maybe are you seeing any impacts from falling Venezuelan volumes or have you still had a strong heavy availability in the Gulf?

Yes.

So in the quarter, we ran about 180,000 barrels a day of heavy Canadian, Ryan, and it's not really a limit in our system, it's more of an economic optimization.

So we could run a lot more heavy Canadian if the economics pointed us in that direction.

But it would be at the expense of some of the other Latin American grades, the Venezuelan or Maya.

Some of those grades we would pushout if the Canadian was more economic.

Follow-up, I guess, in Venezuela, we've certainly seen some issues with production and issues around logistics.

But for the most part, the volumes we got in Venezuela in the first quarter were consistent with what our historical volumes have been.

And we continue to see good value for those barrels versus our other heavy sour alternatives.

Great.

That's helpful.

And maybe one follow-up on -- feels like you've talked about Latin America a lot today, but there is -- Petrobras is obviously looking for partners into both some opening up of the markets there and partnerships in some of the refineries down there.

Do you view that as a similar situation of what you are describing earlier with Pemex?

How do you view the potential opportunity side of the Brazilian market?

Well, this is Joe.

I mean, we'll take a look.

I think it's too early for us to answer your question, specifically as you asked.

So -- I mean, we just don't know yet.

So I mean, just like many others, I'm sure, we'll just take a look, see what the opportunity looks like and see if we can deal with it.

And then, we'll let you know more about it later.

And our next question comes from the line of Matthew Blair with Tudor, Pickering, Holt.

Maybe just circle back.

I think it was Lane's comment, talking about how the crude tower has pretty much been the most economical part of the refinery today.

So just looking at your Gulf Coast system, you've run about 1.44 of crude, but you produced 1.84 products even after the recent crude topper projects at Corpus and Houston.

Is there any thought to adding more crude distillation capacity on the Gulf Coast?

And what kind of economics are you seeing on those recent topper projects?

Well, this is Lane, again.

The issue you have there is a limit to how much you can run crude because at some point or even build it out, when we put our 2 crude toppers on, we sized them such that they would match our downstream capability, particularly in diesel hydrotreating, so we wouldn't have to go out and try to market something that didn't meet the ULSD spec.

So I think when many people look at a crude unit project, they're going to have to -- there is other units involved.

We were -- and the reason we were able to do that because we were buying a number of intermediate feedstocks in lieu of crude.

So that's the size.

For us to go up a lot more in that space, we would have to invest in diesel hydrotreating and gasoline hydrotreating.

What was the second part of your question?

What kind of returns are you seeing on the Corpus in Houston?

(inaudible) can't give you the specifics.

They've been great projects.

They've exceeded our funding decisions with respect to IRR.

So they've been great projects for us.

Yes, yes.

Seems like it.

Second question is on product exports.

So you reported 271,000 barrels per day of product exports.

I think that was down quite a bit year-over-year.

Was that due to higher ethanol blends in Brazil this year?

And can you also provide a split between how much was gasoline and how much was diesel?

Yes.

So we -- starting with that, we did 73,000 barrels a day of gasoline exports and our diesel exports were 163,000 barrels a day.

The year-over-year numbers are down fairly significantly, and there is a number of reasons for that.

Joe alluded to weather issues in the Gulf, especially a lot of fog that prohibited us from exporting during the quarter.

Also we had some refinery maintenance that limited production.

But the biggest thing was really probably more the strength at the U.S. market.

So we have the ability to put barrels on the water.

And for us, during the quarter, we actually saw a lot better value to take those barrels we're putting on the water to the Florida market, for instance, rather than the export market.

So a lot of our dock capacity was consumed taking barrels like to the Florida market, waterborne markets in the U.S. rather than the export markets.

I don't think it's any indication of lack of demand.

It was just a -- we always view that as an economic optimization, and we had better netbacks to send to other markets.

And our next question comes from the line of Craig Shere with Tuohy Brothers.

Understand there's not really a governor or upper limit on share price as far as buyback considerations.

But is there an upper limit on cash holdings that could impact targeted payouts if attractive M&A really doesn't materialize over the next 2 to 3 years?

And as a follow-up to that, can you opine on what you might see long term in terms of industry consolidation in midstream versus refining?

Okay.

Mike, do you want to take the first one?

Yes, I mean, on the -- we continue to evaluate the cash flow uses and the allocation of the surplus cash flow.

That has not changed.

We continue to allocate it per capital allocation framework.

Right now, our payout ratio is 40% to 50%.

If cash would build significantly over the next several quarters, surely, we would have to look at that to see whether we need to adjust that payout ratio in absence of any type of M&A opportunity.

Okay.

And Craig, on the second part of your question, it was the consolidation whether it'd be in refining or MLPs?

And which might come earlier, right.

Yes, okay, this is clearly an opinion, right?

And I open it up to any members of the team if they want to comment also.

But I just don't think there is going to be a significant amount of opportunity for consolidation on the refining side of the business from Valero's perspective.

Because we really like our portfolio today.

We have excellent portfolio.

I mean, there's strength that we could bolt-on to it.

It would be nice to have.

As far as creating -- needing to do a transaction to create, a lot more critical math.

That's just not something that we need to do today.

So opportunistically, we look at everything, but practically speaking, we don't feel we need to do anything.

Now could there be more consolidation?

Sure, I think people are always looking for different ways to grow their businesses.

And certainly, if you can create synergy by combining, it makes a lot of sense to do that.

In the MLP stage, I don't know.

Rich, do you have a view?

I mean, I would say that it would be challenge to think of consolidation right now and the MLP market is, everybody's kind of reassessing the access to the equity capital market.

So it doesn't seem like that, that would be momentum for that to happen right now to let equity capital markets kind of get figured out.

Okay.

I mean, that all makes sense.

It just sounds like eventually the payout ratio is going to have to rise over time.

Yes, well.

The ratio may rise, but probably that's hard.

It's going to stay somewhat consistent.

The volatility that we've historically had in this business, which we have done our best as a team to try to strip.

And so you always want to be careful with the dividend and be sure that once you put it in place, that is our commitment to our owners, and we're going to be sure we do everything we can to sustain that dividend.

And so Mike, we don't have a particular targeted number because Mike and Donna always look at the forecasted cash, what is the balances look like going forward.

And we've told the market for several years now we're not going to hoard cash and we have it.

And so I think Craig, you should just assume that if we find ourselves sitting on a thoughtful of cash then we're going to return it.

And this does conclude today's Q&A session.

And I'd like to return the call to Mr. John Locke for any closing remarks.

Okay.

Well, thanks, everyone.

We appreciate you joining us today.

Feel free to give the IR team a call if you have any additional questions.

Thank you.

Ladies and gentlemen, thank you for participating in today's conference.

This does conclude the program, and you may all disconnect.

Everyone, have a great day.