Good day, ladies and gentlemen, and welcome to Valero Energy Corporation's second quarter 2019 earnings conference call. At this time, all participants are in listen only mode. Later, we will conduct a question and answer session, and instructions will follow at that time. If anyone should require operator assistance, please press the star then the 0 key on your touchtone telephone. 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 have not received the earnings release and would like a copy, you can find one on our website at valero.com. 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. I'll turn the call over to Joe for opening remarks.
Thanks, Homer. 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. 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. 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. 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 NGLs and refinery olefins to produce a premium alkylate product. 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. 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%-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. With that, Homer, I'll hand the call back to you.
Thanks, Joe. For the second quarter of 2019, net income attributable to Valero 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 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 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-1.76 million barrels per day, U.S. Midcontinent at 440,000-460,000 barrels per day, U.S. West Coast at 255,000-275,000 barrels per day, and North Atlantic at 460,000-480,000 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 non-cash 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 non-cash 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 and $400 million. That concludes our opening remarks. Before we open the call to questions, we again respectfully request that callers adhere to our protocol of limiting each turn in the Q&A to two questions. If you have more than two questions, please rejoin the queue as time permits. This helps us ensure other callers have time to ask their questions.
Thank you. Ladies and gentlemen, if you have a question at this time, please press the star, then the one key on your touchtone telephone. If your question has been answered or you wish to remove yourself from the queue, press the pound key. Our first question comes from Manav Gupta from Credit Suisse. Your line is open.
Hey, Joe. 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 are seeing about $8.50 or $9 widening in the next six months. Since HSFO makes up 40% of the Maya pricing formula, mathematically translates to about $3-$4 widening of Brent Maya. 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?
Well, good morning, Manav, that's a really good question. Why don't we let Gary give you some insight into that?
Yeah, Manav. 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. 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. 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 a domestic light sweet alternative such as MEH, Western Canadian Select is trading at an 11% discount to MEH.
The forward market on the Canadian side, at least there's trade being done in the fourth quarter already, you're seeing Western Canadian Select discounted around $2.50 in the fourth quarter already. 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 a deal with the government is struck. They could see rail ramping by 250,000 to 300,000 barrels by year-end. 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 are running?
Yes, pretty much. 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.
Thank you, guys, and congrats on a good quarter.
Thank you.
Thank you. Our next question comes from Doug Leggate with Bank of America Merrill Lynch. Your line is open.
Thanks. Good morning, everybody. Morning, Joe.
Morning, Doug.
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 unit is helping a little bit on NGLs. As we look into the second half of this year and into 2020, the expected ramp-up from the Permian is coming with a lot of question marks over what the gravity of that crude's going to look like and the potential for a 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? 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.
Yeah. Doug, this is Gary again. 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 quote coming out, which is a lighter grade of WTI. We've 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. 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. We're certainly moving that direction and watching the spreads.
If the discount is there, we have a lot of flexibility to be 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's pretty much within the constraints of the system. However, the new toppers we built at Corpus in Houston give us a lot more flexibility in this area.
Great stuff. My follow-up.
In addition to that one, we're going to expand our saturated gas plant at Port Arthur as a part of the Coker project. 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, 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 IMO on distillate margins eased any, or are you still pretty constructive on the disruptive impact as we go into next year? I'll leave it there. Thank you.
Thanks, Doug. I guess our view all along has been that we would probably start to see something late third to fourth quarter of this year. It's been interesting to us that the forward markets really haven't reflected the distillate impact. I think we're starting to see it other places, but you guys want to share your views?
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 not a very liquid market today, and ships are having trouble actually buying high sulfur fuel, which is bidding that market up today. You see the steep backwardation as we approach that January timeline. 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.
All right, guys. Thanks for your time. I appreciate it.
Thanks, Doug.
Thank you. Our next question comes from Prashant Rao with Citigroup. Your line is open.
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. You're still running strong there. As you 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? As you're looking at incremental rail contracts, could you give us some idea what sort of duration maybe you're thinking? Do you have the contracts in handy and we're just going to see that sort of flex up in the numbers as we go forward, as we 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 it to those two assets. Between those two refineries, probably a capacity of about 300,000 barrels a day today to process it. We can run about 50 a day at St. Charles, and we could run some at Corpus Christi as well. Again, the logistics of getting that in are more challenged. On the rail side, we continue to work with producers and we're kind of doing deals on a delivered basis, whereas in the past, we were buying barrels in Western Canada and shipping them ourselves. That volume will continue to ramp up as we get those deals done.
Okay, thank you. It's very helpful. Then just touching back on sort of a bigger picture question. With the Houston ALKY project getting completed, wanted to take a step back and get your views on where U.S. refining, the whole system in the country stands in terms of Tier three compliance. I think we're getting a few more questions. There's been so much that we're looking at in refining in terms of the macro, but a few questions and maybe concerns about how tight octane is going to get by the time we get to 1Q 2020. Just your updated views of how you think the system stands today in terms of the progress we're making. Then, I guess relatively speaking, where your position is relative to that. Feels like you'd be advantaged in that kind of a tight octane market.
Any color you can provide there would be helpful. Thanks.
Yeah. This is Lane. We have 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. Combine that with sort of cheap NGLs. That was the reason we did these projects, and they're coming online exactly the right time. We believe we're seeing octane get more and more expensive. In terms of where the industry is on its tier 3 compliance, we're looking at that ourselves. If you look at us as a proxy for that, we still have three units that have to come online by the end of the year. 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.
Right. They've been using credits.
Yeah, they were using credits. To the extent you could use credits, you deferred the capital. 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.
All right. That's very helpful. Thanks, Joe. Thanks, Blaine. Thanks, Gary. Appreciate that.
Take care, Prashant.
Thank you. Our next question comes from Benny Wong with Morgan Stanley. Your line is open.
Hi, guys. Just wanted to ask about the capture rate in the second quarter. It was particularly weak in the U.S. Gulf Coast. Understand the light heavy differentials probably contribute to that. Just wanted to get a sense if there's any other factors weighing on that, if there's any risk of those factors persisting? Conversely, in North Atlantic, the capture is really strong. It has been strong for a couple of quarters. Just wanted to get a sense, is it Europe or U.S. driving that? Should we expect a higher capture level going forward?
Hey, Benny, this is Lane. Prashant, I'm sorry, a while ago I called you Benny. In the Gulf Coast is a good proxy for what, in terms of capture rates. We're down about 20% year-over-year. About 10%-12% of that is crude differential. Some of it's arb, some of it's just quality. The remaining 7%-8% of that 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. You can sort of come to your own conclusion about what direction propylene is going to, and obviously propane and NGLs are just getting cheaper and cheaper with all the shale.
We're still optimistic that, the rest of it, we're optimistic, 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. They're probably structurally pretty weak for at least some period of time here. On the Line nine or Atlantic, really what you're seeing on the North Atlantic capture rate is our continued advantage position on our Line nine crudes.
Got it. Appreciate the color there. My follow-up is really, one of your peers that's 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?
On that follow-up.
Yeah. I guess what you're saying is where we have fuel oil length, potentially taking it to open coking capacity. Is that the question?
Yeah. 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, exactly what you're saying.
Yeah. 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 we produce at Monroe and potentially run it into Port Arthur Coker when it's expanded.
To Gary's point, what you'll actually see, so we plan to be full both coker and like you said, we don't make much fuel oil as a system, but what it does do is it competes just like some of the long resids today that competes for crude capacity. We do believe you're going to see more and more of that as some of these blending components that were in three and a half weight % fuel oil will be ultimately have to probably get ran through crude units and compete with other medium and heavy sour crudes. 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.
Got it. Great color, guys. Thank you.
Sure.
Thank you. Our next question comes from Sam Margolin with Wolfe Research. Your line is open.
Morning, everybody.
Good morning.
Lane, can I ask you a follow-up about the capture rate impact and naphtha? You sort of touched on something that's swirling around the market. Was there anything Were you producing sort of excess naphtha or NG or LPGs for any reason besides just an increase in light crude throughput in the Gulf Coast? Was there something coming out of the one two turnarounds 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. We did have the turnarounds, and so I'd have to go back and if anything, we would've ran more crude and had more naphtha. Our reformers were full. Right now, one of the most economic units, in addition to alkies, are reformers, and so we would have had our reformers signaled full. I'd have to go look and see what the balance was on naphtha. We weren't. Directionally, it's just we make. We have a position on naphtha and it goes, if we get longer, as we run more and more light sweet crude.
I think exactly. It's really more of a function of the crude diet. The other factor is a lot of the U.S. Gulf Coast naphtha was going to Venezuela as diluent. Certainly as that has shut off, it's caused naphtha to get weaker.
Okay, thanks. 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. They have a. It's going to be interesting to see how they fit in the IMO 2020 universe. There's some belief that you can burn directly. I'm not sure that's the highest value for them necessarily, but. There is some substitution effect. As you've seen, some of these heavy sour crudes come off. These are substitute crudes for coking refineries. They've certainly gotten to where that's not necessarily the best grade. The other thing they have is they don't have a lot of naphtha in them. It's the world just sort of resorting out that quality.
Yeah, 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.
All right. Thanks so much.
Thank you. Our next question comes from Neil Mehta with Goldman Sachs. Your line is open.
Good morning, team.
Good morning, Neil.
First question is around renewable diesel. We're 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? Related to this 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. Just any high-level thoughts on this 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.
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 till 2030. You've got the Low Carbon Fuel Standard in California out to 2030. There's talk on again, off again about Canada adopting a standard. We're bullish to this, and we're actively evaluating opportunities for expansion when 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 this second quarter with no Blender's Tax Credit. If you look in California, they're already blending at 10% renewable diesel. There's really no limit to where you can get with renewable diesel. It meets the same specs as hydrocarbon diesel. We feel good about the prospects.
We've got a great partner with Darling for the feedstock procurement and the front-end processing. We plan to keep growing the business.
Yep. Jason, anything on the Blender's Tax Credit?
As you all probably know, the Blender's Tax Credit expired at the end of 2017. Both the Senate and the House tax-writing committees are looking at bills to extend it. They've got a bill that'll extend two years in the Senate. The House has a bill that'll extend it for three years. We're not sure exactly how it'll get done or which bill it'll get attached to, but we're confident it'll 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. No, 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. Just any thoughts in terms of how we should think about the RINs market from here, especially because there's uncertainty around the degree of waivers for Small Refinery Exemptions here in 2019.
Yeah, sure. This is Jason. I'll give you all our update on some of the recent developments on the RFS front. On June 15th, the EPA published their final rule, which granted the one-pound RVP waiver 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. We also understand there will probably be a legal challenge to whether the EPA has authority to grant that waiver as well.
That's going to be an additional weight on the market as people wait and see if the additional waiver holds up. There is definitely some question about whether the EPA has the authority to do that or whether it has to be done by Congress. 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 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. 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 have them granted this year. This is despite multiple studies that show the SREs haven't led to any real biofuel demand destruction.
That SRE process is very well established as part of the RFS statute. The EPA has gotten guidance from Congress as well as several court cases on how to administer them. 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.
Great. Thanks, Jason. Thanks, Joe.
Yes.
Thank you. Our next question comes from Phil Gresh with JPMorgan. I'm sorry, yes, with JPMorgan. Your line is open.
Yes. Hi, good morning. A couple of quick ones here. One is, as we continue to see these increased flows out of the Permian to the 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?
Yeah. Phil, our focus here has really been get connected to all the lines that make their way to Corpus, and we've made a lot of progress there. We can receive pretty much all of the lines that are coming in. We're also doing some dock work at Corpus to where we can export more to Quebec and Pembroke.
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, I guess what you're asking more about is there enough dock capacity to clear the oil? 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's 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, 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?
Yeah. Phil, it's just all a matter of price. We have plenty 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 a $1.25 type discount to MEH. We've seen some incentive to buy it, if that's the case, we certainly have a lot of capacity to run it, but it will depend on how it prices.
Okay. All right. Thank you.
Our next question comes from Roger Read with Wells Fargo. Your line is open.
Yeah, thanks. Good morning, guys. Come back, Lane, your comments about the Gulf Coast and the light, heavy differentials, the impact that's had. 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. I just wonder if you could give us an idea of how that's happened. It seems a little contrary to 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 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.
Yeah. Roger, well, what I would say is, we did have the FCC down in Houston, that whole FCC Houston alkylation complex was down for a big chunk of the quarter. Consequently, our gasoline production was off. In terms of naphtha, again, the signal's been max reformer the whole time, right? As you increment into the light suite, at least for us, and I believe the industry's in the same spot. As you run more and more light suite, more of it has to be exported, and ultimately it clears in the Far East. It doesn't go into the gasoline.
There'll be, I am sure part of what's happening right now with this tier 3 is saturating the gasoline and lowering octanes, and there's just an abundance of naphtha that everybody's trying to figure out a way to get naphtha back into the gasoline pool, you need octane to do that. Right now, the industry's trying to figure out that balance as, again, as tier 3 is getting implemented.
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 come from. Historically, India exports 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 as a gasoline blend component, with where it prices, you have an incentive to blend naphtha with toluene to make gasoline. That's another source of octane.
To Gary's point on the issue you have around that, at some point on the reformulated gasoline fuel, you'll reach a toxics limit. That's where alkylate's really important. As you get more alkylate in the pool, it allows you to incrementally raise the amount of aromatics in the gasoline as well. Yeah. Anyway.
We could probably spend the whole call on these kind of intricacies.
Yeah. Absolutely.
As a follow-up question, ethanol really weak. You did the acquisition. I don't remember if it closed at the very beginning of the year or the very end of last year. 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. I was just wondering, light at the end of the tunnel, is it a 2020 thing? We have to know how the 2019 corn crop turned out? Is it the trade issues with China? Maybe an order of what matters and magnitude of those events, if you could.
Hey, Roger, this is Martin. The market's tough. If you look at this is the latest corn crop, really in the history of the records in which go back 40 years. You got the latest corn crop, and right now, 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. There's just a lot of uncertainty how big is the crop. What really matters is the carry-out at the end of this 2019 crop year. Nobody knows at this point. There's still weather that could impact it. It's going to be hard to have
Real big ethanol margins for this crop year in the U.S. Obviously, if China opens up, that helps a lot. That's a little different story, right? They have a 10% mandate. That would make a big difference on the exports right away. Absent that, you saw our forward guidance is lower than we ran. 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 five years now where yields have been above trend. It's due for one below it. 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.
Two things I would add to what Martin said. First of all, the industry is just overproduced from what gets blended in today. That's the fundamental problem here. What have we done? We've ramped up exports as an industry. That's where tariffs become a factor in these things. It takes a while to develop markets. Valero has been very aggressive at exporting ethanol and will continue to be aggressive going forward. The other thing Jason spoke to this earlier was the whole E15 issue. The ethanol industry broadly has this notion that 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. 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 and market broadly. If we could just get everybody synced up. This is one of those things where amazingly, the autos are on board, the retail marketers are on board, refineries are okay with it. If the ethanol industry would see that this was a good solution to this problem that we're facing, perhaps we could make some progress. There's a genuine distrust, and we're going to have to get over that. 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.
Yeah. Probably part of the problem of building it on a mandate as opposed to a market incentive to pull more product in. All right. Well, thank you.
You bet, Roger. You got it.
Thank you. Our next question comes from Paul Cheng with Scotiabank Howard Weil. Your line is open.
Hey, guys. Good morning.
Is this Paul Cheng?
Believe it or not.
Hey, welcome back, my friend. It's good to hear your voice.
Thank you.
We missed you.
Yeah. Well, I missed you guys, too. Two quick question. Maybe this is either for Ming 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, how are you guys going to go around to get there? Are you going to take the VGO, or that you're trying to brand the high sulfur fuel oil into that? What do you think the industry approach is going to be?
Yes. Paul, we've been working very hard to develop low sulfur fuel blends. We've worked with several shipping companies. We currently have, I think, three shipping companies burning our low sulfur fuel blend. We've been working hard to be able to produce compliant fuel.
Gary, can you share with us what is the path or the approach that you guys take? It seems like very inefficient to trying to use the high sulfur fuel oil and brand it with the ultra-low sulfur diesel into that. It seems like that it more makes sense to using the VGO. If that's the case, we will have a major problem of the much lower gasoline yield.
Yes, that's exactly right, Paul. What we're looking at is some of these low sulfur, heavy streams that we typically run to our cat crackers. Taking some of those barrels out and being able to blend compliant low sulfur fuel with those, rather than taking a high sulfur fuel oil stream.
I think what Paul is implying, the two places that we're doing that really are at Pembrokeshire and Quebec. We really don't start with a high sulfur residue. We start with something that's maybe a moderate sulfur and it depends on the crude economics. Then we start blending it up.
I see. Gary, I think that you guys, for the industry as a whole, do you think how much is the VGO they're 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, into the gasoline, and obviously back to this low sulfur fuel oil market. Therefore, it's supportive of gasoline, to your point earlier. 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. I think a lot of people thought they'd be disconnected, but they're not. It's really through the VGO. 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 you can get into the blends.
Mm-hmm. Hey, final question. Even if we can fix the diesel issue, the resulting high sulfur fuel oil seems like it's still going to be a problem. You don't produce [any] , indeed, you are a net buyer of the resid. If resid price crash down to zero, it will be great for you. Any idea that, what is really the alternative use that we can do with all the excess high sulfur resid?
It's primarily power generation. That's sort of 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 this high sulfur fuel oil. Our belief is that it's still long, particularly once OPEC starts recovering into production. That's why we feel good about our assets in light of this problem that you're talking about.
Mm-hmm. How easy for the industry be able to fit the high sulfur resid back into the coker and use it as a feed? 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, and we run a lot of resid, so we have a pretty good understanding. The issue you get into is you got to find a way to run it and maintain your desalter operation that's heavier. It doesn't have the light stuff, so you don't get good mixing, and there's other challenges. It depends on the configuration of the refinery. I'm sure as it gets distressed in the marketplace, everybody will try to accelerate and figure out how much they can run.
Thank you.
Hey, Paul, it was good to hear you back. You were true to form.
Well, I want to.
You did dial in.
I want to make up that lost time if possible.
Listen up.
Yeah. Listen up. You got a last three-quarter.
Take care, buddy.
You too.
Thank you. Our next question comes from Patrick Flam with Simmons Energy. Your line is open.
Hey, guys. Thanks for taking my question. 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 a billion and a half 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. It's a blend. Both those. We had a pretty heavy turnaround period, and we don't have nearly as much turnaround activity for the rest of the year. Two, you're just not as productive those last two or three months of the year because of all the holidays. It's really a combination of that.
Thanks.
It's not that unusual to find ourselves in this situation. Things will move a little bit within this. Sometimes we're slightly below, sometimes we're above. The $2.5 billion number is just kind of our nominal expectation of what we're going to spend. Again, you kind of do it as you have to.
To that point, when we had the tube leak at Benicia, that was a turnaround that we had planned in the first quarter of 2020 that we had to bring into this year. We had to bring in, I don't know the number, $80 million or $90 million of turnaround spend from one year to the next. 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 impacts from the potential closure of the PES refinery on the East Coast.
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. Our strategy in that region has been able to supply the market primarily from Pembroke. We have good logistics assets in place to be able to take advantage of that short. Pembroke is a refinery that has a lot of capability to produce octane. That's primarily what we're working on today.
All right, great. Thanks, guys.
You bet.
Thank you. Our next question comes from Jason Gabelman with Cowen. Your line is open.
Yeah. Hey, thanks for taking the questions. I actually wanted to follow up on the Philadelphia Energy Solutions closure. Obviously, gasoline margins strengthened off the fire and have come back a bit, and I am wondering what you attribute the increase to and if you think that is going to be sustained through 3Q. It seems like there is a lot of gasoline supply in the market, so I wonder if it is a matter of once 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. I have a follow-up. Thanks.
Yeah. This is Gary. I think our view is, if you look at the DOE stats from the last couple of weeks, it looks like demand has been down, our view is that demand will be revised back upward, and that you will see actually net exports fall off. 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, it incentivized imports there. PADD 5, we saw imports even after the refinery utilization came back. In the US Gulf Coast with the octane strength, we are seeing some import of components into the US Gulf Coast as well.
Demand is good. The net exports, mainly due to imports being down, is what has caused the build that we have seen in the last couple of weeks. It does look like the market is cooling off some, and you are already seeing signs that that is reversing, especially in PADD 5. We have gone from seeing imports to it looks like a couple of refiners are putting export cargoes together, and you are seeing barrels from California flow into the Arizona market to help clear that as well. I do think it is a trend you will see reverse.
Do you have a view if the world is maxed out on how much octane it can produce right now?
Yeah. I think the combination of the things Lane talked about, with tier 3 gasoline destroying some octane, 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. If I could just ask a follow-up. Mexico is working to revamp its existing refineries in addition to building a new one. Assuming they're successful on the former, it could have implications for U.S. product exports. Is Valero thinking of continuing its strategy to push its logistical reach into new markets, similar to what it did in Peru to combat the potential for the Mexican market to close up a bit to the U.S. for product exports?
Yeah. We currently 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. It's going to be a long time coming before they can do much in terms of revamping their refining system.
Yeah. That, I agree with Gary completely. 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're 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. Certainly the most efficient way for Mexico to supply its shorts is from the U.S. Gulf Coast.
All right. Thanks for the time.
Thank you. We have a question from Matthew Blair with Tudor, Pickering, Holt. Your line is open.
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?
Yeah. Hey, Matthew. Gary, you or Lane?
I don't know that it's all a matter of economics of where alkylate trades. We have flexibility to where we can sell alkylate direct. The additional output 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. 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. I think the top end of your throughput guidance for Q3 2019 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?
Yeah. This is Lane. We just give the ranges. We don't really give any sort of maintenance guidance, really. I'll just leave it at that. We don't normally give that kind of guidance. The volumes are what they are.
Yeah. Matthew, you know what goes into the volume forecast, so it is what it is.
Does this reflect any sort of economic run cuts?
No.
Okay. Okay, thanks.
Thank you. 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, Catherine. 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.