瓦萊羅能源 (VLO) 2019 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to Valero Energy Corporation's Second Quarter 2019 Earnings Conference Call.

(Operator Instructions) As a reminder, this call will be recorded.

I would now like to introduce your host for today's conference, Mr. Homer Bhullar, Vice President of Investor Relations.

You may begin.

Good morning, everyone, and welcome to Valero Energy Corporation's Second Quarter 2019 Earnings Conference Call.

With me today are Joe Gorder, our Chairman, President and Chief Executive Officer; Donna Titzman, our Executive Vice President and CFO; Lane Riggs, our Executive Vice President and COO; Jason Fraser, 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 now 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.

Thanks, Homer, and good morning, everyone.

We're pleased to report that we had good operating performance in the second quarter despite having major turnarounds at our Houston, Memphis and Benicia refineries.

We ran reliably during the quarter with very limited unplanned downtime.

Gasoline cracks improved significantly in the second quarter relative to the first quarter in all regions boosting refining margins.

However, the supplies of medium and heavy sour crude oils remained limited due to continued Venezuelan and Iranian sanctions and OPEC production curtailments resulting in narrower crude discounts for those grades relative to Brent crude oil.

As a result, we optimized our system with additional domestic light sweet, Canadian heavy and Latin American crude oils.

In fact, we set another record for Canadian heavy crude oil runs this quarter with over 190,000 barrels per day.

Turning to our renewables segments, the ethanol business generated positive operating income, despite a weak margin environment.

And our growing renewable diesel business continues to generate strong results due to the high demand for renewable diesel.

We continue to deliver on our commitment to grow Valero's earnings capability through organic growth investments.

We successfully completed the Houston alkylation unit project in the second quarter as scheduled and on budget.

This project is now allowing us to upgrade low-cost and abundant natural gas liquids and refinery olefins to produce a premium alkylate product.

And we continue to make progress on the Central Texas pipelines and terminals project, which remains on track to be fully operational in the third quarter of this year.

Looking at organic growth beyond this year, we have a steady pipeline of projects to enhance the margin profitability of our portfolio.

The Pasadena terminal, St.

Charles alkylation unit and Pembroke cogeneration unit are expected to be completed in 2020.

And the Diamond Green Diesel expansion and Port Arthur Coker are expected to be completed in late 2021 and 2022, respectively.

Our capital allocation strategy remains unchanged with an annual CapEx for both 2019 and 2020 at approximately $2.5 billion with growth capital targeting projects with high returns that are focused on operating cost control, market expansion and margin improvement.

With respect to cash returns to stockholders, we continue to target an annual payout ratio of 40% to 50%.

In the second quarter, we paid out $588 million to stockholders bringing the year-to-date total payout ratio to 50% of adjusted net cash provided by operating activities.

Looking ahead, we're optimistic for the balance of the year with fundamentals supporting continued, healthy product demand.

Vehicle miles traveled continues to increase year-over-year, and we expect positive market impacts from the IMO 2020 implementation as bunker fuel terminals transition to lower-sulfur fuel oil.

With our high complexity refineries, we believe that we're well-positioned to take advantage of the expected wider differentials for heavy crude oils and higher product cracks.

Lastly, we remain committed to disciplined growth and to delivering long-term value to our stockholders through exceptional and environmentally responsible operations.

So with that, Homer, I'll hand the call back to you.

Thanks, Joe.

For the second quarter of 2019, net income attributable to Valero's stockholders was $612 million or $1.47 per share compared to $845 million or $1.96 per share in the second quarter of 2018.

Second quarter 2019 adjusted net income attributable to Valero's stockholders was $629 million or $1.51 per share compared to $928 million or $2.15 per share for the second quarter of 2018.

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 second quarter of 2019 was $1 billion compared to $1.4 billion for the second quarter of 2018.

The decrease from the second quarter of 2018 was mainly attributed to significantly narrower medium and heavy sour crude oil differentials relative to Brent crude oil.

Refining throughput volumes averaged 3 million barrels per day, which was 70,000 barrels per day higher than the second quarter of 2018.

Throughput capacity utilization was 94% in the second quarter of 2019.

Refining cash operating expenses for the second quarter of 2019 were $3.80 per barrel, in line with the second quarter of 2018.

The ethanol segment generated $7 million of operating income in the second quarter of 2019 compared to $43 million in the second quarter of 2018.

The decrease from the second quarter of 2018 was primarily due to higher corn prices.

Ethanol production volumes averaged 4.5 million gallons per day in the second quarter of 2019, an increase of 531,000 gallons per day versus the second quarter of 2018, primarily due to added production from the 3 ethanol plants acquired in November 2018.

The renewable diesel segment generated $77 million of operating income in the second quarter of 2019 compared to $30 million in the second quarter of 2018.

Renewable diesel sales volumes averaged 769,000 gallons per day in the second quarter of 2019, an increase of 387,000 gallons per day versus the second quarter of 2018.

The increase in operating income and sales volumes were primarily due to the expansion of the Diamond Green Diesel plant in the third quarter of 2018.

For the second quarter of 2019, general and administrative expenses were $199 million and net interest expense was $112 million.

Depreciation and amortization expense was $566 million and income tax expense was $160 million in the second quarter of 2019.

The effective tax rate was 20%.

With respect to our balance sheet at quarter end, total debt was $9.5 billion, and cash and cash equivalents were $2 billion.

Valero's debt-to-capitalization ratio net of $2 billion in cash was 26%.

At the end of June, we had $5.4 billion of available liquidity, excluding cash.

With regard to investing activities, we made $740 million of capital investments in the second quarter of 2019, of which approximately $510 million was for sustaining the business, including costs for turnarounds, catalysts and regulatory compliance.

Net cash provided by operating activities was $1.5 billion in the second quarter.

Excluding the impact from the change in working capital during the quarter, adjusted net cash provided by operating activities was $1.2 billion.

Moving to financing activities.

We returned $588 million to our stockholders in the second quarter.

$376 million was paid as dividends with the balance used to purchase 2.6 million shares of Valero common stock.

This brings our year-to-date return to stockholders to $1 billion and the total payout ratio to 50% of adjusted net cash provided by operating activities.

As of June 30, we had approximately $2 billion of share repurchase authorization remaining.

We continue to expect annual capital investments for both 2019 and 2020 to be approximately $2.5 billion with approximately 60% allocating to sustaining the business and approximately 40% to growth.

The $2.5 billion includes expenditures for turnarounds, catalysts and joint venture investments.

For modeling our third quarter operations, we expect refining throughput volumes to fall within the following ranges: U.S. Gulf Coast at 1.71 million to 1.76 million barrels per day; U.S. Mid-Continent at 440,000 to 460,000 barrels per day; U.S. West Coast at 255,000 to 275,000 barrels per day; and North Atlantic at 460,000 to 480,000 barrels per day.

We expect refining cash operating expenses in the third quarter to be approximately $4.05 per barrel.

Our ethanol segment is expected to produce a total of 4.3 million gallons per day in the third quarter.

Operating expenses should average $0.40 per gallon, which includes $0.06 per gallon for noncash costs such as depreciation and amortization.

With respect to the renewable diesel segment, we expect sales volumes to be 750,000 gallons per day in 2019.

Operating expenses in 2019 should be $0.45 per gallon, which includes $0.16 per gallon for noncash costs such as depreciation and amortization.

For 2019, we expect G&A expenses, excluding corporate depreciation, to be approximately $840 million.

The annual effective tax rate is still estimated at 23%.

For the third quarter, net interest expense should be $114 million and total depreciation and amortization expense should be approximately $560 million.

Lastly, we still expect the RINs expense for the year to be between $300 million and $400 million.

That concludes our opening remarks.

(Operator Instructions)

(Operator Instructions) And our first question comes from Manav Gupta from Crédit Suisse.

Congrats on the good quarter.

We understand that Brent Maya is a little tight right now.

But when we look at the forward curves of Brent and 3% credit spread on Bloomberg, we assumed about a $8.50 or $9 widening in the next 6 months.

Now since HSFO makes up 40% of the Maya pricing formula, mathematically, it translates to about $3 to $4 widening of Brent Maya.

So could the Brent Maya easily be $10, just following the pricing formula as it exists today or do you think Pemex, will try and step in and try and change the formula and get rid of high sulfur fuel oil pricing from the formula?

Manav, that's a really good question.

Why don't we let Gary give you some insight into that.

Yes.

Manav, so I guess I'll answer the question on the formula first.

Our discussions with PMI would indicate that they will change the formula in the coming weeks.

So we do expect a change in the formula.

However, we do hold to your view on where heavy sour discounts are going.

If you look at where Maya is today and the backwardation in the high sulfur fuel oil market, it would tell you around a $3 discount from where heavy sour discounts are today.

And then if you look at the Western Canadian Select quote in the Gulf, even today, Western Canadian Select is discounted 15% to Brent, which is a good discount, even if you compare it to domestic light sweet alternatives such as MEH.

Western Canadian Select is trading at 11% discount to MEH.

The forward market on the Canadian side, at least there's trade being done in the fourth quarter already, and you're seeing Western Canadian Select discount at around $2.50 in the fourth quarter already.

So that's pretty close to the $3 number that you were looking at.

A quick follow-up sticking to the Western Canadian Select.

A Canadian major about 25 minutes ago on their call said that if deal with the government is struck, they could see rail ramping by 250,000 to 300,000 barrels by year-end.

So that's a massive volume of crude landing in the Gulf Coast.

I'm just trying to understand if this WCS does land on the Gulf Coast by year-end or, let's say, early 2020, can you seamlessly switch between WCS, Maya or any heavy grades that you were running?

Yes, pretty much.

And we've had discussions and would concur with that view that the rail volume will be ramping up and had a lot of discussions with producers.

And we take that into our Port Arthur refinery, and it pretty much is a direct replacement for Maya.

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

Joe, last time you and I sat down, we talked about your underappreciated, let's say, flexibility on light crude.

My question is obviously the alky units helping a little bit on NGLs.

But as we look into the second half of this year and then into 2020, the ramp up, the expected ramp up from the Permian, it was coming with a lot of question marks over what the gravity of that crude is going to look like and the potential for an renewed period of, let's say, dislocations in pricing.

I'm just curious if you could talk through what Valero's opportunity would be in that situation.

Could you take advantage of that?

Or obviously, your complex system is -- folks normally think about you as advantaged by things like WCS.

I'm curious as to whether you could exploit that opportunity as well.

I've got a follow-up, please.

Doug, this is Gary again.

So we certainly are maximizing light sweet into the system.

In the second quarter, we used about 89% of our available capacity, and really, what was left on the table was primarily due to turnaround activity.

As we move forward, we expect to utilize all of that.

As the gravity gets lighter, we are seeing this WTL "coming out," which is a lighter grade of WTI.

We started running some of that in Three Rivers.

I think in the second quarter, we ran 5,000 to 10,000 barrels a day of that, and we've also purchased some for future runs at Memphis.

I think we're scheduled to run about 40,000 barrels a day of WTL in Memphis in September.

So we're certainly moving in that direction and watching the spreads, and the discount is there.

We have a lot of flexibility being able to take it into our system.

Okay.

Are you retooling, Gary?

Or are you pretty much just flexing within the constraints of the system?

It is pretty much within the constraints of the system.

However, the new toppers we built at Corpus and Houston give us a lot more flexibility in this area.

Great stuff.

My follow-up -- go ahead, Joe.

Doug, our position on that, when we're going to expand our saturated gas plant at Port Arthur as a part of the coker project.

So in 2022, we'll also have an increased capability to run light sweet.

Okay.

I have no doubt that you guys will be taking advantage where you can.

My follow-up is, Joe, is really more of a macro question.

This time last year, the optimism was perhaps a little egregious on IMO impacts.

Have you seen anything yet in terms of turning tanks or indicated demand?

There seems to be a lot of news coming out of pretty much a lot of international refiners on the compliant fuels that they are now able to supply.

Has your expectation for the impact of IMO on distillate margins eased any?

Or are you still pretty constructive on the disruptive impact as we go into next year?

And I'll leave it there.

Thanks, Doug.

And I mean, I guess our view all along has been that we would probably start to see something third -- late third to fourth quarter of this year.

It's been interesting, Doug, that the forward markets really haven't reflected the distillate impact.

I think we're starting to see it in other places, but do you guys want to share your views?

No, I think you are seeing people start to turn tanks, and that's one of the reasons you see high sulfur fuel oil strength, is it's just a not a very liquid market today and ships are having trouble actually buying high sulfur fuel oil, which is bidding that market up today, so you see the steep [backwardation] as we approach that January time line.

And I agree with Joe, all the estimates I still see show a fairly significant step change in diesel demand when the IMO bunker spec changes, and it's not reflected in the forward curve today.

Our next question comes from Prashant Rao with Citigroup.

I wanted to touch back on the Western Canadian Select availability.

190,000 barrels per day in this quarter is still running strong there.

And as we expect that discount to widen with rail hitting the Gulf, I wanted to get a sense of your ability to lean into that a bit more.

How much could you ramp beyond the 190,000?

And as you're looking at incremental rail contract, what sort of -- give us some idea what sort of duration maybe you're thinking?

Or do you have the contracting -- contract in hand you need and we're just going to see that sort of flex up in the numbers as we go forward as you take advantage of those discounts?

Yes.

We have a lot of flexibility to run the heavy Canadian.

We're primarily advantaged to run it at our Texas City and Port Arthur refinery just because we have the best logistics to be able to get into those 2 assets.

Between those 2 refineries, probably a capacity about 300,000 barrels a day today to process it.

We can run about 50,000 a day at St.

Charles, and we could run some at Corpus Christi as well, but again, the logistics of getting that in are more challenged.

On the rail side, we continue to work with producers, and we're doing deals on a delivered basis, whereas in the past we were buying barrels in Western Canada and shipping them ourselves, and that volume will continue to ramp up as we get those deals done.

Okay.

It's very helpful.

And then just switching back on sort of a bigger picture question.

With the Houston alky project getting completed, I wanted to take a step back and get your views on where you guys are finding the whole system in the country stands in terms of Tier 3 compliance.

I think we're getting a few more questions.

There has been so much that we're looking at and refining in terms of the macro.

So a few questions that may be concerns about how tight octane is going to get by the time we get to 1Q '20.

Just your updated views at what you -- how you think the system stands today in terms of the progress we're making.

And then, I guess, relatively speaking, where your position is relative to that?

It feels like you'd be advantaged in that kind of a tight octane market.

But any color you can provide there would be helpful.

Yes.

This is Lane.

So we've always had a strategic outlook that octane was going to get more valuable as Tier 3 matured and finally came to a head here at the end of the year and combined that with sort of cheap NGLs.

That was the reason we did these projects and they're coming online at exactly the right time.

You were definitely seeing -- we believe we're seeing octane get more and more expensive.

In terms of where the industry is on a Tier 3 compliance, we're trying to -- we're looking at that ourselves.

But if you look at us as a proxy for that, we still have 3 units that have to come online by the end of the year.

So there's still some more octane disruption in the industry ahead of us.

It is -- I mean, people's implementation though has been, I would say, somewhat muted or delayed as...

Been using credits.

Yes, they were using credits.

And to the extent you could use credits, you deferred the capital, but now we're getting to the point where the rubber meets the road, and it's going to be a lot of makeup activity or we are going to see this spread continue to expand.

Our next question comes from Benny Wong with Morgan Stanley.

Just wanted to ask about the capture rate in the second quarter.

It's particularly weak in the U.S. Gulf Coast.

Understand the light/heavy differentials probably contribute to that.

But just wanted to get a sense if there's any other factors weighing on that.

If there is any risk of those factors persisting.

And conversely, in North Atlantic, the capture is really strong.

It has been strong for a couple quarters.

Just wanted to get a sense is it Europe or U.S. driving that, and should we expect a higher capture level going forward?

Benny, this is Lane.

And for Prashant, I'm sorry, a while ago, I called you Benny.

So -- and the Gulf Coast is a good proxy for what -- in terms of capture rate, we're down about 20% year-over-year.

About 10% to maybe 12% of that is crude differentials, some of that is arb, some of it's just quality.

But the remaining 7% to 8% is non-gasoline products.

Everybody sort of talks about naphtha and how cheap it is, but the other products that are also discounted year-over-year are propylene and propane.

So you can sort of come to your own conclusion about what direction propylene is going to, and obviously propane, NGLs are just getting cheaper and cheaper or with all of the oil shale.

We're still optimistic that -- and the rest of it's -- we're optimistic that, as Gary alluded to, that IMO 2020 will help improve the medium and heavy sour discounts in terms of where naphtha is going and propylene is going.

I mean, they are probably structurally pretty weak for at least some period of time here.

And then on the Line 9 or Atlantic, really what you're seeing on the North Atlantic capture rate is our continued advantaged position on our Line 9 crudes.

Got it.

Appreciate the color there.

My follow-up is really, one of your peers has been talking about, just preparing ahead of IMO 2020 was really looking to take advantage of slack coking capacity within their system and maybe redirecting excess fuel oils from one part of the portfolio into other areas where there might be excess capacity.

Is this something that you guys looked at within your portfolio?

Or is there an opportunity for that?

Seems like more of a logistical optimization exercise, just curious is that something that you guys looked at?

Yes.

So I guess, what you're saying is where we have fuel oil length potentially taking it to open coking capacity.

Is that the question?

Yes.

Essentially, the question is do you guys have some areas where you have slack coking capacity and if there are areas where you have fuel oil length, exactly what you're saying.

Yes.

So we don't make much fuel oil in our system, and we pretty much keep our coking capacity full.

We are providing some flexibility with the Port Arthur coking project to take some fuel oil we produce at Meraux and potentially run it in the Port Arthur Coker when it's expanded.

To Gary's point, what you'll actually see -- so we plan to be full at both coker and like he said, we don't make much fuel oils in the system.

But what it does do is it competes, just like some of the long resid today that competes for crude capacity, and that we do believe you're going to see more and more of that, as some of these blending components that run 3.5 weight percent fuel oil will ultimately have to probably get ran through crude units and compete with other medium and heavy sour crude.

That's obviously why we feel pretty good about the cost of feedstock from here going into next year as a result of IMO 2020.

Our next question comes from Sam Margolin from Wolfe Research.

Lane, can I ask you a follow-up about the capture rate impact and naphtha, because you sort of touched on something that's swirling around the market.

Was there anything -- were you producing sort of excess naphtha or LPGs for any reason besides just a increase in light crude throughput in the Gulf Coast?

Was there something coming out of the 1Q turnaround or something having to do with the 2Q turnaround at Houston that exacerbated the capture rate impact of the commodity dispersion that you quoted with naphtha and LPGs?

Not really.

I mean, we did have the turnaround and so have to go back.

And if anything, we would have ran more crude and had more naphtha.

And our reformers were full.

Right now, one of the most economic units in addition to alky is a reformer.

And so we would have had our reformer signal full.

So I'd have to go look and see what the balance was on naphtha, but we weren't -- directionally, it's just we make the -- we have a position on naphtha, and it goes if we get longer, is we run more and more light sweet crude.

I think exactly.

It's really more of a function of the crude diet and then the other factors.

A lot of the U.S. Gulf Coast naphtha was going to Venezuela and diluent.

And so certainly, as that has shut off, it's caused naphtha to get weaker.

Okay.

And then this is sort of an IMO question.

There's some reports that spring up here and there about heavy sweet crude pricing.

It's pretty scarce, and this isn't the case everywhere heavy sweet is available, but it's printing at some pretty wide premiums to Brent in certain locations.

Is this an IMO signal?

Or is this like an idiosyncratic weird crude that just trades off-spec and doesn't mean anything?

Gary and I will tag-team this.

I think a lot of those crudes are either from Angola or Brazil.

And they have -- it's going to be interesting to see how they fit in the IMO 2020 universe.

I mean, there's some belief that you can burn directly.

I mean, I'm not sure that's the highest value for them necessarily, but -- and there is some substitution effect as you're seeing some of these heavy sour crudes come off, they -- these are substitute crudes for coking refineries.

And so they've certainly gotten the word that's not necessarily the best grade.

But if you look at the things they have is they don't have a lot of naphtha in them.

So I mean, it's the world just sort of resorting out that quality.

Yes.

I think that's a lot of what you see today, is as people have pushed a lot more of the light sweet, they're getting loaded up on the top end of their distillation column and some of these medium sweets allow them to push rate as long as the crack spreads are strong.

Our next question comes from Neil Mehta with Goldman Sachs.

First question is around renewable diesel.

And just trying to figure out how we should think about this business in the context of Valero.

How big do you want it to be?

And related to the segment, there's some big swings on profitability.

One could be a Blender's Tax Credit.

The other is how you see the low-carbon fuel standard playing out in California.

So just some -- any high-level thoughts on the segment.

How you see it playing out over time?

And then how we should think about some of the swings that could drive some upside optionality on the profitability here?

Neil, this is Martin.

We expect low-carbon fuel mandates to grow across the globe.

In Europe, you've got the Renewable Energy Directive now out to 2030.

You got the low-carbon fuel standard in California out to 2030.

There's talk, on again and off again about Canada adopting the standard.

So we're bullish on this and we're actively evaluating opportunities for expansion where they make sense.

As far as the Blender's Tax Credit, obviously, if that comes in, that's a big upside for us.

If it doesn't, we're still in good shape.

We did a $1.26 EBITDA in this last -- second quarter with no Blender's Tax Credit.

If you look in California, they are already blending at 10% renewable diesel.

There is really no limit to where you can get with renewable diesel, meets the same specs as hydrocarbon diesel.

So we feel good about the prospects.

We've got a great partner with Darling that's -- for the feedstock procurement and the front-end processing.

So we plan to keep growing the business.

Jason, anything on the Blender's Tax Credit?

Yes.

I'll be glad to talk about that.

As you all probably know, the Blender's Tax Credit expired at the end of 2017, and both the Senate and the House tax-writing committees are looking at bills to extend it.

They've got a bill that will extend 2 years in the Senate, and the House has a bill that will extend it for 3 years.

And we believe it's going to get -- we're not sure exactly how it will get done or which bill it will get attached to, but we're confident it will get done by the end of the year.

That's certainly our expectation, likely through the appropriations process that takes place this fall.

That's great.

It's an interesting business.

The other one -- it's been a while since we've asked about RINs here.

They have kind of picked their head back up in terms of the D6 RINs price.

Not enough for us to get super concerned, but something at least to watch from the periphery.

So just any thoughts in terms of how we should think about the RINs market from here, especially because there is uncertainty around the degree of waivers for small refinery exemptions here in 2019.

Yes, sure.

This is Jason.

I'll give you our update on some of the recent developments on the RFS front.

On June 15, the EPA published their final rule, which granted the 1-pound RVP waiver to E15 year round and also made some limited market reforms to the RIN market.

We don't think either of those is really going to radically change the landscape.

There are many reasons E15 hadn't taken off in the past, and those are still here, even with the RVP waiver, like concerns about using it in older cars, potential capital requirements at stations.

And we also understand there will probably be a legal challenge to whether the EPA has authority to grant that waiver as well.

So that's going to be an additional wait on the market as people wait and see if the waiver is going to -- or the additional waiver holds up, which will -- but there is definitely some question about whether the EPA has the authority to do that or whether it has to be done by Congress.

And as for the RIN market reforms the EPA adopted, which are really just a public disclosure when a company goes over a certain RIN holding threshold, and then adding some data reporting requirements.

We don't think they're going to make much of a difference.

It's really inadequate to improve the functioning of the RIN market a lot.

So the bottom line is we don't think either of those is going to be a dramatic effect on the RIN market.

Regarding small refiner waivers, which you mentioned, there's been a lot of discussion in the press about them lately.

The biofuel lobby has been aggressively pushing to not have them granted this year.

And this is despite multiple studies that show the SREs haven't led to any real biofuel demand destruction.

But that SRE process is very well established as part of the RFS statute, and the EPA has gotten guidance from Congress as well as several court cases on how to administer them.

So we're confident the EPA is going to continue to follow the law and hopefully will be announcing their decisions on the 2018 applications soon.

We think from their website they have about 38 applications pending for 2018.

Our next question comes from Phil Gresh with JPMorgan.

A couple quick ones here.

One is as we continue to see these increased flows out of the Permian to Texas Gulf Coast of light sweet crude, how are you envisioning things playing out in Corpus Christi, given the inflow versus outflow situation there and the timing of certain export terminals?

Yes.

So Phil, our focus here is really to have been -- get connected to all the lines that make their way to Corpus, and we made a lot of progress there.

So we can receive pretty much all of the lines that are coming in.

And then we've also doing some dock work at Corpus to where we can export more to Québec and Pembroke and that work will be finished in the fourth quarter as well, which will give us more control on that supply chain on exports into our system.

I really can't comment too much on it.

I guess what you're kind of asking more about is, is there enough dock capacity to clear the oil?

And I don't know that I have a lot of insight whether that's the case or not.

Okay.

Second question would just be around the grade of crude that's going to be coming down those pipelines, a lot more of the West Texas light that everyone has been talking about.

Just kind of wondering how you think about running that grade of crude through your system versus more of a WTI grade.

What capacity you might have to run West Texas light?

And given Lane's comments just around the lightening of the crude slate and the impact that has on NGL and naphtha margins coming out, is that something that you consider as you think about what type of crude you want to run?

Yes.

So Phil, it's just all a matter of price.

We have plenty of capacity to be able to process the barrel.

Historically, we've seen a lot of the light material that makes its way to the Gulf price such that we don't have an economic incentive to run it, and it goes to the export market.

Some of the WTL that's been making its way to Corpus has been pricing at $1.25 type discount to MEH.

And so we've seen some incentive to buy it.

And if that's the case, we certainly have a lot of capacity to run it, but it will depend on how it prices.

Our next question comes from Roger Read with Wells Fargo.

I guess maybe -- come back, Lane, to your comments about the Gulf Coast and the light/heavy differentials impact that's had.

But it was interesting to me in the quarter year-over-year, you actually had a better distillate yield relative to gasoline yield despite, I guess, running a somewhat lighter slate.

So I just wonder if you could kind of give us an idea of how that's happened because it seems a little contrary to the kind of the conventional wisdom, run more lights, get more gasoline?

And then maybe how that tied in also to the issue with the excess naphtha?

I'm just trying to kind of understand how it seems like you're running a better heavy slate in terms of product with a lighter yield, yet the lights caught you on the capture in the end.

Yes.

So Roger, what I would say is we did have the FCC down in Houston -- the whole FCC Houston alky complex was down from -- a big chunk of the quarter, so consequently, our gasoline production was off.

In terms of naphtha, we are -- again, with the signal's been max reformer the whole time.

So as you increment into the light sweet, it leads to us, and I believe the industry is in the same spot, as you run more and more light sweet, more of it has to be exported, and ultimately, it clears in the Far East.

And so it doesn't go in the gasoline.

Now there will be, and I'm sure part of what's happening right now with this Tier 3 is saturating the gasoline and lowering octane and there's just an abundance of naphtha, everybody is trying to figure out a way to get naphtha back into the gasoline pool.

But you need octane to do that.

And right now, the industry is trying to get that -- figure out that balance as again, as Tier 3 is getting acclimated.

Okay.

Maybe as a quick follow-up on that.

What or who or where is our best incremental source of octane outside of the U.S.?

Well, that's a good question.

We've seen some imports, but I can't tell you exactly where that's coming from.

Historically, India excesses alkylate, and we see some trade flow of barrels from India coming over.

The other thing you see today is that either toluene and xylene is using as a gasoline blend component, with where it prices, you have an incentive to blend naphtha with toluene to make gasoline.

So that's another source of octane.

To Gary's point, the issue you have around that, at some point on the reformulated gasoline fuels, you'll read a toxic limit.

That's where alkylate is really important.

It allows you -- as you get more alkylate in the pool, it allows you to incrementally raise the amount of aromatics in the gasoline as well.

But yes.

We could probably spend the whole call on these kind of intricacies.

That was -- yes, exactly.

As a follow-up question, ethanol, really weak.

You did the acquisition -- I don't remember if it closed into the very beginning of the year or very end of last year, but it's been a tough period here in ethanol.

We've seen some competitors shutting down some of their plants and refinancing their companies and everything.

Obviously, your size, you're not worried about making it through the process.

But I was just wondering light at the end of the tunnel, is that a 2020 thing?

Is it -- we have to know how the '19 corn crop turned out?

Is it the trade issues with China?

Can maybe an order of what matters in magnitude of those events, if you could?

Roger, this is Martin.

Yes.

If you look at the -- this is the latest corn crop really in the history of the record, which goes back 40 years.

So you've got the latest corn crop and right now, so the December CBOT price was $3.70 a bushel in early May, went to $4.70 a bushel by mid-June.

Now it's back down to about $4.30.

So there's just a lot of uncertainty how big is the crop.

And what really matters is the carryout at the end of this 2019 crop year.

And nobody knows at this point.

There's still weather that could impact it.

So it's going to be hard to have real big ethanol margins for this crop year in the U.S. Now obviously if China opens up, that helps a lot.

That's a little different story, right.

They have a 10% mandate, and that would make a big difference on the exports right away.

Absent that, you're going to see -- you saw our forward guidance is lower than we ran.

So we're going to trim a little bit.

A lot of people are going to have to trim more.

We've got a great fleet.

In the long term, when you're relying on a crop, these things happen, right?

We've had 5 years now where yields have been above trend and then it's due for one below it.

So we'll get through this.

Obviously, we're still bullish about ethanol.

Long term, it's a great octane component.

It's part of the fuel mix to stay, so we'll be there with it.

Two things I would add to what Martin said.

First of all, the industry is just overproduced for what it is today.

That's the fundamental problem here.

So what have we done?

Well, we have ramped up exports as an industry, and that's where tariffs become a factor in these things.

And it takes a while to develop markets, but we have been, Valero has been very aggressive in exporting ethanol and we'll continue to be aggressive going forward.

The other thing, and Jason spoke to this earlier, was the whole E15 issue.

The ethanol industry broadly has this notion allowing E15, which as we said will be challenged, is going to solve some of this problem.

Frankly, I think the solution to this problem is a higher octane fuel that helps with CAFE, and it could be a nationwide standard like 95 RON.

It would require more ethanol to be blended into the fuel mix.

It would take all the arguments out of what types of fuel we're going to produce in market broadly.

And if we could just get everybody synced up.

This is one of the things where amazingly, the autos are on board, the retail marketers are on board, refiners are okay with this.

And in the ethanol industry, we've seen that this was a good solution to this problem that we're facing.

Perhaps we could make some progress, but there is a genuine distrust, and we're going to have to get over that.

But we will continue to bash away on this, because I agree with Martin.

Ethanol is going to be part of the fuel mix for a very long time, and it will recover.

Yes, probably part of the problem of building it on a mandate as opposed to a market incentive to pull more product in.

Our next question comes from Paul Cheng with Scotia Howard Weil.

Is this Paul Cheng?

Believe or not.

Two quick questions.

Maybe this is either for Lane or Gary.

I know that you guys don't produce a lot of resid, but when you're looking at the bunker fuel market, going into the very low sulfur fuel oil, do you know or that -- I mean, how are you guys going to go around to get there?

I mean, are you going to take the VGO or that you're trying to blend the high sulfur fuel oil into that?

And what do you think the industry approach is going to be?

Yes.

So Paul, we've been working very hard to develop low sulfur fuel oil blends.

We work with several shipping companies.

We currently have, I think, 3 shipping companies burning our low sulfur fuel oil blend.

So we've been working hard to be able to produce compliant fuel.

Gary, can you share with us that -- I mean, what is the path or the approach that you guys take?

Because it seems like it's very, very inefficient to trying to use the high sulfur fuel oil and blend it with the ultra-low sulfur diesel into that.

Seems like that it more makes sense to using the VGO.

But if that's the case, we will have a major problem of the much lower gasoline yield?

Yes.

That's exactly right, Paul.

So what we're looking at is some of these low sulfur heavy streams that we typically run through to cat crackers, taking some of those barrels out and being able to blend compliant low sulfur fuel oil with those rather than taking a high sulfur fuel oil stream.

Paul, this is Lane.

Both -- the 2 places that we're doing that really are Pembroke and Québec, and we really don't start with a high sulfur resid.

We start with something that's maybe a moderate sulfur and it depends on the crude economics, and then we start blending it up.

I see.

Gary and Lane, that you guys -- for the industry as a whole, do you think how much is the VGO they are going to take out for this purpose?

I don't know that we have a macro view of that.

But we've sort of talked all along about this idea that VGO at some point will have to maintain its parity into an FCC or the gasoline and obviously, back to this low sulfur fuel oil market.

And therefore, it's supportive of gasoline, to your point earlier.

It will essentially cause -- it's a linkage between FCC economics and then just straight up low sulfur fuel oil into the bunker market, which is going to be connected with diesel.

So I think a lot of people thought they'd be disconnected, but they're not.

It's really through the VGO.

But in terms of how much, there are compatibility issues.

There's all sorts of things around this that everybody is working on, and we'll just have to see how much of it -- how much you can get into the blends.

A final question.

I mean, even if we can fix the -- diesel issue, I mean, that the resulting high sulfur fuel oil seems like is still going to be a problem.

Do you guys have -- I mean, you don't produce it, and indeed, you are a net buyer of the resid.

So if resid price crashed down to 0, it would be great for you.

Any idea that -- I mean, what is really the alternative use that we can do with all the excess high sulfur resid?

It's primarily power generation that's for the other -- and we don't know the market depth of that or how much can be absorbed.

I think it all depends on OPEC and how much it produces and how much substitution they can do.

Instead of where they were burning crude, they can burn some of these high sulfur fuel oil.

Our belief is that it's still long.

Particularly once OPEC starts recovering in their production, that's why we're not -- we feel good about our assets in light of this problem that you're talking about.

Lane, how easy for the industry be able to feed the high sulfur resid back into the coker and use it as a feed?

I mean, you guys don't -- already doing some, but the industry as a whole, do we have a lot of opportunity doing that?

I think everybody is on a learning curve on that.

We've been doing it a long time.

We run a lot of resids.

So we have a pretty good understanding.

The issue you get into is you've got to find a way to run it and maintain your defaulter operation that's heavier, it doesn't have the light stuff, so you don't get good mixing.

And there is other challenges.

It depends on the configuration of the refinery.

And I'm sure as it gets distressed in the marketplace, there will be a lot of -- there will be -- everybody will try to accelerate and figure out how much they can run.

Paul, it was good to see -- hear you back, and you were true to form.

Our next question comes from Patrick Flam with Simmons Energy.

I really wanted to ask you about capital spending trends so far this year.

If I'm doing my math right, it looks like you've spent about $1.5 billion so far out of the $2.5 billion 2019 target, which implies to me that your spending is going to drop off into the second half of the year.

I was hoping you could just walk me through the moving pieces there.

And if this is a reflection of lower turnaround activity levels or lower project spending or whatever those pieces might be?

It's both.

This is Lane.

It's both of those.

We've had a pretty heavy turnaround period, and we don't have nearly as much turnaround activity for the rest of the year.

And then two, you're just not as productive those last 2 or 3 months of the year because of all the holidays.

So it's really a combination of that.

Yes.

It's not that unusual to find ourselves in this situation.

I mean, and things will move a little bit within this.

Sometimes we're slightly below, sometimes we're above, but I mean, the $2.5 billion number is just kind of our nominal expectation what we're going to spend.

And again, you kind of do it as you have to, so.

Well, and to that point, I mean, when we had the tube leak at Benicia, that was the turnaround that we had planned in the first quarter of 2020, that we had to bring into this year.

So we had to bring on a number -- $80 million or $90 million of turnaround spend from one year to the next.

And so some things like that can happen.

Okay.

Great.

That's really helpful.

My follow-up question is essentially -- I know you guys aren't directly impacted by this, but I was hoping you could frame up any expectations you have for longer-term market impact from the potential closure of the PES refinery on the East Coast.

Yes.

So obviously it's going to tighten the market there, 350,000 barrel a day refinery.

That refinery produced a lot of premium gasoline, 35,000 barrels a day of premium gasoline, and our strategy in that region has been able to supply the market primarily from Pembroke.

And so we have good logistics assets in place to be able to take advantage of that short.

And Pembroke is a refinery that has a lot of capability to produce octane, and so that's primarily what we're working on today.

Our next question comes from Jason Gabelman with Cowen.

I actually wanted to follow up on the Philadelphia Energy refinery closure.

So obviously, gasoline margins strengthened off the fire and have come back a bit.

And I'm wondering what you attribute the increase to and if you think that's going to be sustained through 3Q.

It seems like there's a lot of gasoline supply in the market.

So I wonder if it's a matter of months those imports kind of hit the East Coast, margins are going to fall back off or maybe there is somewhat of an octane shortage that could support gasoline margins through the rest of 3Q?

And I have a follow-up.

Yes.

So this is Gary.

I think our view is, if you look at the DOE stats for the last couple of weeks, it looks like demand has been down.

But our view is that demand will be revised back upward and that you'll see actually net exports fall off.

And a lot of that is the reason that you pointed to.

After the fire and announced closure, you had a $0.03 a gallon open arb to ship gasoline from Northwest Europe to New York Harbor.

And so it incentivized imports there.

PADD 5 we saw imports even after the refinery utilization came back.

And then in the U.S. Gulf Coast, with the octane strength, we're seeing some import of components into the U.S. Gulf Coast as well.

And so demand is good, but the net exports, mainly due to imports being down, is kind of what's caused the build that we've seen the last couple weeks.

And it does look like that the market is cooling off some, and you're already seeing signs that that's reversing, especially in PADD 5. We've gone from seeing imports to it looks like a couple refiners are putting export cargos together, and you're seeing barrels from California flow into the Arizona market to help clear that as well.

So I do think it's a trend you'll see reverse.

Do you have a view if the world is kind of maxed out on how much octane it can produce right now?

Yes.

I think the combination of the things Lane talked about with Tier 3 gasoline destroying some octane and then globally, refiners running a very light diet and excessing naphtha and trying to fit naphtha back into the pool has caused octane to be very tight globally.

Got it.

And if I can just ask a follow-up.

Mexico is working to revamp its existing refineries in addition to building a new one.

But assuming they are successful on the former, it could have implications for U.S. product exports.

Is Valero thinking of kind of continuing its strategy to push its logistical reach into new markets, similar to what it did in Peru to kind of combat the potential for the Mexican market to close up a bit to the U.S. for product exports?

Yes.

So we currently are exporting about -- that we sell ourself about 30,000 barrels a day direct sales into Mexico.

That will continue to ramp up.

We're building our marine terminal in Veracruz and have a strategy in the North as well.

For Mexico to do much on revamping their refining system, it involves a lot.

It's not just the refineries, but it's also a lot of logistics and able to get logistics that were meant to move crude out, now to move crude in.

So it's going to be a long time coming before they can do much in terms of revamping their refining system.

Yes.

I agree with Gary completely.

And then if you look at the new plant that they have in mind, obviously, the capital cost is going to be much higher than they had originally forecasted.

If you are a country and you want to do something as a matter of national pride, and economic returns aren't the primary driver to the investment, then something like that probably makes sense.

But certainly, the most efficient way for Mexico to supply its shorts is from the U.S. Gulf Coast.

And we have a question from Matthew Blair with Tudor, Pickering, Holt.

Joe, I think you could say that Valero has the biggest investment in new alkylation capacity in the industry, just with your projects at Houston and St.

Charles.

Could you talk about how this will change your overall net exposure in alkylate?

Are you net short today?

And after these projects are done, would you become net long?

Gary, you or Lane?

Yes.

So I don't know that -- it's all a matter of economics of where alkylate trades.

So we have flexibility where we can sell alkylate direct.

The additional alkylate in the pool allows us to make more RBOB versus CBOB.

And it also allows us to make a lot more export grades that are required in some of the Latin American markets.

So it will be all a matter of price of what path we choose to go, but we have flexibility to do any of those things.

Sounds good.

And then I think the top end of your throughput guidance for Q3 '19 is about 4% below what you did last year.

I think that the turnaround schedule lightens up this quarter.

Could you just talk about what the constraints are?

Why the volumes are coming in fairly low for Q3?

Yes.

This is Lane.

We don't really give -- we just give the ranges.

We don't really give sort of any sort of maintenance guidance really.

So as long as we [did that], we don't normally give that kind of guidance.

We just -- the volumes are what they are.

Yes, and Matthew, you know what goes into the volume forecast.

So it is what it is.

I mean, does this reflect like any sort of economic run cuts?

No.

Thank you.

And I'm showing no further questions at this time.

I'd like to turn the call back to Mr. Homer Bhullar for any closing remarks.

Thanks, Katherine.

We appreciate everyone joining us today.

Obviously, if you have any further questions, feel free to reach out to the Investor Relations team.

Thank you, everyone.

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

This concludes today's program.

You may all disconnect.

Everyone, have a great day.