瓦萊羅能源 (VLO) 2016 Q2 法說會逐字稿

Welcome to the Valero Energy Corporation reports 2016 second-quarter earnings results conference call. My name is Vanessa, and I will be your operator for today's call.

(Operator Instructions)

Please note that this conference is being recorded. And I will now turn the call over to Mr. John Locke, Vice President of Investor Relations. You may begin.

Good morning, and welcome to Valero Energy Corporation's 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's senior management team.

If you have not received the earnings release and would like a copy, you can find one on our website 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 main factors that could cause actual results to differ from our expectations, including those we've described in our filings with the SEC. Now, I will turn the call over to Joe for a few opening remarks.

Well thanks, John, and good morning everyone. In the second quarter we continued to face a challenging margin environment, which was further complicated by high compliance cost headwinds, but 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 US 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, and 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 and above planned 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 products that will provide octane enhancement, feedstock flexibility, and cogeneration to create higher-value products and reduce cost.

Also 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 US 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 the distribution increase of 7.4% for the second quarter, which keeps us on pace for an annual distribution growth rate of 25%. And 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. So 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 to 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 3 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. The 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 rent 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 for 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 have $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: US Gulf Coast at 1.6 million to 1.65 million barrels per day; US Mid-Continent at 415,000 to 435,000 barrels per day; US 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 US 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 US, 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 question. If you have more than two questions, please rejoin the queue as time permits.

(Operator Instructions)

Neil Mehta with Goldman Sachs.

Congrats on a strong cash flow quarter here. I 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 per 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? And then do you expect that we are going to see run cuts this fall here in the US or elsewhere in the world?

Good morning Neil, and thanks for your comments. Why don't I let Gary take a crack at this?

Yes, Neil. I think you know, 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. So ultimately, we are going to need a rebalancing and see lower refinery utilization moving forward. So I do believe that you will 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. And so it caused utilization to be very high, especially like in the January February timeframe, and that's where we built the large overhang of products that we really had to managed out of the rest of this year.

I appreciate those comments, and secondly on RINs here, you maintain the guidance of $750 million to $850 million, but is it fair to say there's some upward bias to the midpoint of the range. Joe, can you just talk about what you ultimately you 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, and then just how you see the RINs issue evolving from here.

Okay, Neil, that's a good question, and 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, mis-aligns the RIN obligation with the ability to comply by blending. So what's happened is it enabled speculators to drive up RIN prices, which really distorts the markets, and it facilitates opportunities for RIN fraud, which we've seen of their fair amount of. Moving the point of obligation really would address these issues, and then it would enable the penetration of biofuel products into the marketplace, to increase their blending. So 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. And then Jay, on process, any comments?

Yes, as everyone knows, if you're engaged in litigation, we are only in a position to control our own efforts and timing, and we are doing everything possible that we can to bring attention to the issue. We have filed the lawsuits, we've filed a petition for reconsideration, and 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 engaged in a rule making process, and 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 timing of the process of litigation, which is very difficult to speculate.

All right. Thanks for the comments.

Evan Calio with Morgan Stanley.

I know you raised your dividend early in the first quarter, and your yield, your indicative yield today is higher than it was in 2008 and 2009. Can you discuss how you stress the dividend when you establish or decide 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, and we do consider it non-discretionary. With our cash position and nearly $5 billion of liquidity we have available to us, we are quite comfortable with the sustainability of our current dividend, and also the payout target of at least 75% of net income. And in addition, we are also -- we're not concerned with the funding of our capital program.

And Evan, we did take a good hard look at this, and obviously margins can be volatile, right? That's an understatement for the year. Last year they were strong, this year they are weaker, and so we ran cases before we presented to the Board the dividend increase, which really looked at different margin scenarios, and that's how we got our comfort level with it. I mean we stressed it pretty hard, and obviously, in this low margin environment, and with earnings where they are we're still in a good position on the dividend. So obviously, we did a thorough job on that.

That makes sense, and 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, and does the higher distribution reflect your view on an improving outlook or cash generating abilities of your assets?

You know 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. So 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.

Paul Cheng with Barclays.

Couple questions. Mike, do you have any preliminary 2017-2018 CapEx that you can share, and if the margins stayed close to where we are over the next one or two years, then how quickly that you can adjust those numbers?

Okay Paul, we haven't disclosed our 2017 capital budget yet but notionally will be spending $1.4 billion to $1.6 billion on maintenance capital, and roughly $1 billion on growth. Obviously, there's more flexibility in the growth category, but the projects that we're identifying are attractive, and you'd want us to complete these at those rates, at those hurdle rates. Today we have lots of cash like I just mentioned, and a lot of liquidity, and we are quite comfortable with 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 gap in the last several months?

Paul, I would tell you, I don't think we've seen any major change. I mean 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. So it's always a negotiation, when you are looking at it.

But you raise 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. And 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 have consistently shared that we look at opportunities all the time, so a transaction like the Parkway Pipeline acquisition wouldn't come as a surprise. But any M&A transactions will need to compete for cash with our growth capital projects, and our buybacks. So 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.

Philip Gresh with JPMorgan.

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 bit back-half loaded because of the turn arounds, or would you maybe say there's some degree of conservatism in the capital budget outlook, being in the $2.6 billion for the year?

Well, we are tracking a little bit below the $2.6 billion. I mean, Lane, do you have any idea on the timing of some of these projects?

What I would say is what we disclosed, and we had a large turnaround at Port Arthur in the third and fourth quarter, that's obvious. That's a big, big turnaround, and that is a known quantity in terms of our ratable spend. I would say we are still holding for this $2.6 billion, but we will 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. And I'll just leave it at that.

Okay. And then 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. Feels like the market is opening up for quality MLPs, and maybe with the pullback in oil now, maybe a little less, we will see. But how are you thinking about the back half of the year on this front?

As far as the drop?

Yes, in terms of the 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 major pace is prudent, and our guidance is still $500 million to $750 million that we gave in the first quarter call. We will continue to look at third-party logistics still that support Valero's core business. And 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.

So I guess we will continue to keep an eye on it. We are not prepared right now to change what we have shared that we are planning to do. Phil, we are 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.

So we will 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, but we are very attentive to it.

Okay thanks.

Roger Read with Wells Fargo.

I guess some of the main topics have been hit. 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.

I guess on run cuts, we continue to have margin to run in our system. We feel good about the fact that we had this natural gas advantage and feedstock cost advantage in the Gulf, that puts us in a very good position below the way, in the refining industry. So we're not feeling any pressure for run cuts, but I do agree that we're going to need some rebalancing in the markets.

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 in the Northeastern United States, where you are ready starting to hear some in the press of run cuts in today's market. I will let Lane comment on the future turnarounds.

Roger, we disclosed the Port Arthur turnaround 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 the economic costs are much lower 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, do you take advantage in a situation what we've come off several years of high margins, and a big economic cost to turnarounds, do you see that -- is that one of the ways the industry corrects the imbalance here?

So 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 to 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 the refineries are struggling from a maintenance perspective, they may bring the maintenance forward, and just fix whatever it is. And if you want to call that a turnaround, you might say that. I could -- but that's I would say that essentially about all that there is.

Okay, thank you.

Doug Leggate with Bank of America.

I guess my first one might be for Mike. Mike, I just wanted to know help us understand the strength of the cash flow in the quarter, just as it relates to reported income, DD&A. It looks like there were some other moving parts in there, and my follow-up is on the industry, please.

Okay. So on the cash flow, we had change in cash, a build in cash for the quarter of $1.1 billion. But other than that amount, $1.3 billion was due to favorable working capital changes. So 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 at roughly $300 million, and then we decreased our inventories in the quarter by about $300 million. So that nets to the $1.2 billion of working capital, benefit.

Great, that helps me close the gap, thanks. Joe, my follow-up is on -- it's a margin question in terms of the octane premium that hasn't appeared to materialize this summer. You mentioned in your prepared remarks, 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's going to be a call for increased alkylate production or whatever it happens to be, in the future, and I'll leave it there, thanks.

Thank you, Doug. So Gary or Lane, do you want to tag team it?

I'll start Doug, and let Lane talk about the projects a little bit. So what we've seen in the market is actually the octane premiums on the West Coast and in the Mid-Continent in the Group 3 market have been stronger this year than what they were last year; however, in the US Gulf Coast and the New York Harbor we've seen weaker octane premiums. And so if you try to get your mind around what's going on, a lot of that is the fact that where you really can store gasoline is in the US Gulf Coast and the New York Harbor.

So when we had that steep contango earlier in the year, people were storing gasoline, and they were largely storing premium grade summer gasoline, and high-octane blend components. So in those markets, in the Harbor and the Gulf Coast, that inventory has come out, it's caused the premiums to be a little weaker this year than what we saw in the past. However in the Group 3 market, 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.

So Doug, this is Lane. We still have the strategic view that octane has value, and it's really in the context of Tier 3 is going to destroy a lot of octane, and of course the autos on a go-forward basis are looking at higher compression engines, so they may in fact want higher octane fuel. And we still -- and the best way to make that we believe is find a way to get NGL into the transportation fuel, and convert that to octane. That's like Houston alkylation project and we studied, with that strategic view, we look at other projects, if it meets our hurdle rates, to produce additional octane in our system.

Appreciate the answer. That's really helpful. Thank you.

Blake Fernandez with Howard Weil.

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 US. 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 the product to other parts of the world, and Europe is basically penetrating the East Coast, or just basically any color you can give us on that framework?

Yes, 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, and then largely due to Jones Act shipping, we're not as competitive going to the New York Harbor as maybe Northwest Europe are, so the natural flow of our barrels is to go South and to South America, and there's been an incentive to send barrels from Northwest Europe into the Harbor.

Okay, and just to clarify, is Houston, the start-up 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.

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 an outlook on exactly where it would occur, but if I heard the guidance correctly on MidCon, it looks like a pretty decent roll over quarter to quarter. Would that guidance contemplate any economic run cuts that you're planning to do inland?

Blake, this is Lane. The way I'll answer that is, today we have positive economics in the MidCon, and you all -- obviously the reason it'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.

Jeff Dietert with Simmons & Company.

My question is 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 might compress as we get closer to the end of the summer driving season? And we've heard some discussion about already shifting to winter grade gasoline production. Does that make any sense?

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. And 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 in the Harbor.

And 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?

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. And so our assets, we just haven't 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 a strong enough signal to maximize our reformers, as much as we had this year, and it's really just the naphtha discount, but I would just say that's the year-over-year difference.

Thanks for your comments.

Ed Westlake with Credit Suisse.

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 OPEC barrels, or are you seeing things like in Venezuela, as they run out of power, are they having to puke out some real heavy rubbish or 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 of 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, petrosuata heavies and that type of thing. That's really the only change that we've seen.

But presumably, those DCOs you can run through your system at a better economics from the synthetic barrels.

Yes, typically, they have more difficulty placing the DCO than they would a synthetic barrel.

That makes sense. And then a separate question. With the cash pile plus organic free cash, 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 are doing $500 million to $750 million of dropdowns, but 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 sort of medium-term CapEx allocation to logistics.

That's a good question. We have a lot of activity under way 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. And 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. But we do have a lot going on. So we are focused on continuing to expand the logistics side of the business, and obviously those assets would be those that support the system, would bring to VLP some third-party volumes, and then continue to expand the drop-down inventory.

Okay, thanks so much.

Paul Sankey with Wolfe Research.

I had a couple 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 alternative strategy if the lawsuit fails, what really is the next recourse after that?

Well Paul, the obvious operating strategy is to try to go ahead and continue to find ways to blend more, right? So expansion of our wholesale marketing business is something that we've got a key eye on. Obviously, acquiring terminalling assets would provide that opportunity. And 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. And I can tell you that based on the conversations that we have, 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.

And we believe that's caused by this structural problem that we talked about earlier. So we're not going to give up the fight. We will continue to push it, both from a regulatory and legislative perspective, and then from an operating perspective.

Yes, understood. Good luck with that. And the other one was again pretty much the first question you answered, which is regarding the market environment. If the demand is higher than this year than it was last year in the US, is it a function of extra refineries being added you think globally, new capacity? Or is it more the competitive advantage of the Atlantic basin and non-US refiners has improved, and therefore they are running stronger? Or I would imagine it's a combination of both but any sort of market commentary you have on that, would be great.

Yes, 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. So as I talked about, typically you get refineries cutting in the fourth quarter and the first quarter, and this year, we saw our refineries running at very high utilization rates, and a lot of that was just due to the steep contango that was in the market.

Yes, understood. And finally from me, the demand side, it seems to be being revised lower in the US. Is that a concern for you? Do you think the demand has been overstated, or do you really think that this is a supply problem? Thank you.

I could give comment on what we are seeing through our wholesale demand domestically, and we're seeing good demand through that wholesale channel. So year-over-year, our gasoline volumes through wholesale are up 3%, and even on the distillate side, we're moving about 1% more through the wholesale channel in diesel than what we did last year.

Great, that's helpful. Thank you.

Faisel Khan with Citigroup.

Just going back to the question that Jeff Dietert asked on switching from summer grade to winter grade and people are 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. But I think after we've gone through this period where the market has been weaker this year, I don't think it's a greater risk as what we saw in the winter, where people were storing the summer grade.

Okay, got you. And then just with the outages in Canada that we saw over the summer, earlier this summer, have you seen those volumes completely recover and how are you dealing with that disruption, and how is that evolving as production ramps back up for you?

Yes, so I think for us, on the Canadian heavy side, we pretty much are seeing all the volume back available to us and the Canadian heavy barrels are being priced very competitively versus either another heavy sour alternative, or a medium sour alternative. So I would say that we have fully recovered from those fires so far.

Okay, great. Thanks for the time.

Chi Chow with Tudor, Pickering, Holt.

Joe, this question may be the same as Paul's, couple questions ago. But just this RIN issue is just 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?

Well it would probably be hard to say that the RIN was helpful to the merchant refining model. Okay? Obviously it's not. But then you get into what are the options for dealing with it, and 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.

And so I really don't have anything to add to that, but I think certainly it's an issue that we are working very hard to deal with, because it does. It puts an expense on the merchant refiner that he shouldn't be bearing today. And so that creates a real problem, it creates an unlevel playing field in the marketplace, and that's never good. So anyway, we will continue to address it the way we are.

Yes, 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, but you've written the whole asset off at this point. So are you suggesting that there's no options going forward to sell or transfer this land to another operator?

I'm looking at Jay to see what we say about this.

The option to transfer is still there, it's just a function of financial requirements. We've chosen to write it off.

Okay, so you can still transfer, but for free, basically. Is that what you're signaling?

Yes, I guess so.

Okay. Great. Thanks for that.

Brad Heffern with RBC Capital Markets

Just a follow-up to Jeff's question a little while ago on yield. Lane, you mentioned the system has been running at maximum gasoline yield for quite a while now, and I think there was maybe an implication to 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 have been. But how are you thinking about making catalyst decisions and so on that affect the next 18, 24 months?

So we are currently, and I would say max jet mode, so the decision you make there is between our cut point between jet and naphtha, and naphtha shows up in our overall result as a gasoline, although it's not really. We export it. So we're maximizing jet. We're still actually maximizing gasoline as the next step, and that's largely due to butane blending economics, and it has to do with what we would call the swing cut between the heavy part of cat gasoline and the LPO, and there's some selling economics as well to bring butane into the pool, so that's how we're postured today. But we are 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 the time there, we make a decision on whether we want to try to fill our alkylation capacity catalytically, with VSM-5 and not run as much rate. And that's normally what we do in the winter, and we're certainly looking at that, and I would be surprised if we didn't end up there.

And on the hydrocrackers, it's a -- 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. So we're still biased on the side of making distillate out of our big hydrocrackers.

Okay, got it. Thanks for that color. And then 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?

Brad, this is Gary. I would tell you that the big factors that we saw there, if you are looking year-over-year, was our feedstock costs. So as you are aware, last year we had a pretty good incentive to move US Gulf Coast barrels to Quebec, and we had very good feedstock advantage doing that. But 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 take advantage of in the first quarter? I'm just thinking about it on a sequential basis, versus the first quarter, and the margin was down, as well.

We moved an occasional cargo to Quebec, but even when we are moving it, 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.

Spiro Dounis with UBS.

Just two quick ones, hopefully. First, just on the OpEx, figures are pretty strong this quarter, despite slightly lower utilization. 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. But beyond that, just wondering if there's belt-tightening going on, and how much more we can see of that?

This is Lane. I'll answer that. We are always belt-tightening. We run our business very disciplined, we are 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 drives when you compare quarter to quarter year-over-year, it has to do with what our relative throughput were through that timeframe, that affects things. And obviously natural gas has a big hand in this, but those are really the two. When you start really looking at our -- at least our cash operating expenses, it's really the energy, and it has to do with our throughput.

Got it, that makes sense. And just second one. Seems like West Coast was a bit of a bright spot over the last quarter, but on margins and costs. And I guess just focusing more on margins, I guess how sustainable is that? Over the last few weeks they have come in a bit, but I know driving on the West Coast has been pretty strong, and seems like demand there is pretty strong. And on top of that I think some of the stockpile levels are a bit better than the rest of the US. Just wondering how you are viewing that market.

Yes I think we felt 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, and certainly with the increased demand, the production -- the supply-demand balance is much tighter than it used to be.

Got it, appreciate the color. Thanks.

Paul Cheng with Barclays.

This is for Gary and Lane. When you decided whether you want to stretch the yield between distillate and gasoline, are you looking at the spot economic, or do you also take into consideration of the future curve?

I would say we do a combination of both, Paul. As you look, we certainly, when we are making cut point decision, it's more done on a spot economic basis, but when you talk about catalyst changes, then we are looking more, using the forward curve for those type of decisions.

Okay, so just for the cut of the temperature and all, that would just be on the spot? You won't be looking at say, the next two months or three months, as the future 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.

And final one if I may. Maybe this is either for Lane and Gary also. If I'm looking at, if the third-quarter market conditions would be certainly the same as the second quarter, given your expectation of your runs, should we assume that your margin capture weight versus your Valero index would be roughly about the same, or that there's something we should be considered?

Paul, this is Lane. I would say it's going to be roughly the same with the exception of where feedstocks are. I mean that's really the only major hurdle, in terms of our capture rates. We will start in the butane blending at the end of the third quarter. That will affect it a little bit as well.

But that won't start until September right? The butane blending won't start until September, I presume?

Right, and so then there'll be a little bit of impact. And the other one is, as we have said earlier, we disclosed we have a big turnaround at the Gulf in our Port Arthur refinery starting in the third quarter.

Yes, is that a full turnaround?

Over the course of the time frame, most of the refinery with the exception of our conversion units will be down, so it's really the crude and coking complex that will be coming down.

Okay, 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.