Valero Energy Corp (VLO) — Q2 2017 Earnings Call Transcript

Good morning, and welcome to Valero Energy Corporation's second quarter 2017 earnings conference call. With me today are Joe Gorder, our Chairman, President and Chief Executive Officer; Mike Ciskowski, our Executive Vice President and CFO; Lane Riggs, our Executive Vice President of Refining Operations and Engineering; Jay Browning, 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. Also attached to the earnings release are tables that provide additional financial information on our business segments. If you have any questions after reviewing these tables, please feel free to contact our Investor Relations team after the call. I would like to direct your attention to the forward-looking statement disclaimer contained in the press release. In summary, it says that statements in the press release and on this conference call that state the company's or management's expectations or predictions of the future are forward-looking statements intended to be covered by the Safe Harbor provisions under federal securities laws. There are many factors that could cause actual results to differ from our expectations, including those we've described in our filings with the SEC. Now, I'll turn the call over to Joe for a few opening remarks.

Well, thanks, John, and good morning, everyone. We're pleased to report that we completed another quarter where we ran our refineries very well at high rates, and also delivered good financial results. Our low cash operating cost and highly reliable operations, combined with our advantageous footprint focused on the U.S. Gulf Coast and the Mid-Continent, enabled us to achieve positive earnings and free cash flow generation, despite the choppy margin environment. As always, our team's primary focus is on safety and reliability, and we continue to deliver distinctive operating performance, but we remain committed to improvement. As such, we're extending our participation in OSHA's Voluntary Protection Program to more of our facilities. Moving on to the refined products markets, we're pleased to see a rebound in distillate demand, in addition to the strong gasoline pull by domestic and export customers. Downward trends in product inventories and structural shortages in the primary export markets for the U.S. Gulf Coast provide an encouraging backdrop as we move into the second half of the year. On the crude supply side, we're seeing the impact of the OPEC cuts on the medium and heavy sour discounts, but increased U.S. drilling activity and crude production have supported attractive domestic sweet crude discounts relative to Brent in the second quarter. As a result, we switched our refining system to a maximum light crude slate in June. With current market conditions, operating a system with flexibility to process a broad range of feedstocks is very beneficial. Turning to capital allocation, we continued to execute very well on our capital program during the quarter. The Diamond Pipeline and Wilmington cogeneration plant are both on track for completion this year. Construction is continuing as planned on the Diamond Green Diesel expansion and the Houston alkylation unit, and we're looking forward to seeing the additional earnings contribution from all of these projects once they're complete. We continued demonstrating our commitment to stockholders by returning $658 million through dividends and stock buybacks in the second quarter. At this pace, we believe we're well positioned to exceed our payout target for the year. Lastly, on the topic of public policy, we get many questions seeking our perspective on the various initiatives being worked on by the Trump administration. While it's difficult for us to speculate on the range or probability of potential outcomes, we're pleased with the emphasis that President Trump and his administration have placed on the energy sector, and their willingness to discuss the issues. So, with that, John, I'll hand the call back to you.

Thank you, Joe. For the second quarter, net income attributable to Valero stockholders was $548 million, or $1.23 per share, compared to $814 million or $1.73 per share, in the second quarter of 2016. Second quarter 2016 adjusted net income attributable to Valero stockholders was $503 million, or $1.07 per share. For reconciliations of actual to adjusted amounts, please refer to the financial tables accompanying our release. Operating income for the refining segment in the second quarter of 2017 was $959 million, compared to $1.3 billion for the second quarter of 2016, which has been revised retrospectively to reflect the VLP segment. Second quarter 2017 operating income was in line with second quarter 2016 adjusted operating income of $902 million. Refining throughput volumes averaged 3 million barrels per day, which was 192,000 barrels per day higher than the second quarter of 2016. Our refineries operated at 96% throughput capacity utilization in the second quarter of 2017, despite an external power failure at the Benicia Refinery that caused an abrupt shutdown and unplanned maintenance. Refining cash operating expenses of $3.51 per barrel were $0.10 per barrel higher than the second quarter of 2016, mainly due to higher energy costs in the second quarter of 2017. The ethanol segment generated $31 million of operating income in the second quarter of 2017, compared to $69 million in the second quarter of 2016. Adjusted operating income for the second quarter of 2016 was $49 million. The decrease from the 2016 adjusted amount was primarily due to higher energy costs and strong industry ethanol production. Operating income for the VLP segment in the second quarter of 2017 was $71 million compared to $52 million in the second quarter of 2016, mainly due to contributions from the Meraux and Three Rivers terminals, and the Red River pipeline, acquired subsequent to the second quarter of last year. For the second quarter of 2017, G&A expenses, excluding corporate depreciation, were $178 million, and net interest expense was $119 million. Depreciation and amortization expense was $499 million, and the effective tax rate was 26% in the second quarter of 2017. The effective tax rate was lower than expected mainly due to the favorable resolution of an income tax audit. With respect to our balance sheet at quarter end, total debt was $8.5 billion, and cash and temporary cash investments were $5.2 billion, of which $88 million was held by VLP. Valero's debt to capitalization ratio net of $2 billion in cash was 24%. At the end of June, we had $5.4 billion of available liquidity, excluding cash, of which $720 million was available only for VLP. We generated $1.8 billion of cash from operating activities in the second quarter. Excluding a working capital benefit of about $700 million, net cash generated was $1.1 billion. Regarding investing activities, we made $461 million of growth and sustaining capital investments, of which $63 million was for turnarounds and catalysts. Moving to financing activities, we returned $658 million in cash to our stockholders in the second quarter, which included $312 million in dividend payments, and $346 million for the purchase of 5.4 million shares of Valero common stock. As of June 30, we had approximately $1.9 billion of share repurchase authorization remaining. Capital investments for 2017 remain on track for $2.7 billion of total spend. This amount, which includes turnarounds, catalysts, and joint venture investments, consists of approximately $1.6 billion for sustaining and $1.1 billion for growth. For modeling our third quarter operations, we expect throughput volumes to fall within the following ranges: U.S. Gulf Coast at 1.65 million barrels per day to 1.7 million barrels per day, U.S. Mid-Continent at 445,000 barrels per day to 465,000 barrels per day, U.S. West Coast at 280,000 barrels per day to 300,000 barrels per day, and North Atlantic at 440,000 barrels per day to 460,000 barrels per day. We expect refining cash operating expenses in the second quarter to be approximately $3.80 per barrel. Our ethanol segment is expected to produce a total of 3.9 million gallons per day in the third quarter. Operating expenses should average $0.39 per gallon, which includes $0.05 per gallon for non-cash costs, such as depreciation and amortization. We expect G&A expenses, excluding corporate depreciation, for the third quarter to be around $190 million, and net interest expense should be around $115 million. Total depreciation and amortization expense should be approximately $500 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. This helps us ensure all callers have time to ask their questions. If you have more than two, please rejoin the queue as time permits.

Hey, good morning.

Morning, Phil.

First question, just on the quarter itself, in terms of the situation at Benicia. I know there's been some press about this. I was wondering if you could just elaborate on it a little bit. What would you quantify as lost opportunity cost from it? It sounds like you're back, up and running, but just if you could clarify that as well.

Yeah, Phil, this is Mike. We did – yeah, we are back, up and running. The opportunity is about – it's over $100 million in this loss. Using $100 million can give you some perspective; that would equate to about $0.16 per share. So, our second quarter earnings should have been around in that $1.40 range.

And we're back up and running at this point?

Yes, we are.

Yes, we are.

Got it, okay. Okay, second question is just on the capital spending. It feels a lot like last year, where you're trending well below the $2.7 billion number and kind of running closer to about $2.2 billion. So, is there anything big, specifically in the second half, we should be thinking about from a turnaround standpoint, growth capital standpoint, that would lead to a big pickup?

I mean, our guidance right now is still $2.7 billion. We are trending a little bit below that. We have the completion out of a few of the projects that Joe talked about in his comments. So, we'll be reviewing this as we go throughout the balance of the year, and see if we need to give any updated guidance.

Okay. Thanks.

Thanks, Phil.

Hey, guys, good morning.

Morning, Paul.

Two questions that maybe I don't know whether it's Gary or whether Lane is here. In your refining system, you've been doing phenomenally well for the last several years. Utilization rate is up, and more reliable. So, why not that realistically should we assume that this is as good on a sustainable run rate that you may be able to achieve or do you actually think that the sky is the limit, and you will continue to be able to push it upward?

Hi, Paul, this is Lane. I'll take a stab at it. We obviously always focus on reliability. Even though we know we outperform our peer group in this space, there's always room for improvement. We have a whole portfolio of 14 refineries. Some are absolutely excellent in the area of reliability, and some not so much. And so, we can continue to work on those and get better. But, that's really what we're focused on, trying to be reliable. And through reliability, we think it's the path to lower operating costs because we minimize the one-time events. So, there's still upside with respect to our reliability over the long haul. I mean, I think the area that we continue to really focus on is improving our turnaround duration. That's really the last – our cost structure is great. We just want to get – that's the area that we think we can work on. So, essentially, try to do these – expanded to raise the interval between turnarounds, and execute on time and certainly be very predictable on that.

And if you could quantify, say is it going to be another 1%, 2%? Any kind of range that you can help?

I'd have to get back with you on that, Paul. I don't know that we can – I don't know that we have estimated a range for that. The measure we use internally for our reliability is a Solomon indicator for mechanical availability, and I would say it's probably on the order of 0.5% to 1% probably improvement is still in front of us.

Okay. The second question is for Joe. Joe, it's a little bit of the curveball. The last month or so, we have heard the number of countries in Europe, such as in UK and France, talking about, by 2040, they would stop the sale or ban the sale of the gasoline and diesel car. Just curious that in the board that when you guys are looking at that, is that a threat the board actually spend a lot of time at all? Or do you think say another 20 years to 30 years out is just way too premature to really be thinking too much on that?

Paul, last year, at our strategic planning session, we met with the board and talked about the long-term viability of fossil fuels. So, the products that we produce. And every analyst that we read believes that, and people are doing 20-year outlooks, they all stated that we are going to see continued demand for gasoline and diesel fuel into the extended future. This news, I believe that you're talking about, I guess, we saw it a couple of days ago, yesterday or day before, on the EU moving away from fossil fuel vehicles by 2040. And it's not a surprise that things like that get proposed. But it's so far out on the horizon, and so many things change that it's not something that we would change our strategy today to try to deal with. Jason, is there anything that you'd add to that?

I'd just add – kind of echo what you said. Specific to the UK announcement, it seems like they're really focusing on improving their air quality, specifically fighting nitrogen dioxide emissions. And 2040 is a way out. I mean, it's hard to say what pollution control or other technologies could evolve during that time, which may lead to different policy actually being implemented by the time you get to 2040.

So, Paul, just to summarize, I think it's not an issue that we believe is material enough right now that it's something that we need to alter strategy or visit with the board extensively about.

Thank you.

Hey, good morning, everyone. Thanks for taking the question. Just want to start off with Mexico. I believe we've seen some headlines suggesting that maybe they already made or are in the process of getting permits there, expanding into Mexico and the wholesale market. Just wondering if you could provide anything on that front.

Yeah, I can, this is Gary. We are looking to build upon our current supply relationship with Mexico, as opportunities for product demand growth appear to be there. We believe our refineries are well positioned to allow us to be the cost-advantage supplier into Mexico. We are in the final stages of securing a major supply arrangement in Mexico, but we have certain confidentiality obligations that prohibit us really from talking about it at this time. We're working on some pretty exciting things, and we'll be able to share our Mexico strategy with you in the near future.

Totally understand. I appreciate that color. And second, Joe, you mentioned the RFS, and the fact that you're encouraged just purely by the fact that the administration is willing to listen. I guess, I'm just wondering for sort of gauging our optimism on some sort of relief, is that really the only thing to be excited about, is that they're actually listening? Or do you feel like real relief is something we should expect maybe November or sometime next year?

Boy, that's really a great question. Why not let Jason take a crack at this, and then we'll see if there's anything to add.

Sure, yeah, this is Jason again. One thing that happened recently were the proposed RBOs were released by the EPA, and they were generally what we were expecting. We're pleased to see the reductions in the cellulosic and advanced targets, which seem to be more in line with the volumes that are actually being produced. Regarding the RIN prices, the RBO really didn't change our outlook for what we foresee on the horizon. On the volume side, we still have a 15 billion gallon conventional ethanol target, which has the industry butting up against the blend wall. And the blend wall is a real challenge in light of vehicle warranty, equipment compatibility and other issues. One positive note was, EPA did mention in the proposed RBO that they would be looking at possibly using their reset in the future, which is encouraging. That's a tool they have at their disposal. We also still have this broken structure with a disconnect between the point of obligation and the point of compliance. There're still very long parties and very short parties, and we think this is contributing to the high RIN prices, which are costing consumers billions of dollars a year. We are still hopeful the EPA is going to address the point of obligation. Our petition is still outstanding, and the docket is still open. These high RIN prices really aren't benefiting corn farmers or ethanol producers. It's just the RIN-long parties. They're not leading to more ethanol blending because the parties who control the blending are benefiting from the high RIN prices. So they just have no incentive to push to the blend wall. So, we're hoping this is a situation we can get addressed.

We have been continuing to work this very actively, and really the administration has been very receptive to conversations around this. They are trying to do what's right and to fix broken processes. And so, we remain hopeful that point of obligation is dealt with properly, and we also are hopeful that the EPA uses its authority to adjust the RBOs to ensure that the blend wall doesn't become a chronic problem going forward.

Got it. Really appreciate the comprehensive answer. Thanks, guys.

Thanks.

Hi, everyone.

Morning, Brad.

Morning, Joe. You or Gary, I'm just wondering your thoughts on if we see sanctions on Venezuela, what the impact on Valero's crude sourcing could be. Do you think that there will be difficulty securing heavy volumes? Or is it only going to be a price effect, if there is a price effect? Any color there would be great.

Yeah, Brad, this is Gary. We've had a longstanding, very good relationship with PDVSA, and they've been a good crude supplier to our system. The way we view any potential sanctions is, it really just creates some inefficiencies in the crude market. So, the natural trade flow for a lot of Venezuelan production should be to the U.S. Gulf Coast. If sanctions were imposed, those barrels will continue to flow. They'll just flow to other markets, and then we'll have to buy barrels away from other markets to supply our system, which will cause the cost of the heavy crude to go up some. It's really impossible for me to speculate how much the cost impact that would be.

Okay. Thanks for that. And then, Joe, I feel like we kind of have this conversation every quarter. But you guys continue to come in far above the payout target, and I think that you've come in above it ever since you've had the payout target. So, is that just an artifact of being in a lower crude spread environment right now that the earnings are depressed, but the cash flows aren't? Or is there a time in the future when we could see that target move higher?

Well, I mean, that's a good question, too. We are producing significant amounts of free cash flow, and we've been consistent in using the capital allocation framework that we've got in place to help guide our use of cash. The one thing that we've shared is that we don't have an intention to continue to build huge stockpiles of cash because Mike's got the balance sheet in a place where with our low debt to cap, if we wanted to do something we could do it. So, I think you should anticipate that we're going to continue to execute similarly to what we've done in the last several quarters. We always evaluate share repurchase versus dividends, and we would like to be in a position to continue to increase the dividend going forward. But to the extent that we have free cash, we're going to use it. Mike, anything you'd add to that?

In addition to the payout target, we do look at, I mean, obviously, our operating and financial results, our cash flow, our cash position, and then competing uses of that cash. So, the target is just one thing that we look at. And Joe said, our plan is not to hoard the cash, but we're going to continue to invest in our business, and then also buy back shares, if that's the best alternative.

Okay. Appreciate the answers, guys.

Thanks, Brad.

Hi, good morning, everyone. This is kind of maybe not a follow-up, but maybe should have been a prequel to the previous question, Joe, which is about where you think we are in the cycle. Because, the way I see it, oil has settled around $50 per barrel, and looks like that kind of down the strip. Your earnings have been fairly stable. We've mentioned that you've been doing a great job of paying out cash. I guess one exception might be the OPEC cuts and whether that changes things. And the other thing I wanted to sort of address, and this is a bit convoluted, but also how you see seasonality now. And then, to be specific, to start you off, you said you maximized out your light crude consumption. Could you just specify or remind us what that number is?

You bet, Paul, and I'll let Gary take a crack at this.

Okay, to start with, on the light processing capability, we now say we can run about 1.6 million barrels a day of light sweet crude. In the second quarter, we were a little below 1.4 million barrels a day, so about 88% of our capacity was utilized in the second quarter. The third quarter, we'll see that trend up a little bit more. Some of it has been, some of the domestic medium sours have still been economic to run, and that's why we're not completely at 100% of our capacity in the system. On the discussions on margins, we tend to look at a mid-cycle case. And our view is that where current margins are, they're below mid-cycle. The gasoline cracks are good, slightly above mid-cycle. But the diesel cracks have been fairly significantly below our mid-cycle case. As we move forward, our view is that the diesel cracks continue to improve as global demand growth causes those balances to tighten. And then, certainly, when you look out further, the IMO bunker spec change, in our mind, has a significant impact on diesel consumption and will cause cracks to be fairly strong as you approach 2020.

Yeah, how do you define mid-cycle then?

So, everyone does that differently. We have a period that is from 2009 through 2015 that we use. That average over that period is what we call our mid-cycle.

Okay, that's understood. And so, I guess you're a bit below. Would you be anticipating, therefore, higher oil prices? I mean, crude prices going forward.

Yes, we think crude prices will go up. I think that the efficiency gains in the upstream kind of caps how high they need to go, but we certainly see where crude prices will go up some from where they are today.

Okay, great. That's helpful. Thanks. And, Joe, if I could – again, speaking of people saying we seem to ask this every quarter, but if I could just roll back, you seem to be talking about cash in and cash out as how you're looking at the company. But you've got this net income target. Could you just square the circle one more time for me on the payout potentially of net income against the company, which seems to be more planned on cash in, cash out? Thanks.

Yeah, Paul, I think we've said, we look at both, right? We use the 75% of net income as the target just because it's such a transparent metric. But when Mike and John are looking at our repurchase strategy, and really the use of cash in general, in setting that target, he looks at multiple metrics, right.

I mean, if you look at it on a cash flow basis, excluding the favorable working capital that we had this quarter, the payout is at 60% of our cash flow. That was for the second quarter.

Yeah, it's been great for you guys. I mean, if you look at the multiple, assuming that you're below mid-cycle it makes sense, but you've nevertheless seen quite a material expansion in your multiple, I think, as a result of your strategies. So, congrats, I guess. Thanks, guys.

Thanks, Paul.

Good morning, guys.

Hi, Neil.

So, you guys have a unique perspective on what's happening from a global oil demand perspective given how far your barrels travel. Obviously, there was concerns about demand earlier this year, with the IEA reporting demand sub 1 million barrels a day in the first quarter. The second quarter looked very, very good. I just wanted to get your perspective, over the last couple months and then also looking forward, where do you see oil demand tracking? And, geographically, where do you see pockets of strength?

Yeah, Neil, this is Gary. We continue to see domestic demand as strong, and then a real pull into the export markets. As the U.S. Gulf Coast basis is stronger during driving season, you don't see that so much on gasoline. Although, we still saw a pretty good pull of gasoline into Mexico and South America. Then, on the diesel side, we saw very high diesel demand into the export markets. We exported 281,000 barrels a day of diesel during the quarter, which was a record for us, and we're really not seeing that fall off much as you move forward. So, this time of year is typically where diesel demand bottoms out seasonally, and so the fact that we've been able to continue to pull diesel inventories down, at a period where demand is at its lowest, kind of sets up what could be a very good heating oil season this year.

That's great, guys. Then, the follow-up question is just on RINs here. I think your guidance is $750 million to $850 million. Given where the D6 RIN has moved, and even frankly, the D4 as well, is it fair to say that you're going to be on the upper end of that range?

Yeah, I think that's fair to say, Neil. Unfortunately.

All right. Yeah. All right, guys, thanks. Thanks again.

You bet.

Thanks, Neil.

Hey, guys, good morning.

Good morning.

I realize we didn't get tax guidance for next quarter, but I was hoping you could maybe just give us an update on the status of this income tax audit. I guess I'm just a little worried if this finally rolls off or comes off, we're going to have like a rapid reversal in the taxable income.

Yeah, the tax rate, we've had some favorable adjustments the last couple of quarters that have lowered that tax rate. But, why don't I try to give you guidance for the year. So, for 2017, we do expect our effective tax rate to be about 28%.

Okay, so, on a full year, 28%.

Yeah, let's try that.

Blake, you were listening, you missed the tax guidance.

We had a bet on that, whether anybody would notice.

I thought maybe John just skipped it, so.

But we've been so accurate.

The second question I had for you is kind of a follow-on to Paul's question on the light sweet. So, it sounds like you're kind of at 88% of your capacity in 2Q, and that's trending up in 3Q. I guess, is the view that that will continue ramping up as lower 48 volumes ramp up? And I presume, once we've exhausted the system, assuming Valero is kind of a proxy for the industry, presumably we'll have more exports. Are you planning to kind of participate in that? Or is that an opportunity for you?

Yeah, Blake. So, I guess the way I would say, certainly in the near future, we expect to be maximizing light sweet, and it's somewhat tied to U.S. production. But, to me, the real change would probably be more tied to when the OPEC barrels come back online. As the OPEC production comes back online, the differentials widen back out, and we start pushing some mediums and heavies back into our system. In terms of your question on the exports, our primary focus is putting the most economic crude dye in front of each of our refineries. So, our exports have really been focused on getting barrels to Pembroke, in Quebec. As exports continue to grow, we could decide if we want to venture into selling to third parties. But right now, our focus has just been getting it into our own system.

Got it. All right, thanks, guys.

Thanks. Morning, Joe. Morning, everybody.

Doug.

Joe, I want to hit on this light crudes question as well, if I may. I hate to beat a dead horse. But I'm just kind of curious, from a macro standpoint, what has triggered this change recently. It might seem pretty obvious. But Saudis and OPEC's comments about cutting exports to the U.S., directionally, is that the thing that has prompted you to do this? I'm just curious what the catalyst was, given the OPEC theoretically cut at the beginning of the year. As a quick follow on to that, hopefully John doesn't count this as my second question, when you're running light sweet crude, what does that do to your operating costs, given you're not running the upgraders? I guess, less than you'd normally be.

All right, I'll answer the first part, and then Lane answers the operating cost portion. Really what we saw is when the OPEC cuts were announced, you really didn't see much of a market response to that announcement. So, the medium sour differentials and the heavy sour differentials remained wide enough that that was the economic barrel to put in front of our system. Had the cuts gone on longer, longer, the medium sour differentials have come in and the heavy sour differentials have come in such that the most economic barrel to put in front of our refineries is the domestic light sweet. And so, that's what we've done. And the change there kind of started occurring in the second quarter. And even in the second quarter, you saw the domestic medium sour still economic. But now, if you look at the MARS versus MEH type spread, or TI in Houston; it strongly favors running domestic light sweet. And so that's where we're headed, and I think we'll be there until the OPEC production comes back.

Well, Doug, this is Lane. In terms of the incremental operating cost or light versus medium or heavy, I think at a reportable level, it's not very measurable. I mean, I don't think you would see a change in our operating costs based on our crude mix. Where it would show up, if we run more or fewer barrels. And so, to the extent that, at some of our refineries when we go light, like at Port Arthur, we actually run more barrels because our coker fills up later. So, on an OpEx basis, you might actually see our OpEx go down. But, it's a little bit by refinery whether it would show up. I sort of believe you wouldn't see it in aggregate. We wouldn't – it wouldn't be a reconciling item for us.

That's helpful. I've actually assumed it would be an incremental positive, given your coker comment. But – so, my follow up and, John might note, sort of for the record, my second question. But my follow-up, I guess with a bigger, a larger light slate, you're going to see a larger gasoline cut coming out of that. And I want to wrap a couple things together here with the dynamics of U.S. demand. Your project queue, as it relates to somewhat limited growth capital with your discipline and so on, I'm just wondering where the whole export strategy fits for products in Valero's strategy going forward. In other words, is that something we could see you swing to a more aggressive investment to basically avoid RINs and maximize your gasoline margin and all the rest of that? I'm just kind of curious how that fits. I'll leave it there. Thank you.

Yeah, so I guess the first question on whether running the lighter diet increases our gasoline make, I would say it's not significantly different as we go lighter. A lot of our gasoline production capacity is maxed out. And so when we go lighter, we end up exporting naphtha. And then, on the export strategy, we want complete flexibility to take our finished product to the highest netback market. And so that's certainly been our strategy, and we'll continue along that path. If that's selling domestically, that's great. But if we can get a higher netback putting the barrels on the water, then we want the flexibility to be able to do that.

And Doug, just on the capital piece of this. So, we are working projects aggressively that facilitate our ability to be very efficient in the export of products. And it's just, unfortunately, a little bit premature for us to give you any insight into that. But I think that you should expect there to be more communications on this over the next several weeks as we firm up some of the things that we're working on.

That's terrific, Joe. Maybe we can do it on beer and a sausage and you can tell me about it over that.

You're on. I would look forward to it.

Thanks a lot. Take care. Bye.

Thank you. Bye.

Great, thank you. I might have missed this, but could you provide the product export volumes by product in 2Q? And related to that, can you talk about the dynamic on the slack capacity on the Colonial Pipeline? And is that related to the exports? And how will that trend going forward in the back half of the year here?

Hey, Chi, this is Gary. So, on gasoline, we did 88,000 barrels a day during the second quarter. Most, all of that went to Mexico and South America. Diesel, we did 281,000 barrels a day. And then, if you combine the kerosene, it was 326,000 barrels a day. That went about 75% to South America, 25% to Europe. And so, then, on your question on Colonial, we've seen the economics of shipping on Colonial have been challenged for quite some time now, and it really is tied to the exports. So, historically, what you saw happen is, as U.S. Gulf Coast started to become long on product, the bases got weak, and you had an arb to ship up to New York Harbor on Colonial. What's happening today is that the length in the Gulf has been pulled to the export market, and it kind of keeps the U.S. Gulf Coast basis a lot stronger such that there isn't an economic incentive to ship on Colonial. The other factor that comes into play here is the Jones Act freight. And so with Jones Act freight coming off, you can put finished product on a Jones Act vessel and bring it around to the harbor, and it's within a penny of what it costs to move it on Colonial. So, that also has been a factor that's come into Colonial coming off allocation.

Gary, I guess what you were saying back to the netback question. You are getting a higher netback on exports then is that what's implied versus shipping on Colonial?

Yes, that's right.

Okay. Okay, thanks. Second question is more a strategic in nature. Yes, Joe, regarding the company's long-term investment strategy, many of your Gulf Coast competitors and I'm pointing to specifically Exxon and Motiva, have announced absolutely huge capital programs, $18 billion to $20 billion predominantly to integrate downstream into petchems. Do these announcements influence your thinking at all, from a competitive standpoint, on the long-term strategy of sticking to refining, primarily in the Gulf Coast?

Well, I mean, Chi, it's a good question. And it doesn't change our strategy. We've talked in the past about a petrochemical strategy, and it's really not as dramatic or significant as you might be thinking. Currently, we produce a number of petrochemical streams, products like propylene and BTX. The strategy that we're talking about here is really to capture more of the margin available from those petrochemical streams where it makes economic sense to do so. The investments associated would be related to any additional processing, and then logistics to store and transport these products. We have no plans to deviate from our capital allocation framework, and decisions to allocate capital to these projects will be based on the expected project returns within our notional capital budget. So, although these guys are investing in these major petchem projects, that's really not our plan or our focus. And we do continue to have a focus on improving our refinery operations. We have a focus on integrating from the wellhead into the refineries, and from the refineries out, so that the margin that's captured in the movement of products and crude is something that we capture rather than paying to somebody else. And so, I don't think that you should worry that you're going to wake up one day and we're going to be announcing that we're investing in a mega billion dollar petchem complex. It's just not on the radar screen for us.

Okay. Are any of these incremental petchem projects in the CapEx budget at this point?

They're still in development, and we've got placeholders for them.

Okay.

So, again, I don't think you should expect that we're going to deviate materially from this $2.5 to $2.7 billion number going forward.

Okay. Got it. Thanks, Joe. Appreciate it.

Great. Thanks. Good morning, guys. I guess maybe a couple on midstream from me. So, obviously, there's a lot of competition there and some pretty high asset valuations. And, Joe, I know you've said in the past that recent transactions have looked a bit aggressive, and really I appreciate the answer to Blake's question on light sweet. But really would the interlink with the refining footprint in VLP and maybe the synergies there be enough to justify a higher multiple for building or buying assets?

Yeah, I think if you're going to buy assets, you're going to have to be prepared to pay a higher multiple. I mean, that's just where the market seems to be today. And, so, building them has really been where we've had a great deal of focus. I mean, we're looking at assets that are in the market for sale today, but we always compare it to the alternative uses for cash. Relative to exports, Rich, you want to give any update?

Yeah, relative to the exports on the crude side, we're looking at a couple of projects at Corpus and at Port Arthur to increase the ability to export crude. We've got, as Joe mentioned earlier, we've got some projects that are in development that we'll be able to share more in the coming weeks, but that will significantly increase the ability to increase product exports. So, we're focused on getting that flexibility for Valero.

Yeah, but, Justin, we really like the idea of the organic growth projects, where we have a great deal of control over the investment profile and the project execution.

Yeah, great. I appreciate that response, guys. And maybe – not sure how far I'm going to get with this one, but with the contested terminal acquisition in California, anything you can share there, in terms of what you expect, and in terms of how that plays out, and what it would mean to have in Valero's hands going forward?

Yeah. This is Rich again. So, we really can't provide anymore additional details than what's kind of been in the press release, other than the FTC allowed the transaction to go through, and the Cal AG has intervened. And that's kind of where it's at right now.

Figured that was the case, but had to try. Thanks, guys.

You bet.

Good morning, guys.

Good morning, Faisel.

Just a couple questions. First of all, just on the working capital, the $700 million benefit. What caused that? Because I guess some of the companies that are reporting are seeing working capital draws.

Yeah, in our instance, a little over $400 million of that was due to reduction in inventories. And then we had about a $250 million increase in the crude expenses. So, some of that's going to be timing, obviously, where we will be paying off those expenses.

Okay, got you. And then just on the projects that you guys have in development, but not in execution. I guess this potential, I guess, $1 billion in EBITDA, when do you have to start to go to FID on these projects? Because, you've already got some projects in execution that are in 2019, and you're talking about a potentially large number as you go into 2021. So, at what point do you have to start making decisions on some of these projects, whether it's octane enhancement or the supply chain into Mexico?

Faisel, the way, and Lane can talk in more detail about this, but the way that we work our projects, we look at the target for the year. And we've got a fairly dynamic approach to doing this, where Lane's engineering staff will work the projects, and then we review them periodically to see which ones we want to continue to proceed forward and to invest capital in. And so, it's not like we look at everything in the first quarter, second quarter, third quarter. We're looking at them throughout the year. Any color you want to add to that?

The only thing I would add is, we do have a strategic view. We invest in projects that we think increase our ability to meet what we consider to be higher octane requirements in the future. We like the idea of small, sort of quick-hitting projects that give us more feedstock flexibility because we think we're particularly good at that. And, obviously, we have a strategic view to capture more of or pay ourselves for our own secondary costs, and there's a lot of projects in this. We just have made the decision to be careful about communicating more around the timeframe of where we do have an FID decision versus just sort of – we're trying to say, conceptually, this is how we view the world. Trust us that we have plenty of projects that fit into that space and we're going to execute them rateably, and on a predictable basis.

And so then, when I think about the $1 billion annually through 2021, and then the illustrative number of 1.2 to 1.4, so is it right to say that that gets you to your 25% IRR? Is that the way to think about it?

Yeah, so the way that we've talked about this is we wanted to illustrate the fact that we did have attractive growth projects in place. And so, half of that capital is deemed to be refining projects, which have the higher 25% return threshold. It could be 24%, could be 28%. But they're typically in that range or better. And, on the logistics side, we know that those tend to be lower-risk projects, so they tend to have lower return thresholds. And so that's where we use kind of a 12% to 15% threshold for. And that capital is split 50/50 between those two categories. And if you just extrapolate out where that would take you, you get to your $1 billion to $1.2 billion of incremental EBITDA resulting from a capital program that would be executed every year for the next five years.

Okay, got you. And this is the last question. The open season on Keystone XL, are you guys still committed to take capacity to that line? And I guess especially given some of the issues going on in Venezuela, does that make it more important?

Yeah, I think we remain committed to the line, and we think that the U.S. Gulf Coast with the high complexity refining assets is the best home for the growing production of Canadian crude. So, we're working a number of commercial options to continue to support that Pipeline.

Okay. Great. Thanks, guys.

Thanks, Faisel.

Yeah, good morning.

Morning, Roger.

Well, most of this has been hit, but I guess maybe following up on the recent comments. One of the questions here on the export terminals in Port Arthur and Corpus. Recent headlines, the LOOP would be considering the possibility of exports, and I believe you've got an interest there. So, how does that fit into the overall process? Does it change anything you would do? Or is it just a longer term enhancement?

Roger, this is Gary. I think what we understand is being contemplated at LOOP, at least in the short term, is a fairly small capital investment that will allow limited exports out of LOOP. We think around the neighborhood of 50,000 barrels a day, which in our mind is not really significant in terms of impacting the overall capability. But that's exactly what we're doing, is we're evaluating the existing logistics and the volume leaving, and when those logistics start to become taxed, then we can look at adding to those, either through what Rich talked about at Corpus or Port Arthur, as those opportunities become available to us.

Take a little while to fill up a VLCC at 50,000 barrels a day?

Yeah, it's exactly right.

All right, and then kind of getting back to some of the macro questions here. We've seen the northern or let's call it the Atlantic market, product market, tighten up quite a bit. Nice inventory draws here, and in Europe. Given that we've had really high throughputs here, what do you kind of identify as what's helped us see the market change from kind of Memorial Day to the 4th of July period? It didn't appear to be lower run rates here or in Europe. So I was just curious, did we see bigger product draws into markets that are harder for us to identify? I'm thinking Africa or anywhere else. Or was it just demand picked up?

Yeah, I think it was a combination. So, we certainly saw an increase in demand from the first quarter to second quarter domestically. And then we've seen a big pull into Mexico and South America that's really helped us create the inventory draws.

All right. I appreciate the help. Thanks.

Thanks, Roger.

Okay, thanks, Vanessa. We appreciate everybody joining us today. Please contact our IR team if you have any additional questions. Thank you.