Welcome to the Valero Energy Corporation 2016 Second Quarter Earnings Results Conference Call. My name is Vanessa and I'll be your operator for today's call. At this time, all participants are in a listen-only mode. Later, we will conduct a question and answer session. Please note that this conference is being recorded. I will now turn the call over to Mr. John Locke, Vice President of Investor Relations. You may begin.
Good morning, welcome to Valero Energy Corporation Second Quarter 2016 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 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 now 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, good morning, everyone. In the second quarter, we continued to face a challenging margin environment, which was further complicated by high compliance cost headwinds. Our team performed well, running safely and reliably while maintaining our cost-efficient operations. Turning to the markets, sweet crude discounts in the second quarter remained narrow as shale crude production continued to slow. Unplanned crude production outages caused by wildfires in Canada led to the tightening of medium and heavy sour crude discounts relative to Brent. More recently, with the resumption of crude production in Canada and the continued flow of foreign medium sour crudes to the U.S. Gulf Coast, we've seen discounts widening versus Brent. We expect medium, heavy and sour crude oils to remain attractive. On the product side, margins improved compared to the first quarter, product demand in domestic and export markets remained robust.
In fact, we exported record volumes of distillate and gasoline combined for a second quarter. Turning to our refining growth strategy, we successfully commissioned the new Houston crude unit in June. In addition, the Corpus Christi crude unit, which was completed late last year, ran well in above-plan rates. We continued engineering and procurement work on the $300 million Houston alkylation unit, which we expect to complete in the first half of 2019. We also continued to develop other strategic projects that will provide octane enhancement, feedstock flexibility, and cogeneration to create higher-value products and reduce cost. In June, we acquired the remaining 50% interest in the Parkway Pipeline, which connects our St. Charles refinery to the Plantation Pipeline. With 100% ownership interest in this pipeline and the planned connection to the Colonial Pipeline, we've enhanced our product supply options to the U.S. East Coast.
This transaction fits our strategy to optimize through investments in logistics assets, which we expect to be eligible for future drop to Valero Energy Partners LP, our sponsored MLP. With respect to VLP, last week we announced a distribution increase of 7.4% for the second quarter, which keeps us on pace for an annual distribution growth rate of 25%. Finally, despite the lower margin environment, we generated solid cash flow from operations and stepped up our return of cash to stockholders through our buyback program. With that, John, I'll hand it back over to you.
Thank you, Joe. For the quarter, net income attributable to Valero stockholders was $814 million, or $1.73 per share, which compares to $1.4 billion, or $2.66 per share in the second quarter of 2015. Excluding an after-tax lower cost or market inventory valuation benefit of $367 million, or $0.78 per share, and an asset impairment loss of $56 million, or $0.12 per share, second quarter 2016 adjusted net income was $503 million, or $1.07 per share. Please refer to the reconciliations of actual to adjusted amounts that begin on page three of the financial tables that accompany our release. Operating income for the refining segment in the second quarter of 2016 was $1.3 billion, and adjusted operating income was $954 million, which was $1.2 billion lower than the second quarter of 2015.
Primary drivers of the decline were weaker gasoline and distillate margins due to lingering high product inventories and lower discounts for sweet crude oils relative to Brent crude oil. Higher RIN prices also created additional earnings headwinds in the second quarter of 2016. Refining throughput volumes averaged 2.8 million barrels per day in the second quarter of 2016, which was in line with the second quarter of 2015. Our refineries operated at 94% throughput capacity utilization, which was impacted by a turnaround at our Texas City refinery. Refining cash operating expenses of $3.51 per barrel in the second quarter of 2016 were $0.15 per barrel lower compared to the second quarter of 2015, largely driven by lower energy costs.
The ethanol segment generated $69 million of operating income in the second quarter of 2016, and adjusted operating income of $49 million, which was $59 million lower than in the second quarter of 2015, due primarily to lower gross margin per gallon, driven by higher corn prices in the second quarter of 2016. Additionally, for the second quarter of 2016, general and administrative expenses, excluding corporate depreciation, were $159 million, and net interest expense was $111 million. Depreciation and amortization expense was $471 million, and the effective tax rate was 26% in the second quarter of 2016.
The effective tax rate was lower than expected and lower than in the second quarter of 2015, primarily due to the positive change in the company's lower of cost or market inventory valuation reserve in the second quarter of 2016, which contributed to a stronger relative earnings contribution from international operations with lower statutory tax rates. With respect to our balance sheet at quarter end, total debt was $7.5 billion, and cash and temporary cash investments were $4.9 billion, of which $67 million was held by VLP. Valero's debt to capitalization ratio, net of $2 billion in cash, was 21%. We had $5.3 billion of available liquidity excluding cash, of which $436 million was only available to VLP.
We generated $2.3 billion of cash from operating activities in the second quarter, of which $1.3 billion was due to favorable working capital changes, primarily increases in accounts and taxes payable, and a reduction in inventories. With regard to investing activities, we made $461 million of capital investments, of which $164 million was for turnarounds and catalysts. This amount excludes our purchase of the remaining 50% interest in the Parkway Pipeline from Kinder Morgan. Moving to financing activities, we returned $683 million in cash to stockholders in the second quarter, which included $282 million in dividend payments and $401 million for the purchase of over 7.5 million shares of Valero common stock. As of June 30, we had approximately $700 million of share repurchase authorization remaining.
For 2016, we expect to invest $1.6 billion to maintain the business and another $1 billion for refining asset optimization and logistics projects, which are expected to drive long-term earnings growth. For modeling our third quarter operations, we expect throughput volumes to fall within the following ranges: U.S. Gulf Coast at 1.6 million to 1.65 million barrels per day, U.S. Midcontinent at 415,000 to 435,000 barrels per day, U.S. West Coast at 260,000 to 280,000 barrels per day, and the North Atlantic at 460,000 to 480,000 barrels per day. The guidance range for the U.S. Gulf Coast reflects the previously announced major turnaround at the Port Arthur refinery, which occurs once every five years. Refining cash operating expenses are estimated at approximately $3.70 per barrel in the third quarter.
We continue to expect costs related to meeting our biofuel blending obligations, primarily related to RINs in the U.S., to be between $750 million and $850 million for 2016. Costs will likely end up in the upper end of that range based on recent RIN prices. The ethanol segment is expected to produce a total of 3.9 million gallons per day. Operating expenses should average $0.37 per gallon, which includes $0.05 per gallon for non-cash costs such as depreciation and amortization. G&A expenses for the third quarter, excluding corporate depreciation, are expected to be around $180 million, and net interest expense should be about $110 million. Total depreciation and amortization expense should be approximately $465 million, and our effective tax rate should be around 30%. That concludes our opening remarks.
Before we open the call to questions, we ask that callers adhere to our protocol in the Q&A to two questions. This will help us ensure that other callers have time to ask their questions. If you have more than two questions, please rejoin the queue as time permits.
Thank you. We will now begin the question and answer session. If you have a question, please press star then one on your touch tone phone. If you wish to be removed from the queue, please press the pound sign or the hash key. If you're using a speakerphone, you may need to pick up the handset first before pressing the numbers. Once again, if you have a question, please press star then one on your touch tone phone. We have our first question from Neil Mehta with Goldman Sachs.
Good morning, guys. Congrats on the strong cash flow quarter here. Want to kick it off on the product side. Clearly, product margins are a concern for investors as we think about both the refining stocks and then also as we think about the flat price for crude. So two questions on that basis. One, Joe, do you think there's just too much refining capacity in the world here? Is there a structural oversupply in the amount of capacity? Do you expect that we're going to see run cuts this fall here in the U.S. or elsewhere in the world?
Morning, Neil, thanks for your comments. Why don't I let Gary take a crack at this?
Yeah, Neil, I think, despite the fact that we've seen very strong product demand, obviously the refinery utilization has been such that supply has been able to keep up and even outpace demand. Ultimately, we're going to need a rebalancing and see lower refinery utilization moving forward. I do believe that you'll see some refinery run cuts as we head into the third and fourth quarter. I think that some of what happened this year is that with the steep contango in the market, especially early in the year, some marginal refining capacity that typically you would see cut in the winter had incentive to go ahead and run and produce a summer grade of gasoline. It caused utilization to be very high, especially in the January, February timeframe.
That's where we built the large overhang of products that we've really had to manage the rest of this year.
No, I appreciate those comments. Secondly, on RINs here, you maintained the guidance of 750-850, but it's fair to say there's some upward bias to the midpoint of the range. Joe, can you just talk about what you ultimately see as the resolution to this RINs issue? I know it's something that you've been talking to the EPA about quite a lot. Just how you see the RINs issue evolving from here.
Okay, Neil, that's a good question. I'll speak just briefly about the lawsuit, really, and then if we have procedural questions, Jay can help me with that. Our action with the EPA is really focused on dealing with the current structure of the system. The current system, as you know, misaligns the RIN obligation with the ability to comply by blending. What's happened is it's enabled speculators to drive up RIN prices, which really distorts the markets, and it facilitates opportunities for RIN fraud, which we've seen a fair amount of. Moving the point of obligation really would address these issues, it would enable the penetration of biofuel products into the marketplace to increase their blending. That's really the emphasis for us on trying to push this, just to try to fix a structure that we think really is misaligned and infeasible today.
Jay, on process, any comments?
Yeah. As everyone knows, if you're engaged in litigation, we're only in a position to control our own efforts and timing, we are doing everything possible that we can to bring attention to the issue. We have filed the lawsuits, we've filed the petition for reconsideration, we've engaged in a lot of effort to educate other affected parties as well as EPA officials. Ideally, we would like to see EPA, of its own accord, engage in a rulemaking process. If they were to do so, you can go to the EPA website and see basically how long it takes for them to put out a proposed rule, gather comments, and finalize a rule. Short of that, we're having to fall back on the timing of the process of litigation, which is very difficult to speculate.
All right, guys. Thanks for the comments.
Thanks, Neil.
Thank you. Our next question comes from Evan Calio with Morgan Stanley.
Hey, good morning, guys.
Morning, Evan.
Hey, I know you guys raised your dividend early in the first quarter, and your indicative yield today is higher than it was in 2008 and 2009. Can you discuss how you stressed the dividend when you established or decided to raise that earlier this year, and how you view the sustainability of your yield?
Okay, Evan. Our dividend is a commitment to our shareholders, we do consider it non-discretionary. With our cash position and nearly $5 billion of liquidity we have available to us, we're quite comfortable with the sustainability of our current dividend and also the payout target of at least 75% of net income. In addition, we're not concerned with the funding of our capital program.
Evan, we did take a good hard look at this. Obviously margins can be volatile, right? That's an understatement of the year. Last year they were strong. This year they're weaker. We ran cases before we presented to the board the dividend increase, which really looked at different margin scenarios, that's how we got our comfort level with it. We stressed it pretty hard, obviously in this low margin environment, with earnings where they are, we're still in a good position on the dividend. Obviously we did a thorough job on that.
Yeah. No, that makes sense, that should help support it in this environment, your stock. Maybe a follow-up on the distribution comment. You're running above the 75% payout target year to date and in 2Q. How should we think about that target going forward? Does the higher distribution reflect
Your view on an improving outlook or the cash-generating abilities of your assets?
Our target is based on net income, but we do understand in this lower earnings environment that we have to consider our cash flow generating capabilities and then also the drops to the VLP.
Through June, we have paid out 156% of adjusted net income, and that's about 42% of our cash flow.
Got it. Appreciate it, guys.
Thanks, Evan.
Thank you. Our next question comes from Paul Cheng with Barclays.
Hey, guys. Good morning.
Good morning.
A couple questions. Mike, do you have any preliminary 2017, 2018 CapEx that you can share? If the margins stay close to where we are over the next one or two years, then how quickly in advance that you can adjust those numbers?
Okay. Paul, we haven't disclosed our 2017 capital budget yet, notionally, we're going to be spending $1.4 billion-$1.6 billion on maintenance capital and roughly $1 billion on growth. Obviously, there's more flexibility in the growth category, the projects that we're identifying are attractive, and you'd want us to complete these at those hurdle rates. Today, we have lots of cash, like I just mentioned, and a lot of liquidity, and we're quite comfortable in funding our capital expenditures at those levels.
Joe, just curious then, with the refining market, I think weaker than people expected. When you're looking at the M&A market, have you seen any change in the bid-ask gap in the last several months?
Paul, I would tell you, I don't think we've seen any major change. Obviously, in a down market, a seller doesn't want to sell for what the valuations might be, and a buyer doesn't want to pay for assets based on what we've experienced in the past. It's always a negotiation when you're looking at it. You raised the question on M&A, and if I could, I just want to stress the fact that M&A is a component of our capital allocation framework. It is not the component of our capital allocation framework. Unfortunately, in our last call, we gave the impression that there was a greater emphasis on M&A than there had been in the past, which we really never intended to do. We've consistently shared that we look at opportunities all the time.
A transaction like the Parkway Pipeline acquisition wouldn't come as a surprise. Any M&A transactions will need to compete for cash with our growth capital projects and our buybacks. Just to be clear, there's no greater emphasis on M&A today than there was two years ago, and our commitment to the other components of our capital allocation framework is really unchanged.
Thank you.
You bet.
Thank you. Our next question comes from Phil Gresh with JPMorgan.
Hey, good morning.
Good morning.
Just following up on the CapEx side of things. You're tracking well below for the full year. Were you always expecting it to be a little bit more back-half loaded because of the turnarounds? Or would you say maybe there's some degree of conservatism in the capital budget outlook being maintained at $2.6 for the year?
Well, we are tracking a little bit below the $2.6. Lane, do you have any idea on the timing of some of these projects?
Yeah. I thought what all I would say, we've disclosed, since we have a large turnaround in Port Arthur in the third and fourth quarter, that's a big turnaround, and that is a known quantity. In terms of our ratable spend, I would say, we're still holding sort of this 2.6, but we'll see because it is, in terms of capital projects, the ratability is such that November, December, it's difficult to spend a lot of money during that time of year. I'll just leave it at that.
Okay. The second question, the return of capital discussion, you mentioned cash available via drops. Some of your peers have been pretty active with capital raises and drops so far this year. It feels like the market is opening up for quality MLPs, maybe with the pullback in oil now, maybe a little less. We'll see. How are you thinking about the back half of the year on this front?
As far as the drop?
Yeah, in terms of
The equity drops
desire to raise capital and do drops.
Okay. Right now, we have no change to the strategy to grow our LP primarily through the drop-down. We do believe a measured pace is prudent, and our guidance is still 500 to 750 that we gave in the first quarter call. We will continue to look at third-party logistics deals that support Valero's core business. In regard to the capital markets, on the equity side, obviously they've been improving, and they have improved throughout the quarter. Debt markets look very good.
I guess we'll continue to keep an eye on it. We're not prepared right now to change what we've shared that we're planning to do. Phil, you
We're all watching this to see, are we dealing with a new normal or are we dealing with just a spike in the market that was driven by the financial situation we had last year? We'll continue to eyeball it. We've got, again, plenty of assets that we could drop. We've got significant EBITDA there, and we continue to look for opportunities to grow the LP with potential joint ventures and some smaller acquisitions. We're very attentive to it.
Okay, thanks.
Thank you. Our next question comes from Roger Read with Wells Fargo.
Hey, good morning.
Morning.
I guess some of the main topics have been hit. If maybe we could dive just a little bit deeper into the concern about run cuts and then maybe the outlook for turnarounds beyond just Port Arthur for you as we're looking into the fall.
Run cuts.
Yeah. I guess on run cuts, we continue to have margin to run in our system. We feel good about the fact that we have this natural gas advantage and feedstock cost advantage in the Gulf that puts us in a very good position globally in the refining industry. We're not feeling any pressure for run cuts, but I do agree that we're going to need some rebalancing in the market. Going forward, I think you'll see some run cuts in the third and fourth quarter. I'm not sure where those will occur, probably Northwest Europe and some of them in the Northeastern U.S., where you're already starting to hear some in the press of run cuts in today's market. I'll let Lane comment on the future turnarounds.
Yeah. Roger, we disclosed the Port Arthur turnaround just because it was so material, and we wanted to make sure it was out there. It's not our normal way we communicate in terms of providing any additional information on our forward-looking statements with respect to our turnarounds.
Okay, maybe a broader question about turnarounds and experience where we've had these oversupply situations. Is it Valero's experience or would you say it's maybe the industry broadly, that when you have a weak margin environment, you'll take advantage of opportunities given that economic costs are much lower of doing a turnaround? Or that maybe you don't try to force product through the non-crude unit if you have a big crude unit turnaround? Just curious if, do you take advantage in a situation where we've come off several years of high margins and a big economic cost to turn around? Do you see that is that one of the ways the industry corrects the imbalance here?
First, I'll comment on Valero. We have a strategy of planning our turnarounds a couple of years in advance and executing our turnarounds as they come up. We have a big system, and we feel like we, by virtue of being disciplined and doing that, we don't try to move our turnarounds based on what prompt economics are. Now, as the rest of the industry, there may be some of that. I can't say that there's not. I'm sure that people are looking at whether if the refineries are struggling from a maintenance perspective, they may bring the maintenance forward and just fix whatever it is. If you want to call that a turnaround, you might say that. I would say that's essentially about all that there is.
Okay. Thank you.
Thank you. Our next question comes from Doug Leggate with Bank of America.
Thank you. Good morning, everybody.
Morning, Doug.
Joe, I guess my first one might be for Mike. Mike, I just wonder if you could help us understand the strength of the cash flow in the quarter, just as it relates to reported income and DD&A. It looks like there's some other moving parts in there. My follow-up is on the industry, please.
Okay. On the cash flow, we had a change in cash, a build in cash for the quarter of $1.1 billion. Of that amount, $1.3 was due to favorable working capital changes. We had an increase in our payables and receivables, and you net those together, it's about $600 million benefit. We had an increase in our taxes payable of roughly $300 million, and then we decreased our inventories in the quarter by about $300 million. That nets to the $1.2 billion working capital benefit.
Great. That helps me close the gap. Thanks. Joe, my follow-up is on, I guess it's more of a margin question in terms of the octane premium that hasn't appeared to materialize this summer. You mentioned in your prepared remarks that octane enhancement or projects might be something that Valero continues to look at. Is 2016 just a one-off, or do you still think that there is going to be a call for increased alkylate production or whatever it happens to be in the future? I'll leave it there. Thanks.
Thank you, Doug. Okay, Gary or Lane, you guys want to tag team it?
I'll start, Doug, and then let Lane talk about the projects a little bit. What we've seen in the market is actually the octane premiums on the West Coast and the Mid-Continent and the Group 3 market have been stronger this year than what they were last year. However, in the U.S. Gulf Coast and the New York Harbor, we've seen weaker octane premiums. If you try to get your mind around what's going on, I think a lot of that is the fact that where you really can store gasoline is in the U.S. Gulf Coast and the New York Harbor. When we had that steep contango early in the year, people were storing gasoline. They were largely storing premium grade summer gasoline and high octane blend components.
In those markets, in the harbor and the Gulf Coast, as that inventory has come out It's kind of caused the premiums to be a little weaker this year than what we saw in the past. However, in the Group 3 market, in the West Coast market, where you don't have a lot of capability to store gasoline, the octane values have actually been stronger than what we saw last year.
Doug, this is Lane. We still have a strategic view that octane has value, and it's really in the context of Tier 3 is going to destroy a lot of octane. Of course, the autos on a go-forward basis are looking at higher compression engines. They may in fact want higher octane fuel. The best way to make that, we believe, is trying to find a way to get NGL into the transportation fuel and then convert that to octane. That's why we like our Houston alkylation project. With that strategic view, we look at other projects to, if it meets our hurdle rates, to produce additional octane in our system.
I appreciate it. Good full answer, guys. That's really helpful. Thank you.
Thank you. Our next question comes from Blake Fernandez with Howard Weil.
Hey, guys. Good morning.
Blake.
Question for you, I guess it's kind of macro and also company specific, but you obviously hit record levels on the export side. At the same time, we're seeing increased gasoline imports into the U.S., and so I'm just trying to get a sense of exactly what's going on. Is this more of a regional dynamic where Gulf Coast is really sending product to other parts of the world, and Europe is basically penetrating the East Coast? Just basically any color you can give us on that framework.
Yeah, Blake, this is Gary. I think it's exactly what you said. We see, especially on gasoline exports, that we have a competitive advantage going to Mexico and South America. Largely due to Jones Act shipping, we're not as competitive going to the New York Harbor as maybe Northwest Europe are. The natural flow of our barrels is to go south into South America, and there's been an incentive to send barrels from Northwest Europe into the harbor.
Okay. Just to clarify, the startup of Houston, is that contributing to those exports, or is that not really that material in the quarter?
No, it really didn't have any material impact at all in the quarter.
Okay. If you don't mind, just a final point of clarity. I know you said on the economic run cuts, you're not necessarily providing, I guess, an outlook on exactly where it would occur. But if I heard the guidance correctly on MidCon, it looks like a pretty decent rollover quarter-to-quarter. Would that guidance contemplate any economic run cuts that you're planning to do inland?
Hey, Blake, this is Lane. The way I'll answer that is, today we have positive economics in the MidCon. Obviously, the region's landlocked, so we get into seasonal product containments potentially in the fourth and first quarter. That happens about every year.
Okay. Fair enough. Thank you.
Thank you. Our next question comes from Jeff Dietert with Simmons & Company.
Good morning.
Morning, Jeff.
My question's on summer grade gasoline. With the gasoline inventory overhang that we've got, are you worried about moving your summer grade gasoline at a premium? Are you concerned that that might compress as we get closer to the end of the summer driving season? We've heard some discussion about already shifting to winter-grade gasoline production. Does that make any sense?
Hey, Jeff, this is Gary. I don't think there's really a concern on being able to clear out the overhang of the summer grade spec gasoline and moving it out to the market. I guess to your second comment, yes, we are hearing that there are people starting to put some winter-grade gasoline into some of the markets, especially into the harbor.
Secondly, you reported, I think, record light product yield, gasoline yield. We saw 49.3%, up 1.3% year-on-year. Industry, the DOE stats show it up maybe slightly more than that. What would you attribute the increase in gasoline yield to in the second quarter? What were the primary factors?
Hey. Jeff, this is Lane. I would say we've been in a strong maximum gasoline signal for the most part up until about a month ago. Our assets, we just had them pointed to try to make as much gasoline as possible. When you compare it year-over-year, there were times last year we maybe didn't have as strong a signal to maximize our reformers as much as we have this year, and it's really the naphtha discount. That, I would just say that's sort of the year-over-year difference.
Great. Thanks for your comments.
You bet.
Thank you. Our next question comes from Edward Westlake with Credit Suisse.
Yeah, good morning. You shouted out on the front page ample supplies of medium and heavy sour crude, obviously, which your system can process better than others. Is that a comment about the sort of OPEC barrels, or are you seeing things like in Venezuela? As they run out of power, are they having to puke out some sort of real heavy rubbish at cheap discounts that you can run and others can't?
I think we see good supplies from the Middle East, South America, and Canada as well. I don't know that we've seen a lot in terms of change in behavior from Venezuela. We continue to see good supply of oil from Venezuela. The grades are a little bit different, so we see a lot more what we call diluted crude oil, or DCO, and less of some of the synthetic barrels, Petrozuata heavy, some of that type of thing. It's kind of really the only change that we've seen.
Right. Presumably, those DCOs you can run through your system at a better economics than the synthetic barrels?
Yes, typically. They have more difficulty placing the DCO than they would a synthetic barrel.
Yeah, makes sense. Okay, a separate question. With the cash pile plus organic free cash flow, we'll obviously see how refining works out in the second half, and your inventory in VLP. A question about how you plan to grow the EBITDA inventory that you could then subsequently drop down into VLP. Obviously, you're doing $500-$750 of drop-downs, should we think of that number being the same number as how you want to grow the top of the funnel of logistics inventory at the parent? I'm trying to think about medium-term CapEx allocation to logistics.
Yeah. No, that's a good question. We have a lot of activity underway right now, both for organic projects, which tend to be smaller in their nature, but also some opportunity to acquire assets, really to extend the supply chain into and out of our refineries. We've made it a point really not to get out over our skis and talk about the specific opportunities until we were comfortable how the business case looked, and really to firm up the opportunity. We do have a lot going on. We are focused on continuing to expand the logistics side of the business, obviously those assets would be those that support the system, would bring to VLP some third-party volumes, continue to expand the drop-down inventory.
Okay. Thanks so much.
Thank you. Our next question is from Paul Sankey with Wolfe Research.
Hi, good morning, everyone.
Hey, Paul.
I had a couple of questions, which actually were the first questions asked about half an hour ago, so I appreciate the details. I was going to ask about RINs. I just wanted, as a follow-up, is there an alternate strategy if the lawsuit fails? What really is the next recourse after that?
Paul, the obvious operating strategy is to try to go ahead and continue to find ways to blend more, right?
Expansion of our wholesale marketing business is something that we've got a key eye on. Obviously, acquiring terminaling assets would provide that opportunity, then continuing to try to build the export markets to try to alleviate some of the burden of the RIN. Those are all things that we look at regularly and really ongoing. Other than that, you just continue to bang away on the rock, and you try to get people to recognize the fact that the system that we have today is broken, that it is creating windfalls for some, and it's creating disadvantages for others, and the playing field isn't level. I can tell you that based on the conversations that we've had, there's an understanding of this issue, and there's an understanding that the RFS isn't intending what it was intended to do, which was increase the amount of biofuels blended.
We believe that that's caused by the structural problem that we talked about earlier. We're not going to give up the fight. We'll continue to push it, both from a regulatory and a legislative perspective, then from an operating perspective.
Yep. Understood. Good luck with that. Then the other one was, again, pretty much the first question you answered, which is regarding the market environment. If the demand is higher this year than last year in the U.S., is it a function of extra refineries being added, do you think, globally, new capacity? Is it more that the competitive advantage of the Atlantic Basin non-U.S. refiners has improved and therefore they're running stronger? I would imagine it's the combination of both, but any sort of market commentary you have on that would be great. Thanks.
I would say that a lot of it is really more a result of utilization, especially utilization in periods where typically we see refineries cut. As I talked about, typically you get refineries cutting in the fourth quarter and the first quarter, this year we saw refineries run at very high utilization rates. A lot of that was just due to the steep contango that was in the market.
Yeah, understood. Then finally from me, the demand side. It seems to be sort of being revised lower in the U.S. Is that a concern for you guys? Do you think the demand has been overstated, or do you really think that this is a supply problem? Thank you.
I can just comment on what we're seeing through our wholesale demand domestically, we're seeing good demand through that wholesale channel. Year-over-year, our gasoline volumes through wholesale are up 3%, even on the distillate side, we're moving about 1% more through the wholesale channel of diesel than what we did last year.
Great. That's helpful. Thank you.
Thank you. Our next question is from Faisel Khan with Citigroup.
Thanks. Good morning.
Hi, Faisel.
Hi, Joe. Just going back to, I think, a question that Jeff Dietert asked on the sort of switching from summer grade to winter grade and people already putting gasoline in inventory for the winter. Do you think that's a risk, or do you think this is a one-off that hopefully we don't carry this excess inventory from the summer into the winter?
It certainly is a risk. It's always a risk that's out there and will depend on what the market structure is. I think after we've gone through this period where the market's been weaker this year, I don't think it's as great a risk as what we saw in the winter where people were storing the summer grade.
Okay, got you. Just with the outages in Canada that we saw earlier in the summer, have you seen those volumes completely recover? How are you dealing with that disruption? How is that evolving as production ramps back up for you guys?
Yeah. I think for us, on the Canadian heavy side, we pretty much are seeing all the volume back available to us, the Canadian heavy barrels are being priced very competitively versus either another heavy sour alternative or a medium sour alternative. I would say that we've fully recovered from the fire so far.
Okay, great. Thanks for the time, guys.
Thank you. Our next question comes from Chi Chow with Tudor, Pickering Holt.
Great. Thanks. Good morning.
Hi, Chi.
Hi, Joe. This question may be the same as Paul's a couple of questions ago, but just this RIN issue kind of cropping back up this year. Do you think there's any vulnerability to the merchant refining model that you have longer term, given the RIN issue or anything else that may be out there?
It would probably be hard to say that the RIN was helpful to the merchant refining model. Okay. Obviously, it's not. You get into what are the options for dealing with it. I think I mentioned those earlier, Chi. Specifically from Valero's perspective, the retail marketing business isn't something that's currently on our radar screen. We believe there's better ways to deal with the issue. I really don't have anything to add to that. I think, certainly, it's an issue that we're working very hard to deal with because it does. It puts an expense on the merchant refiner that he shouldn't be bearing today. That creates a real problem. It creates an unlevel playing field in the marketplace, and that's never good. Anyway, we'll continue to address it the way we are.
Yeah. Thanks, Joe, for those thoughts. Maybe a question on Aruba. There's been a lot of industry chatter about Venezuela's interest in Aruba lately, you've written the whole asset off at this point. Are you suggesting that there's no option going forward to sell or transfer the plant to another operator?
I'm looking at Jay to see what we say about this.
No. The option to transfer is still there. It's just a function of the financial requirements. We've chosen to write it off.
Okay. You can still transfer, but for free, basically. Is that what you're signaling?
Well, yeah, I guess so.
Maybe.
Okay, great. Thanks for that.
Okay, Chi.
Thank you. Our next question comes from Brad Heffern with RBC Capital Markets.
Good morning, everyone.
Morning, Brad.
Just a follow-up to Jeff's question a little while ago on yield. Lane, you mentioned the systems have been running at maximum gasoline yield for quite a while now, I think there was maybe an implication in what you said that you're not running quite at maximum gasoline anymore. I'm curious just how you're thinking about your yield decisions these days. I would assume that given the incentives in the market at the moment, you're probably running a little more distillate with more of a distillate focus than you had been. How are you thinking about making catalyst decisions and so on that affect the next 18, 24 months?
We are currently in, I would say, max jet mode. The decision you make there is between our cut point between jet and naphtha. Naphtha shows up in our overall results as a gasoline, although it's not really. We export it. If we're maximizing jet, we're still actually maximizing gasoline is the next step, and that's largely due to butane blending economics. It has to do with what we would call the swing cut between the heavy part of cat gasoline and LCO, and there's compelling economics to swell to bring butane into the pool. That's how we're postured today. We're very close on all these things just because of where the relative cracks are. In terms of catalyst choices, FCCs we can change relatively quickly.
I would say most of the time there, we make a decision on whether we want to try to fill our alkylation capacity catalytically with ZSM-5 and not run as much rate. That's normally what we do in the winter, and we're certainly looking at that, and I wouldn't be surprised if we didn't end up there. On hydrocrackers, every three years we make that decision, and that really is a choice between it's not really gasoline and diesel in our hydrocrackers. It's really naphtha and diesel. We're still biased on the side of making distillate out of our big hydrocrackers.
Okay, got it. Thanks for that color. I was curious if you could talk a little bit about the results in the North Atlantic this quarter. The indicator was up $3 sequentially, but the margin was down. What were the contributing factors to the performance?
Yeah, Brad, this is Gary. I would tell you that the big factor that we saw there, if you're looking year-over-year, was our feedstock cost. As you're aware, last year we had a pretty good incentive to move U.S. Gulf Coast barrels to Quebec, and we had a very good feedstock advantage doing that. With the Brent TIR coming in, we lost a lot of that advantage, and it's impacted our North Atlantic basin results.
Okay. Is that an arb that you were still taking advantage of in the first quarter? I'm just thinking about it on a sequential basis versus the first quarter, the margin was down as well.
Yeah. We moved an occasional cargo to Quebec, but even when we're moving it's not near the margin that we saw last year when the arb was much wider.
Okay. I'll leave it at that. Thanks.
Thank you. Our next question comes from Spiro Dounis with UBS.
Hey, good morning, gentlemen. Thanks for taking the question. Just two quick ones, hopefully. First, just on the OpEx. Figures are pretty strong this quarter, despite, I guess, slightly lower utilization. I guess, just wondering how repeatable that is. I know next quarter it sounds like it's going to tick up a bit, just given the turnarounds. Beyond that, just wondering if there's sort of belt-tightening going on and how much more we could see of that.
This is Lane. I'll answer that. We're always belt tightening. We run our business very disciplined. We're always very attentive to all of our costs, and that's just the way we run our business. I would say our throughput is largely when you sort of compare quarter-to-quarter, year-over-year, it has to do with what our relative throughputs were through that timeframe that affects things. Obviously, natural gas has a big hand in this. Those are really the two. When you start really looking at at least our cash operating expenses, it's really the energy, and it has to do with our throughput.
Got it. That makes sense. Just second one, it seems like West Coast was a bit of a bright spot over the last quarter, both on margins and costs. I guess, just focusing more on margins, I guess, how sustainable is that? I guess over the last few weeks, they've come in a bit, but I know driving on the West Coast has been pretty strong, and it seems like demand there is pretty strong. On top of that, I think some of the stockpile levels are a bit better than the rest of the U.S. I'm just wondering how you're viewing that market.
I think we feel pretty good about the West Coast. It's a unique grade of gasoline in that market, so it limits some of the stockpiling of barrels. Certainly with the increased demand, the supply-demand balance is much tighter than it used to be.
Got it. Appreciate the color. Thanks, guys.
Thank you. We have a follow-up question from Paul Cheng with Barclays.
Hey. This is for Gary and Lane. When you decide that whether you want to switch the yield between distillate and gasoline, do you looking at the spot economics or that you also take into consideration of the future curve?
You want to take that one?
I would say we do a combination of both. Paul, as you look, we certainly when we're making cut points decision, it's more done on a spot economic basis, but when you talk about catalyst changes, then we're looking more using the forward curve for those type of decisions.
Okay. If just for the cut of the temperature and all that will be just on the spot. You won't be looking at, say, the next two months or three months, what is the futures curve may suggest?
It comes into play, but for the most part, we're looking at spot economics on making cut point changes because we can do that day to day in our refining system.
A final one, if I may. Maybe this is either for Ling and Gary also. If I'm looking at if the third quarter market condition will be exactly the same as the second quarter, given your expectation of your runs, should we assume that your margin capture rate versus your Valero index will be roughly about the same, or that that's something that we should be consider?
Paul, this is Lane. I would say it's going to be roughly the same with the exception of where feedstocks are. That's really the only real major variable in terms of our capture rates. We'll start into butane blending at the end of the third quarter. That will affect it a little bit as well.
That it won't start until September, right? The butane blending. The butane blending won't start until September, I presume.
Right. There'll be a little bit of that impact. The other one is, as we said earlier, we've disclosed that we have a big turnaround in our Port Arthur refinery starting in the third quarter.
Is that a full plant turnaround?
Over the course of the timeframe, most of the refinery, with the exception of our conversion units, will all be down. It's really the crude and coking complex that'll be coming down.
Okay. Thank you.
Thank you. We have no further questions at this time. I will now turn the call back over to John Locke for closing remarks.
Thank you, Vanessa. We appreciate everyone joining us today. Please contact Karen Ngo or me if you have any additional questions. Thank you.
Thank you, ladies and gentlemen. This concludes today's conference. We thank you for participating, and you may now disconnect.