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Valero Energy Corp (VLO 1.23%)
Q2 2019 Earnings Call
Jul 25, 2019, 10:00 a.m. ET
Contents:
- Prepared Remarks
- Questions and Answers
- Call Participants
Prepared Remarks:
Operator
Good day, ladies and gentlemen, and welcome to Valero Energy Corporation Second Quarter 2019 Earnings Conference Call. [Operator Instructions]. I would now like to introduce your host for today's conference, Mr. Homer Bhullar, Vice President of Investor Relations. You may begin.
Homer Bhullar -- Vice President, Investor Relations
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.
Joseph W. Gorder -- Chairman, President and Chief Executive Officer
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 fracs 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 renewable 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.
Homer Bhullar -- Vice President, Investor Relations
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 productions from the three 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 average 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.
Questions and Answers:
Operator
[Operator Instructions] And our first question comes from Manav Gupta from Credit Suisse. Your line is open.
Manav Gupta -- Credit Suisse -- Analyst
Thank you. Congrats on the good quarter. We understand that Brent Maya is a little tight right now. But when you look at the forward curves of Brent and 3% that displayed 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 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, etc., stuff stepping and trying to change the formula and get rid of high sulfur fuel oil pricing from the formula?
Joseph W. Gorder -- Chairman, President and Chief Executive Officer
Well, good morning, Manav. That's a really good question. Why don't we let Gary give you some insight into that.
Gary Simmons -- Senior Vice President-Supply, International Operations and Systems Optimization
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're looking at.
Manav Gupta -- Credit Suisse -- Analyst
A quick follow up sticking to the Western Canadian Select. A Canadian major about 25 minutes ago on their call said that a 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?
Gary Simmons -- Senior Vice President-Supply, International Operations and Systems Optimization
Yes, pretty much. And we've had discussions in what 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.
Manav Gupta -- Credit Suisse -- Analyst
Thank you guys and congrats on a good quarter.
Joseph W. Gorder -- Chairman, President and Chief Executive Officer
Thank you.
Operator
Thank you. Our next question comes from Doug Leggate with Bank of America Merrill Lynch. Your line is open.
Doug Leggate -- Bank of America Merrill Lynch -- Analyst
Thanks. Good morning everybody. Good morning, Joe.
Joseph W. Gorder -- Chairman, President and Chief Executive Officer
Good morning, Doug.
Doug Leggate -- Bank of America Merrill Lynch -- Analyst
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 advantage by things like WCS. I'm curious as to whether you could exploit that opportunity as well. I've got a follow up, please
Gary Simmons -- Senior Vice President-Supply, International Operations and Systems Optimization
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 pretty reverse. 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 at 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 to take it into our system.
Doug Leggate -- Bank of America Merrill Lynch -- Analyst
Okay. Are you retooling, Gary, or are you pretty much just flexing within the constraints of the system?
Gary Simmons -- Senior Vice President-Supply, International Operations and Systems Optimization
It is pretty much within the constraints of the system. However, the new toppers we build at Corpus and Houston give us a lot more flexibility in this area.
Doug Leggate -- Bank of America Merrill Lynch -- Analyst
Great stuff. My follow up -- go ahead, Joe.
Joseph W. Gorder -- Chairman, President and Chief Executive Officer
I think that's an awful addition on that one. We're going to expand our saturation gas plant at Port Arthur to power the coker project. So in 2022, we'll also have and appreciate ability to run light sweet.
Doug Leggate -- Bank of America Merrill Lynch -- Analyst
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 micro 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 volume 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. Thank you.
Joseph W. Gorder -- Chairman, President and Chief Executive Officer
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 hasn't reflected the distillate impact. I think we're starting to see in other places, but do you guys want to share your views?
Gary Simmons -- Senior Vice President-Supply, International Operations and Systems Optimization
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 the ships are not a very liquid market today and ships are having trouble actually buying high sulfur fuel oil, which is bidding that market up today. 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.
Doug Leggate -- Bank of America Merrill Lynch -- Analyst
All right guys. Thanks for your time. Appreciate it.
Gary Simmons -- Senior Vice President-Supply, International Operations and Systems Optimization
Thanks Doug.
Operator
Thank you. Our next question comes from Prashant Rao with Citigroup. Your line is open.
Prashant Rao -- Citigroup -- Analyst
Good morning. Thanks for taking the question. I wanted to touch back on the Western Canadian Select availability. 190,000 barrels per day in this quarter 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 and you maybe just going to see that sort of reflects up in the numbers as we go forward as we take advantage of those discounts?
Gary Simmons -- Senior Vice President-Supply, International Operations and Systems Optimization
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.
Prashant Rao -- Citigroup -- Analyst
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 stand in terms of Tier 3 compliance. I think we're getting a few more questions. It has been so much that we're looking at in refining in terms of the macro. So a few questions that maybe 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 advantage in that kind of a tight octane market. But any color you can provide there would be helpful.
Lane Riggs -- Executive Vice President and Chief Operating Officer
Yes, it's 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 us ahead here at the end of the year and combined that with sort of cheap NGLs. That was the reason we did these projects in the terminal line exactly the right time. You were definitely seeing -- we believe we're seeing octane get more and more expenses. 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.
Joseph W. Gorder -- Chairman, President and Chief Executive Officer
People's implementation though has been, I would say, somewhat muted or delayed as...
Lane Riggs -- Executive Vice President and Chief Operating Officer
Been using credits.
Joseph W. Gorder -- Chairman, President and Chief Executive Officer
Yes, they were using credits. And to the extent you use credits, you defer the capital, but now we're getting to the part 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.
Prashant Rao -- Citigroup -- Analyst
All right. That's very helpful. Thanks Joe, thanks, Lane, thanks, Gary. Appreciate that.
Gary Simmons -- Senior Vice President-Supply, International Operations and Systems Optimization
Take care, Prashant.
Operator
Thank you. Our next question comes from Benny Wong with Morgan Stanley. Your line is open.
Benny Wong -- Morgan Stanley -- Analyst
Hi, guys. 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?
Lane Riggs -- Executive Vice President and Chief Operating Officer
So hi, Benny, this is Lane. And for Sean, I'm sorry well over that call to 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 that are for just quality. But the remaining 7% to 8% of that is non-GAAP points -- 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. Being 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 probably 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 advantage position on our Line 9 crudes.
Benny Wong -- Morgan Stanley -- Analyst
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 opportunity for that. Seems like they are more of a logistical optimization exercise? Just curious is that something that you guys looked at that?
Gary Simmons -- Senior Vice President-Supply, International Operations and Systems Optimization
Yes. So I guess, what you're saying is where we have fuel length potentially taking into open coking capacity. Is that the question?
Benny Wong -- Morgan Stanley -- Analyst
Yes. Essentially 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 is exactly what you're seeing?
Gary Simmons -- Senior Vice President-Supply, International Operations and Systems Optimization
Yes. So we don't make much fuel oil at all 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.
Lane Riggs -- Executive Vice President and Chief Operating Officer
To Gary's point, what you'll actually see -- so we plan to be full at both coker and I can say we don't make much fuel oils in the system. But what it does is compete just like some of the long resist today that compete for crude capacity. We do believe you're going to see more and more of that as some of these blending components that run 3.5% to 8% fuel oil will be -- ultimately have to probably get ramped 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.
Benny Wong -- Morgan Stanley -- Analyst
Got it. Great color guys. Thank you.
Operator
Thank you. Our next question comes from Sam Margolin with Wolfe Research. Your line is open.
Sam Margolin -- Wolfe Research -- Analyst
Good morning everybody.
Gary Simmons -- Senior Vice President-Supply, International Operations and Systems Optimization
Hi, there.
Sam Margolin -- Wolfe Research -- Analyst
Lane, can I ask you a follow up about the capture rate impact and naphtha because you 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 one Q turnaround or something having to do with the two Q turnaround at Houston that exacerbated the capture rate impact of the commodity dispersion that you quoted with naphtha and LPGs?
Lane Riggs -- Executive Vice President and Chief Operating Officer
Not really. I mean we did have a turnaround since -- I'd have to go back. And if anything, we would have ran more crude and have more naphtha in our reformers or so. We're right now one of the most economic units in addition to alky as a reformer. And so we would have had our reformer signaled full. So I 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, we run more and more light sweet crude.
Gary Simmons -- Senior Vice President-Supply, International Operations and Systems Optimization
I think exactly. It's really more of a function of the crude dye and then the other factors. A lot of the U.S. Gulf Coast naphtha was going to Venezuela. And so certainly as that has shut off, it's caused naphtha to get weaker.
Sam Margolin -- Wolfe Research -- Analyst
Okay. And then this is sort of an IMO question. There's some reports that bring 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?
Lane Riggs -- Executive Vice President and Chief Operating Officer
Gary and I'll tack this. I think a lot of those crudes are rather from Angola or Brazil. And they have -- it's going to be interesting to see how they fit in the IMO 2020 intervals. 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 heave 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.
Gary Simmons -- Senior Vice President-Supply, International Operations and Systems Optimization
Yes. I think that's a lot of what you see today is people have pushed a lot more the light sweet. They're getting loaded up on the top end of their distillation column instead of these medium sweets allow them to push rate as long as the crack spreads are strong.
Sam Margolin -- Wolfe Research -- Analyst
All right. Thanks so much.
Operator
Thank you. Our next question comes from Neil Mehta with Goldman Sachs. Your line is open.
Neil Mehta -- Goldman Sachs -- Analyst
Good morning team.
Gary Simmons -- Senior Vice President-Supply, International Operations and Systems Optimization
Hey Neil.
Neil Mehta -- Goldman Sachs -- Analyst
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?
Martin Parrish -- Senior Vice President-Alternative Fuels
Hey 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 to get on and get off again about Canada adopting the standard. So we're bullish on this and more 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, meet 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.
Joseph W. Gorder -- Chairman, President and Chief Executive Officer
Jason, anything on the Blender's Tax Credit.
Jason Fraser -- Executive Vice President and General Counsel
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 two years in the Senate, and the House had the bill that will extend it for three years. And we believe it's going to get -- we're not sure exactly how it will get done, which bill will it get attached to, but we're confident it will get done by the end of the year. That's certainly our expectation, likely to the appropriations cost as it takes place this fall.
Neil Mehta -- Goldman Sachs -- Analyst
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.
Jason Fraser -- Executive Vice President and General Counsel
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 carries the GBP1 RVP waiver to E15 here around and also made some limited market reforms to the end 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 of the past, and those are still here, even with the RVP waiver, like concerns about using 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 weight 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 the public disclosure. When a company goes over certain RIN holding threshold, it didn't expanding 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 smaller fine or waivers, which you mentioned, there's been a lot of discussion in the press about them lately. The biofuel lobby has been aggressively pushing hard to have them granted this year. And this is just slight multiple study, so the SREs haven't led any real biofuel demand destruction.
But that SRE process is very well established as part of the RFS statute, and 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.
Neil Mehta -- Goldman Sachs -- Analyst
Great. Thanks, Jason and thanks, Joe.
Operator
Thank you. Our next question comes from Phil Gresh with JP Morgan. Your line is open.
Phil Gresh -- JPMorgan -- Analyst
Yes, hi good morning. I have 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?
Gary Simmons -- Senior Vice President-Supply, International Operations and Systems Optimization
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 Quebec 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.
Phil Gresh -- JPMorgan -- Analyst
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?
Gary Simmons -- Senior Vice President-Supply, International Operations and Systems Optimization
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're seeing 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.
Phil Gresh -- JPMorgan -- Analyst
Okay, all right. Thank you.
Operator
Our next question comes from Roger Read with Wells Fargo. Your line is open.
Roger Read -- Wells Fargo -- Analyst
Yeah, thanks good morning. I guess maybe -- come back, Lane, 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 out 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.
Lane Riggs -- Executive Vice President and Chief Operating Officer
Yes. So Roger, we did have the SEC down in Houston -- the whole SEC Houston housing complex was down from -- a big chunk of the quarter is coming from our gasoline production was part. In terms of naphtha, we are -- again with the signals of the max reformer the whole time. So as you increment into the light sweet, it leaves you up -- and I believe the industry is in the same spot -- as you run more and more light sweet, more of it have to be exported, and ultimately it clears in the Far East. And so it doesn't go onto the gasoline. There will be -- 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. You need octane to do that. And right now, the industry is trying to get that -- took out that balance as again at Tier 3 estimates.
Roger Read -- Wells Fargo -- Analyst
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.?
Gary Simmons -- Senior Vice President-Supply, International Operations and Systems Optimization
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 excess is alkylate, and we see some trade flow of barrels from India coming over. The other thing you see today is that toluene and xylene is using the gasoline component with where prices you had an incentive to blend naphtha with toluene to make gasoline. So that's another source of octane.
Lane Riggs -- Executive Vice President and Chief Operating Officer
To Gary's point, the issue you have around that at some point on the reformulated gasoline fuels you'll read a toxic elements. 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 of the gasoline as well. But yeah...
Roger Read -- Wells Fargo -- Analyst
You could probably spend the whole call on these kind of intricacies. As a follow-up question, ethanol really weak. You did the acquisition -- I don't remember if it closed until 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 plans 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 it 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?
Martin Parrish -- Senior Vice President-Alternative Fuels
Hey, Roger, this is Martin.
Roger Read -- Wells Fargo -- Analyst
Hi, Martin.
Martin Parrish -- Senior Vice President-Alternative Fuels
Yeah. 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 not now. So the December CBOC price was $3.70 a bushel in early May, went to $4.70 a bushel by mid-June, was back down to a $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 here 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 wouldn't 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 it trends a little bit. A lot of people are going to have to trend 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 five years now where yields have been above trend and the year 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. We'll be there with it.
Joseph W. Gorder -- Chairman, President and Chief Executive Officer
Two things I would add to what Martin said. First of all, the industry is just overproduced from 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 in the developed markets, but we have been -- has been very aggressive in exporting ethanol. We 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 blend into the fuel mix. It would take all the argument out of what types of the fuel we're going to produce and 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 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 faster way 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.
Roger Read -- Wells Fargo -- Analyst
Yes, probably part of the problem of building it on a mandate as opposed to a market incentive to pool more product in. All right, well, thank you.
Joseph W. Gorder -- Chairman, President and Chief Executive Officer
You bet, Roger. You got it.
Operator
Thank you. Our next question comes from Paul Cheng with Scotia Howard Weil. Your line is open.
Paul Cheng -- Scotia Howard Weil -- Analyst
Hey guys. Good morning.
Joseph W. Gorder -- Chairman, President and Chief Executive Officer
Is this is Paul Cheng?
Paul Cheng -- Scotia Howard Weil -- Analyst
[Foreign Speech]
Joseph W. Gorder -- Chairman, President and Chief Executive Officer
Hey welcome back my friend. Good to you hear. We missed you.
Paul Cheng -- Scotia Howard Weil -- Analyst
Thank you. I missed you guys too. Believe or not. two quick questions. Maybe this is either for Lane or Gary. I know that you guys don't produce or not allowed receipt, 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 brand the high sulfur fuel into that? And what do you think the industry approach is going to be?
Gary Simmons -- Senior Vice President-Supply, International Operations and Systems Optimization
Yes, 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, three shipping companies burning our low sulfur fuel blend. So we've been working hard to be able to produce compliant fuel.
Paul Cheng -- Scotia Howard Weil -- Analyst
Gary, can you share with us that? I mean what is the path for the post that you guys take? Because it seems like 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 make sense to using the VGO, but if that's the case will we have a major problem after much lower gasoline yield?
Gary Simmons -- Senior Vice President-Supply, International Operations and Systems Optimization
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 our tack 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.
Lane Riggs -- Executive Vice President and Chief Operating Officer
Paul, this is Lane. Both -- the two places that we're doing that really are Pembroke and Quebec, and we really don't start with a high sulfur. We start with something that's maybe a moderate sulfur and then take crude economics, and then we start blending it up.
Paul Cheng -- Scotia Howard Weil -- Analyst
I see. Gary, a link there, 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?
Lane Riggs -- Executive Vice President and Chief Operating Officer
I don't know. We have a macro view of that. But we've sort of talked all along about this idea of the VGO at some point will have to maintain a parity into an SECs 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 -- the link is between SEC economics and then just straight out 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 be disconnected, but they're not and certainly 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 this -- how much you can get into the blends.
Paul Cheng -- Scotia Howard Weil -- Analyst
A final question. I mean, even if we can fix the -- not 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 on, did you, a net buyer of the receipt. So if receipt probably crash down to zero, it would be quick for you. Any idea that -- I mean what is really the alternative use that we can do with all the excess high sulfur receipt?
Lane Riggs -- Executive Vice President and Chief Operating Officer
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 the OPEC starts recovering into production, that's one we're not. We feel good about our assets in light of this problem that you're talking about.
Paul Cheng -- Scotia Howard Weil -- Analyst
How easy for the industry be able to fit the high sulfur with back into the coke? And you say that's a fit. I mean, you guys don't already doing some, but the industry as a whole do we have a lot of opportunity doing that?
Lane Riggs -- Executive Vice President and Chief Operating Officer
I think everybody is on a learning curve on that. We've been doing it a long time. We run a lot of reserves. So we have a pretty good understanding. As you get into is you've got to find a way to run and maintain your defaulter operation that's heavier, doesn't have a life, that's going to get the next thing. And there is other challenges. It depends on the configuration of the refinery. 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 Cheng -- Scotia Howard Weil -- Analyst
Thank you.
Joseph W. Gorder -- Chairman, President and Chief Executive Officer
Paul, it was good to see -- hear you back in your truer form.
Paul Cheng -- Scotia Howard Weil -- Analyst
Well I want to make up
Joseph W. Gorder -- Chairman, President and Chief Executive Officer
Yeah. I got a last three quarter.
Paul Cheng -- Scotia Howard Weil -- Analyst
Thank you.
Operator
Thank you. Our next question comes from Patrick Flam with Simmons Energy. Your line is open.
Patrick Flam -- Simmons Energy -- Analyst
Hey, guys thanks for taking my question. I really wanted to ask you about capital spending trend 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?
Lane Riggs -- Executive Vice President and Chief Operating Officer
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.
Joseph W. Gorder -- Chairman, President and Chief Executive Officer
Yes. It's not that unusual to find ourselves in this situation. 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...
Lane Riggs -- Executive Vice President and Chief Operating Officer
On to that point, I mean when we had tube leak at Benicia though, 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.
Patrick Flam -- Simmons Energy -- Analyst
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.
Gary Simmons -- Senior Vice President-Supply, International Operations and Systems Optimization
Yes. So obviously it's going to tight 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.
Patrick Flam -- Simmons Energy -- Analyst
All right. Great. Thanks guys.
Gary Simmons -- Senior Vice President-Supply, International Operations and Systems Optimization
Okay.
Operator
Thank you. Our next question comes from Jason Gabelman with Cowen. Your line is open.
Jason Gabelman -- Cowen -- Analyst
Yeah. Hey. Thanks for taking the questions. 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 of 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.
Gary Simmons -- Senior Vice President-Supply, International Operations and Systems Optimization
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 to shift 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. 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.
Jason Gabelman -- Cowen -- Analyst
Do you have a view if the world is kind of maxed out on how much octane it can produce right now?
Gary Simmons -- Senior Vice President-Supply, International Operations and Systems Optimization
Yes. I think the combination of the things Lane talked about with two or three gasoline destroying some octane and then globally refiners running a very light diet and the excess in naphtha and trying to fit naphtha back into the pool has caused octane to be very tight all the way.
Jason Gabelman -- Cowen -- Analyst
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 add implications for U.S. product exports. Is Valero thinking of kind of continuing its strategy to push its logistical region to new markets, similar to what it did in Peru to go to combat the potential for the Mexican market to close up a bit to the U.S. for product exports?
Gary Simmons -- Senior Vice President-Supply, International Operations and Systems Optimization
Yes. So we currently are exporting about -- that we sell ourselves 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 on logistics and able to get logistics that were meant to move crude out, not to move crude in. So it's going to be a long time coming before they can do much in terms of revamping their refinery system.
Joseph W. Gorder -- Chairman, President and Chief Executive Officer
Yes. I agree with Gary completely. And that if you look at the new plant that they have in mind, obviously the capital cost is -- would 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 in shorts is from the U.S. Gulf Coast.
Jason Gabelman -- Cowen -- Analyst
All right. Thanks for the time.
Operator
Thank you. And we have a question from Matthew Blair with Tudor, Pickering, Holt. Your line is now open.
Matthew Blair -- Tudor Pickering Holt -- Analyst
Hey, 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?
Joseph W. Gorder -- Chairman, President and Chief Executive Officer
Gary, you or Lane?
Gary Simmons -- Senior Vice President-Supply, International Operations and Systems Optimization
Yes. So I don't know that -- it's all a matter of economics of where alkylate plays. So we have flexibility where we can sell alkylate direct. The additional alkylate in the pool allows us to make more Bob versus Sea Bob [Phonetic]. 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. We have flexibility to do any of those things.
Matthew Blair -- Tudor Pickering Holt -- Analyst
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 ends up in this quarter. Could you just talk about what the constraints are? Why the volumes are coming in fairly low for Q3?
Lane Riggs -- Executive Vice President and Chief Operating Officer
Yes. This is Lane. We don't really give -- we just give the ranges. We don't really
give sort of maintenance guidance really. So we don't normally give the economic guidance. The economies are what they are.
Joseph W. Gorder -- Chairman, President and Chief Executive Officer
Yes, and, Matthew, you know what goes into the volume forecast. So it is what it is.
Matthew Blair -- Tudor Pickering Holt -- Analyst
I mean does this reflects like any sort of economic run cuts?
Lane Riggs -- Executive Vice President and Chief Operating Officer
No.
Matthew Blair -- Tudor Pickering Holt -- Analyst
Okay. Okay. Thanks.
Operator
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.
Homer Bhullar -- Vice President, Investor Relations
Thanks guys. 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.
Operator
[Operator Closing Remarks]
Duration: 60 minutes
Call participants:
Homer Bhullar -- Vice President, Investor Relations
Joseph W. Gorder -- Chairman, President and Chief Executive Officer
Manav Gupta -- Credit Suisse -- Analyst
Gary Simmons -- Senior Vice President-Supply, International Operations and Systems Optimization
Doug Leggate -- Bank of America Merrill Lynch -- Analyst
Prashant Rao -- Citigroup -- Analyst
Lane Riggs -- Executive Vice President and Chief Operating Officer
Benny Wong -- Morgan Stanley -- Analyst
Sam Margolin -- Wolfe Research -- Analyst
Neil Mehta -- Goldman Sachs -- Analyst
Martin Parrish -- Senior Vice President-Alternative Fuels
Jason Fraser -- Executive Vice President and General Counsel
Phil Gresh -- JPMorgan -- Analyst
Roger Read -- Wells Fargo -- Analyst
Paul Cheng -- Scotia Howard Weil -- Analyst
Patrick Flam -- Simmons Energy -- Analyst
Jason Gabelman -- Cowen -- Analyst
Matthew Blair -- Tudor Pickering Holt -- Analyst
