Valero Energy Corp (VLO) — Q2 2015 Earnings Call Transcript

Thank you, Tiffany. Good morning and welcome to Valero Energy Corporation's second quarter 2015 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. 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 our 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 will turn the call over to Joe for a few opening remarks.

Thanks very much, John, and good morning, everyone. As John will cover in more detail shortly, our team operated our system safely, reliably, and efficiently during the second quarter, allowing us to capture a very high percentage of the favorable margins available to us. In particular, we saw market conditions that incentivized maximum gasoline production in most regions. As for our priorities, we continue to demonstrate our commitment to stockholders by exceeding our total payout guidance. As reflected in the earnings release, we've increased the targeted total payout ratio for 2015 to approximately 75% of net income. We continue to advance the next dropdown transaction to Valero Energy Partners LP, which is our sponsored MLP. We've also completed our estimate of potential MLP-eligible EBITDA within our fuels distribution business. In that regard, we've identified approximately $350 million that may be eligible for dropdown transactions to VLP, which is incremental to the approximately $800 million of remaining EBITDA that we've previously identified. And finally, in regard to the proposed methanol project at St. Charles, we plan to have a final investment decision by the end of the fourth quarter. As a reminder, our prior investments in hydrogen production capacity at the refinery provide us with a competitive advantage versus a greenfield methanol plant in the U.S. Gulf Coast region. So with that, John, I'll hand it back over to you.

Great, thank you, Joe. Now moving on to the quarterly results, we reported net income from continuing operations of $1.4 billion or $2.66 per share versus second quarter 2014 earnings per share of $1.22. The refining segment reported operating income of $2.2 billion, notwithstanding planned turnaround work on the FCC and alky units at our Port Arthur refinery. Refining throughput volumes averaged 2.8 million barrels per day, which is an increase of 87,000 barrels per day versus the second quarter of 2014. Our refineries operated at 96% throughput capacity utilization in the second quarter of 2015. Refining cash operating expenses were $3.66 per barrel in the second quarter of 2015, or $0.24 per barrel lower than the second quarter of 2014. Lower energy costs, primarily due to lower natural gas prices and less planned and unplanned downtime, were the main drivers for the decrease. The ethanol segment generated $108 million of operating income in the second quarter of 2015 versus $187 million in the second quarter of 2014. General and administrative expenses excluding corporate depreciation were $178 million in the second quarter of 2015. Also in the second quarter of 2015, net interest expense was $113 million, which is $15 million higher than in the second quarter of 2014, primarily due to the debt issuance in March of this year. Depreciation and amortization expense was $425 million. The effective tax rate was 30.8%. With respect to our balance sheet at quarter end, total debt was $7.3 billion and cash and temporary cash investments were $5.8 billion, of which $52 million was held by VLP. Valero's debt-to-capitalization ratio net of $2 billion in cash was approximately 20%. Valero had over $5 billion of available liquidity excluding cash. Cash flows in the second quarter included $530 million of capital spending, of which $160 million was for turnarounds and catalysts. We also repaid $75 million of debt that matured in June. We returned $870 million in cash to our stockholders in the second quarter, which included $203 million in dividend payments and $667 million for the purchase of 11.3 million shares of Valero common stock. Year-to-date we've purchased 19.5 million shares for $1.2 billion. For modeling our third quarter operations, we expect throughput volumes to fall within the following ranges: U.S. Gulf Coast at 1.57 million to 1.62 million barrels per day; U.S. Mid-Continent at 445,000 to 465,000 barrels per day; U.S. West Coast at 275,000 to 295,000 barrels per day; and North Atlantic at 475,000 to 495,000 barrels per day. We expect refining cash operating expenses in the third quarter to be around $3.75 per barrel. Our ethanol segment is expected to produce a total of 3.8 million gallons per day in the third quarter. Operating expenses should average $0.37 per gallon, which includes $0.04 per gallon for non-cash costs such as depreciation and amortization. We expect G&A expense excluding corporate depreciation for the third quarter to be around $180 million, and net interest expense should be about $110 million. Total depreciation and amortization expense should be approximately $450 million. And our effective tax rate is expected to be around 33%. Lastly, following the EPA's announcement of proposed RFS targets in late May and the subsequent decline in Ethanol RINs prices, we expect 2015 RINs expense to be between $350 million and $450 million. Tiffany, we have concluded our opening remarks. In a moment, we will open the call to questions. During the Q&A, we ask that our callers please limit each turn to two questions. Callers may rejoin the queue with additional questions as time permits.

Good morning.

Morning, Neil.

Joe, we continue to see this tremendous bifurcation in the crack between gasoline and diesel. Is this the world that you envision here over the next couple months or even into 2016, where gasoline stays strong and diesel stays weak? And can you talk about the demand dynamics you're seeing from the product side between those two different categories?

You bet, Neil. It's probably best if Gary Simmons spoke to that. He's closest to the market.

Neil, I guess what I would say is we certainly expected some price demand elasticity for gasoline with the fall in flat price. And we've seen that, and we didn't really know exactly what the magnitude of the pent-up demand would be. And it's been a very pleasant surprise, and I think we do expect that that response will continue into the future. Overall, you talk about diesel margins being weak. Really diesel margins are about where they've been historically. It's just mainly the strength in gasoline. We would see that there would be some seasonality. As we get out of driving season, we would certainly expect some fall-off in gasoline demand. But as long as we see the lower prices, I think we expect the demand response to continue to be good.

Very good. And then the follow-up here is on the methanol project. Maybe I'm over-interpreting the remarks here, but it sounds like you're more constructive on a possible project. Can you talk through the pluses and minuses associated with methanol and just remind us of some of the project economics?

Okay, we'll let Lane talk to this and then we'll all add.

Neil, this is Lane. Just as a reminder on the fundamentals of that project, it's really a natural gas-to-liquids project. And we still have a long view that natural gas is going to be advantaged going forward, and it is one of the most economical ways to get natural gas into the liquids, crude-related pricing environment. We did review all of the way up through Gate 3. The project still looks good. But as we've mentioned in all of our Investor Relations meetings, where we are now is trying to get the right deal with a partner to make this a good deal for our shareholders, and that's what we're working on currently. And we expect to have some resolution on that by the end of this year or early first quarter. What else was it?

I think that covers it. Neil, honestly, the project looks good and the guys have now identified what the capital might look like, and we're just working through the negotiations with a partner on what the transaction might look like. We consider having gas-to-liquids projects as good projects for us. We also consider that entering into what we would consider to a be bit of a new line of business, it's always prudent to try to manage that risk and to look for opportunities not only to do a project like this but additional projects going forward. So again, we continue to advance it. I would tell you we feel pretty good about it. And if we can get the type of deal that we're looking for, I would suspect that we'd advance it.

Thanks, Joe.

You bet.

Hey, guys, good morning.

Good morning, Paul.

Joe, one of your competitors recently did a deal using the high-currency MLP vehicle to buy another MLP, and the end result for the C-Corp has been quite excellent. And last year the other competitor of yours did something similar. So I know that you guys have been focusing on the dropdown. But given the success from your competitor, is that something that you guys will reconsider, maybe shifting the strategy a bit here or that you're going to stick with dropdown?

Paul, I didn't see the transaction that you're talking about. I'm teasing you. But I think, look, we've seen two transactions now take place like this. Let me start by saying we clearly understand the value of the general partnership and we understand the value of pushing to the high splits. That being said, we're very comfortable with the approach that we've taken thus far with our dropdowns. We'll execute the second dropdown transaction later this year, and I think that you could expect that going into next year that dropdowns will probably be accelerated somewhat further. But it's always a matter of opportunity and timing, and for us we don't believe that VLP currently is positioned to do a transaction similar to this on their own. They don't have their investment-grade rating. We're probably a year behind these others in getting an MLP into the marketplace. And so we believe that right now the most prudent thing to do is to execute the strategy that we've laid out, and then longer term we'll look for opportunities. And obviously, these deals seem to be a double-edged sword. They do create significant value at the C-Corp, but they've also had a fairly questionable effect on the LP. And so in a perfect world, we could get a transaction that would benefit both, but right now our focus is on continuing to do the dropdowns.

Okay, second question. Maybe this is for you or for Simmons. There seems to be a tightness in the alkylate or the high-octane component in the market today, and I just want to see whether you guys agree with that assessment. And secondly that if it is, how do you think the impact on the industry gasoline supply as well as the gasoline crack? Thank you.

Yes, Paul, so this is Gary. We certainly do see that all heavy octane components are trading at a significant premium. I think there are several driving factors here that are causing that to occur. One, you have a very wide spread between naphtha and gasoline, so that's incentivizing people to try to blend naphtha into the gasoline pool. In order to make that happen, you have to have a high-octane blend component. The second thing that's happened is there has been quite a bit of planned and unplanned maintenance on re-formers and Appalachian units throughout the industry. So some of it is supply-related. And then finally, some of these export markets, in particular Mexico, we're seeing a lot of good demand for gasoline. And although the octane retirements in Mexico are comparable to what we have here in the U.S., they have an olefin spec on their gasoline, NPT and olefins, and that forces you to blend a lot more reformate and alkylate and less TET gasoline in order to sell your product into that market. So I think this is something that we see that will continue into the future.

Gary, can I ask a slightly somewhat different question? With the LLS mass discount we know with Maya is over $4 and LLS priced at $50, it seems like you guys must be printing money in processing the medium sour, and especially comparing to the Maya discount is not really attractive. So do you think that it will ultimately force the Maya discount to be wider now, or that you're actually going to see the mass discount narrow from here?

I think we're into a period where the crude discounts will be very favorable for us in the third quarter. Yes, economically right now we're incentivized to maximize medium sours in our system. I think the hard thing to see when you talk about heavy sours is certainly we agree with your comment; Maya is not priced competitively today. When we roll to August, they have widened the K by another $1.50. And most of the heavy sours that we're buying are not off the Maya formula, which gives us a good incentive for those as well.

Thank you.

Thanks, Paul.

I think gasoline is going to be a seam – congrats on the results. I was just looking at a chart which showed that globally we're 2.5 million barrels a day more gasoline demand than we were before the financial crisis. So how possible is it do you think, and obviously specs have tightened as well around the world, particularly for summer grades. And how possible is it do you think that we just hit a tipping point and this could take some time to resolve?

I think it will take some time to resolve. We're certainly running all of our gasoline-producing units at max utilization. We've seen good utilization in Europe. And as you've mentioned, we're having trouble keeping up with gasoline inventories. So I think it will be here for an extended period.

Coming back then to the more strategic payout versus growth, obviously you've been very clear about what you're planning to do this year. Presumably with VLP also being a little bit, should we say, still needing to develop before you could do something maybe more strategic with that, you would continue to adopt that through into 2016 because obviously your guidance was very much this year. Maybe some broader comments about payout versus reinvesting for growth in the business.

Okay, and so let's put VLP to the side for just a minute. But, Ed, we believe that growth and return of cash to shareholders aren't mutually exclusive, and I think that we've been demonstrating that. We've shared in our analyst presentations a definition of what we would consider to be discretionary and non-discretionary uses of cash, and we explained how we've created a competition within Valero for the use of that cash. And from a capital project perspective, it's largely based on the adequacy of the returns and then the timing to get the projects through our gated process to where we're looking at doing that. But I don't want – with our increase in the payout ratio, we view this as an opportunity to return what we would deem to be excess cash to shareholders. It's not at the expense of starving the organization of capital certainly for our maintenance projects but also for our growth strategy projects. We forget that we've got two crude units that we've spent somewhere around $800 million on excluding tanks and infrastructure to support those. Those two projects will be on the first part of next year. We've got investments that we made in Line 9 assets that are going to allow us to take that crude into the refineries, which will provide significant crude benefits for us. That hasn't shown up yet in the earnings because of course Line 9 isn't functioning yet. So we've got a lot of things we're doing to drive growth in the earnings of our business in addition to returning cash to shareholders. But as we've communicated clearly too, I think we're being very disciplined in our assessment and in our communications of our plans around these projects, and we'll continue to do that. It doesn't mean that Lane and his team aren't looking at a host of very interesting projects for the refining business, but they tend not to be of the order of magnitude like the hydrocracker projects. They tend to be smaller, higher returns, and projects that we can execute quicker. As we run them to ground, we'll be happy to share them.

Thanks very much, very clear.

You bet.

Thank you. Hi, everyone. Could you talk a little bit about the outlook for utilization in the back half of the year, turnaround season firstly for you guys to the extent that you're prepared to do that? And then if you've got any observations on how you see the industry running, that would be helpful. Thanks.

Hey, Paul, this is Lane. So, we don't really provide forward-looking comments on our turnaround, but I will say I think you'll see a seasonal drop in utilization in the industry going into the late third and obviously the fourth quarter. But I do think you're going to see a pretty heavy turnaround season in the first and second quarter of next year. If you think back, we had the USW strikes, which caused many of our counterparts to delay much of their turnaround activity. So talking to our main contractors, we believe there's going to be a heavy turnaround season in the first half of next year.

Interesting. Lane, while I've got you, could you talk a bit more about crude markets? Particularly, we've been consistently surprised this earnings season by the strength of U.S. oil production through Q2. And also I guess imports are high, and you've talked about some of the spreads that are attractive to you as regards imported barrels. How do you see the market playing out now? Do you get the sense that we are going to see a rollover in U.S. production or not? And also how sustainable do you think the import story is going to be? Thanks.

Paul, I'm going to have defer to my esteemed colleague, Mr. Simmons, on that, so he'll answer that.

I think we've been surprised with the decline in rig count, production still seems to be holding. I don't really know that I can give you much insight whether that will continue or not. I think what we're seeing in terms of the imports is just the volatility in the crude markets. The Brent/TI spread comes in and incentivizes people to start importing foreign light sweet. As we talked about in the past, the first place we tend to do that is our Quebec refinery, which we did in the second quarter. In fact, the Brent/TI spread got narrow enough that we even took some foreign light sweet into St. James. You see that same dynamic hold on the medium sours. We maximize Mars and domestic medium sour production into our refineries. And then as the differentials come in, we actually brought in some Brazilian grades to compete with that when the markets get tight. So I think as long as you see this volatility, you'll continue to see windows where it supports imports of crudes into the market.

Sure, and I've seen particularly that the foreign light sweet is basically just West African that bounces in and out depending on where the spreads are.

Primarily, yes.

When we go into turnaround season coming up and as distillate takes leadership in the market in general, I guess you'd be anticipating lower crude prices through Q3 and Q4 if we turn around – at least to this extent turn around the U.S. refining system.

Yes, I would suspect that that would happen. We're sitting on a pretty good overhang of crude oil inventory here in the U.S. We're 90 million barrels above where we were last year. So with that overhang and then heading into a typical maintenance period where refiner demand is down, you would think that that would have pressure on the price of crude oil.

Just checking, thank you.

Good morning, guys, and I look forward to the VLP strategy evolution over time. My question is maybe a follow-up on the buyback. Given the cash position, especially with the dropdowns, and I know you raised that potential today, your net debt to cap is at 6%. Does that really imply that while active that you're pacing the buyback so you can continue at maybe a similar rate, even in the potentially seasonally weaker margins of other quarters, or really relate to some of the projects that you're maturing in your portfolio with the potential to change that CapEx outlook for 2016?

When we look at our rate on our buybacks, this is Mike. We do look at our future capital and working capital requirements, and then also what we've committed to do to date. But we do realize that we had a great quarter. Our cash balance built despite doubling our buyback rate. So we will continue to look at these things as we move through the year.

And then, Evan, though, the tail on your question addressed 2016 CapEx. And we haven't gone through the process of reviewing 2016 details with the Board of Directors yet, so we don't want to get ahead of ourselves. But we don't see any material change to 2016's numbers. We've got good projects that have good returns, but as I mentioned, they tend to be much smaller. And we don't expect we're going to come out with a big huge capital number to drop on you.

Okay, even with the methanol and/or alky unit proceeding?

Look, the methanol plant, as we've talked about, what we're really looking for in a partner there is somebody who's willing to put skin in the game along with us. And of course, we would view a significant part of our capital contribution to be the infrastructure and other assets that we're bringing to the table. So let's just assume that you're talking about a project that's somewhere around $900 million to begin with, and you ended up with a 50:50 relationship, and part of our contribution to that is going to be what we have in place today. You're not talking about a significant amount of capital from Valero's perspective. We are willing to put some in, but I don't think it's going to exceed anything that we've shared with you. In fact, I'm certain it won't to date. That being said, that project somewhat hinges on our ability to get the kind of transaction that we're comfortable with, number one, that brings expertise to the table; and number two, provides a potential platform for us to do additional transactions down the road. So that's really our view on that. Do you guys want to speak to alky at all?

Yeah. Evan, this is Lane. So the alky is still in the gated process. It still looks okay. We're going to reach a funding decision, yes or no, somewhere in the first quarter of next year.

Great, that's good news, guys. And if I could just maybe get one follow-up as we're talking about capital projects, any detail on the McKee expansion startup and/or Line 9 in the back half the year? Thanks.

Evan, this is Lane. I'll answer McKee and I'll let Gary answer Line 9. So McKee, we should have the projects entirely complete in September, and that's a plus 25,000 barrel per day crude throughput, so that's the status of that project.

Good.

And on Line 9, Enbridge did get the approval to start up the pipeline from the National Energy Board, which was good news. However, they had a stipulation that they had to hydro-test three sections of the line. They have a plan to do that which has also been approved by the National Energy Board. It does require some permits that they don't have, and then we don't know what will happen with the hydro test. But for us, assuming everything goes well, there's a chance that Line 9 is operational by the end of the year.

Good, thanks, guys.

Thanks, Evan.

Good morning.

Hi, Jeff.

Could you talk about product exports for the quarter, especially I guess both gasoline and diesel, and what you're seeing in the international markets there? And perhaps talk about opportunities to sell gasoline out of the Gulf Coast into California as well.

Jeff, this is Gary. Our export volumes of gasoline were down a little bit in the second quarter, and it was primarily just due to the strength of the domestic markets. We exported 76,000 barrels a day of gasoline. Most all of that volume went to Mexico and Latin America. A small amount of it went to Eastern Canada. On the distillate side, we did 235,000 barrels per day of diesel; then we did another 45,000 barrels per day of jet kero. So total distillates were 280,000 barrels per day, most of that to Latin America. We also sent some of that to Europe. Over 60% of it was to Latin America though. As far as your question on Gulf Coast exports to the West Coast, in our system, mainly because of Jones Act 3, the way that optimization works is we generally supply West Coast barrels from our Pembroke refinery, and we did do that in the second quarter. Pembroke blended CARB gasoline, which we took to the West Coast.

Got you. And secondly, the industry is focused on distillate yield over time, with a historical growth rate that was more rapid for diesel than for gasoline. Recently, it seemed gasoline demand has been really strong. Can you talk about maybe some of the major drivers there and how sustainable you think that trend might be?

I think that the big driver for gasoline demand has just been the lower flat price and demand elasticity and the response to the lower flat price. And so I think as long as we're in this lower price environment, we'll see good gasoline demand moving forward.

Got you. And finally, you've got the Houston-Appalachian unit projects that you've been talking about. And with the tightness in octane, do you see other projects developing to bring more octane into your portfolio?

Hey, this is Lane. The only thing we're really, we'll have to – obviously, our re-former margins are very wide. Naphtha is very discounted. We're focused on getting our re-forming unit capability tuned up. We've been working on it all summer to make sure that we are getting full utilization of our current assets. We don't have a whole lot of other, besides the alky, of projects in the pipeline to address the shortage on the octane side yet.

Okay, thanks for your comments.

Hey, thanks a lot.

Hi, Chi. How are you doing?

Good. It looks like you've had this structural uptick in margin capture in the North Atlantic region really over the last four quarters or so. Is this really the result of crude slate optimization at Quebec, or are there other factors contributing to that trend?

Chi, I would say that the biggest driving factor has certainly been that we're supplying the Quebec refinery with domestic crude from the U.S. Gulf Coast. Again, that's an economic optimization, but we've put our Corpus dock in place during the quarter, which gave us a further incentive to get those barrels to Quebec. In April, 95% of the barrels we ran in Quebec were domestic barrels, and I think that's been the biggest reason.

And do you believe once Line 9 starts up, are you going to get another uptick in that capture rate just with the additional flexibility you've got with Line 9?

Yes, we certainly think that that will be the case. If you look at today's economics, a barrel off Line 9 into Quebec would have about a $3 a barrel margin advantage over something that we're sourcing from the Gulf Coast. So if this holds, it would be a fairly significant uplift.

Good to hear, okay. And what's your outlook for refining dynamics in Europe going forward here for Pembroke?

Pembroke is a little bit unique, I would say, Chi, in that it's really satisfying the domestic market in the UK with some export capability. So it tends to not be as exposed to import barrels, for example, as some of the other European refineries might be. But I think our view is the same. Longer term, Western Europe and the Med have probably the least competitive refineries out there. And as barrels move into those markets, they're going to be exposed.

All right, okay, one final question here. In California, obviously, it's been a great environment out there this year. How do you see things playing out in the second half? Do you expect ongoing strong gasoline cracks there for the balance of the year?

Yes, it's difficult to predict. Certainly, as you know, as we head out of driving season, demand weakens a little bit, and then you get more butane blending into the pool. That will swell production some. So to me, a lot of what happens on the West Coast will be supply-driven. And some of these refinery outages that we've been seeing, will they continue or not will really determine how strong the West Coast market will be.

But your plants are running well at this point out there?

Chi, this is Lane. I've got to knock on wood, they've been running very well.

It shows up in the second quarter. Okay, thanks a lot.

You bet.

Thanks, good morning.

Hey, Faisel. How are you, Faisel?

All right, just a couple quick questions. First is just going back to some of the comments around your payout ratio, I just want to make sure I understand. So this year we're looking at a 75% payout ratio. And then just so I understand how that evolves as we go into next year, is it wait and see, or should we expect something similar in that range? I appreciate all the commentary around capital spending and everything.

We're in the process of running I guess our strategic plan and budget for next year, and so we really haven't come up with guidance that we're prepared to give at this particular time.

Okay, understood. Is it fair to say there's – is there something special about this year versus the forward years that makes the payout ratio 75% this year different than – I'm just trying to understand how you guys are philosophically looking at the outlook on this payout ratio.

Philosophically, we started the year saying we want to achieve a minimum 50% payout ratio. I think you could expect that if the business is performing, that would be a minimum that we'd like to live with going forward. You know the potential volatility in this business, and so what we have committed to is we've given you an indication of what we deem to be the minimum cash that we want to keep on the balance sheet. We've got a capital budget that's certainly under control and very manageable. And the other thing we can tell you is that we don't plan to raffle cash. So depending on the performance in the business, we would look at returning surplus cash flows to shareholders. That being said, there are other opportunities that may come up that from quarter to quarter we'd want to change that. But again, if you look at what we've said in the analyst presentations, we're committed to maintaining the assets. We're committed to the dividend. We will continue to look at the dividend going forward and make changes as we see fit. And then we're going to let the investment-grade rating overall govern it. So I think we're very comfortable taking this year's payout to 75%, and I think you could expect that we'll try to maintain a 50% level going forward.

That's very clear, thank you. This is the last question. I believe you've received the last set of rail cars, the 5,300 you purchased. I'm trying to understand. How is that fleet being utilized now? I know the differentials have been pretty narrow. But I'm just trying to understand what the fleet utilization is given the current market situation.

We certainly saw in the second quarter that we didn't have near the advantage to ship crude by rail that we have been seeing in the past. However, the differentials are coming back up, and so we see that we'll start ramping up volumes in our Lucas terminal. We're still taking volume to Memphis via rail, St. Charles as well. So we're utilizing the rail cars, and then some of the general-purpose cars that we have we are going ahead and transitioning into our ethanol service.

And this is Martin Parrish. On the ethanol, we run at least 2,800 cars there routinely in that business. We don't see that changing, so we've got a lot of room there for rail cars.

Okay.

Hi, good morning, so just one follow-up first on the distillate exports. Obviously, the trends have softened over in Asia in the past month or so. I was just wondering what you're seeing more recently relative to the 2Q trend and whether that distillate arb is still there for export. Just in general, what's going on?

I think we're still seeing good demand in Latin America for the distillate exports. That's still there. The other big market for us, Europe, we've been hovering around breakeven, and it's still about there. The big thing that's impacting that is freight. So the freight has been varying anywhere from $0.07 to $0.11. And depending on freight, it means that the arb is either open or closed. I would tell you today it's about breakeven.

Got it, okay. And on the commentary about potentially accelerating drops, I'm curious how you're thinking about the capacity for drops right now. And if you accelerate it, how much more would you be able to do? How much could the market handle in your view?

It wasn't really commentary. It was just a comment. And I think that what we've done, this year we're going to end up slightly over our $1 billion. Next year I think we'll end up slightly over what we're doing this year. Your sense on how big that market is, is probably as good as our sense on how big that market is. But we think that we can execute the transactions and do the drops on the pace that we're thinking about without rattling the market. So, Rich, is there anything that you'd add to that?

No, I think that's the plan and to grow distributions in that targeted 25% range.

Right. Phil, we just haven't wavered on that. And I don't know if you could hear Rich or not but the point was that we've still got the 25%-plus distribution growth as our target.

Sure, okay. And just to confirm on the buybacks that the buyback target is just as a percent of net income and you're going to also add in 100% of all dropped capital on top of that in terms of buybacks. I believe that's something you said in the past. I just wanted to confirm that?

Let me say what we've said in the past is 50% plus the cash proceeds for buybacks. So resetting the target to 75% of net income is now going to be 75% of net income. Mike, you want to elaborate on that?

No, that's pretty much it.

So the drops, of course, and you know this, Phil. We haven't taken a lot of free cash in on these drops yet. And until VLP has access to the public markets, we'll probably continue to have a limited amount of cash that we get from VLP for the drops. So from our perspective, what we've done is just simplify the way to look at this, and we're saying it's 75% of net income.

Okay, fair enough. And I guess to the extent that M&A opportunities do come up on the midstream side, and you've mentioned you'd rather wait a year to get investment-grade, et cetera. But if something comes up that is attractive to you, would you consider doing M&A at the Valero level for midstream and then dropping it down later, or is it more of a let's wait and see how it goes for the next year and not really looking at those sets of opportunities right now?

Would we consider doing an acquisition at the Valero Energy level? Sure, we would look at that and compare that to our other uses of cash and make that decision, but we would consider it.

Phil, we're not opposed at all to acquisitions, and we tend to look at everything that's out there. And we're well positioned to do acquisitions, but we just haven't found one yet that we think adds value for Valero shareholders.

Thank you, good morning, everybody.

Hi, Doug.

Joe, periodically you've talked about whether the West Coast was strategic for Valero. And obviously, it's been – I guess with the Torrance situation in February that this sector has never really looked back against the strong gasoline demand. So I'm just curious. Does your view on the strategic importance of the West Coast change given recent events, or just update us on how you're thinking about that?

Okay. Doug, honestly, I think it's been in the past and it's really well in the past that we looked at potential dispositions around the West Coast. Subsequently, we've said that we view the West Coast as a great option. I think Lane has answered the question that even when margins were challenged out there, we were cash flow positive on the West Coast. We continue to monitor our investments out there so that we don't end up going cash flow negative, but it does provide a very interesting option for periods like this where we've got basically extraordinary cracks. And so I would tell you that this management team hasn't changed their perception, that we really like having the West Coast assets, which as Lane said, are running very well. They have strong management teams. We're very comfortable and pleased to have them as part of this asset portfolio.

Okay, I appreciate the answer. Joe, my follow-up is really more really to get your sense as to what you're really seeing in this market currently. And really you've not made any secret of the fact that we all know this is a seasonal business and we've had a lot of extraordinary events this year, starting with Torrance, albeit against a backdrop of very strong demand. And I guess what I'm really getting at is that last year gasoline cracks were zero in December, and we're probably going to see a 0.5 million barrel a day drop in demand in gasoline seasonally between now and the end of the year. So my question to you is do we see the typical rotation towards distillate given where distillate cracks are right now from yourselves and from your peers? And not so much from your peers but from yourselves as far as what your plan would be? If your LP is still telling you to max gasoline, do you keep running that until it flips even though the gasoline demand drops? Because obviously that's a harbinger for weaker gasoline cracks in the second half of the year. So we're all wrestling with this, obviously I just want to get your perspective as to how you're planning to run Valero's business if cracks remain at a significant premium for gasoline over diesel.

You bet. Gary, do you want to?

Yeah, so overall, the way our optimization works is it would be like you suggested. We would continue to maximize gasoline as long as the prompt market supports doing that. Looking forward, I do see that you'll have the general seasonal trends and that we'll see some fall-off in gasoline demand, again, a lot of that probably weather-related. But I would expect as we head into the third and fourth quarter that gasoline would get some weaker and distillates strengthen, and we'll put ourselves back into a max distillate mode. The other thing I think happens in the market is, the Northwest Europe 2-1-1 yesterday was around $15. And as it falls below $15, that's when you start to see utilization in Europe fall. And so I think you'll see utilization fall, some due to economics in Europe and then also seasonal maintenance, which will open up the distillate arb again from the U.S. Gulf to start supplying that market with diesel.

Gary, maybe I could just risk a quick follow-up on that topic. There has been a lot of chatter about delays and ultimately startups, and you're finally coming in Middle East refining. That obviously is probably going to back into the Atlantic Basin some European product. So I'm just curious. From an international perspective, we've all been waiting on this international refinery expansion coming, and it never really seems to have arisen. Do you have any perspective as to whether those things are finally coming online, and if so, how you see it impacting the current market environment? And I'll leave it there, thank you.

The only thing I can really tell you is we have not seen an impact in the current market from anything happening in terms of the refinery capacity additions. And our view is that the place that you'll probably see that is more in the eastern Med, which is not really a market we tend to go into.

Doug, the other thing to keep in mind is that U.S. Gulf Coast refining is very competitive. And so your concern is that ultimately these barrels get pushed back at us, what you might do is have some rationalization. But I think that goes to – if you're going to assume it's a zero-sum game, there's going to be winners and losers, and U.S. Gulf Coast refining is going to hold its own very well.

I appreciate the answers, guys. Thank you.

Hi, good morning.

Good morning.

Talked a lot about returning capital to shareholders and improvement this year and absolutely deserve congratulations for that. I'm curious though. Given a year where margins have been so strong, obviously helped out on the West Coast, fairly – if I look at Q3 guidance for throughputs, not really much growth year over year relative to actual numbers. The growth in McKee, what else should we be thinking of as we look forward to 2016 in terms of thinking about earnings growth or cash flow growth or free cash generation? Is it more modest CapEx that helps out? It's hard for us to think about replicating West Coast margins, although the Gulf Coast could obviously be strong. I'm just trying to think about, other than the growth in VLP, where else do we look for some increases in 2016 and maybe into 2017?

We spoke to this briefly earlier today. We've got three projects that will be on stream certainly by the beginning of next year. We've got the two crude toppers, Corpus and Houston, and those will produce significant returns for our shareholders. And then we've got the Line 9 project, which Gary mentioned earlier. We've invested a couple hundred million dollars to prepare to process that crude at our refineries and we haven't received the benefit of that yet. So we've got those three things that are clearly in hand. And then down the road we've got the Diamond pipeline, which will certainly add benefit to the Memphis refinery. And then as I mentioned, we've got the methanol project that we continue to look at. And then Lane's got some other smaller that you'd almost call self-help or optimization projects, which we're running the traps on. And then Martin Parrish has some of those similar type of projects for the ethanol business. So there's no hydrocracker, Roger, that's coming on that's going to create some step change in what we're looking at, but we don't feel we need to do that. We've got a great portfolio that we're executing very well. We have a great team that's making sure that our assets are available and running, and we will see continued growth as a result of that.

I appreciate the answer. And then getting back to the questions that have been asked earlier on the distillates side, a small part of the overall complex, the jet inventories have really increased significantly over the last several months. I'm just wondering if there's any color you can provide on that. I'm talking about total U.S., but you could also point to Gulf Coast jet is up fairly significantly.

I really don't know that I have any commentary on that, Roger, on what's driving that.

All right, good enough for me. Thanks, guys.

Hey, guys, good morning. I hope you're doing well. Gary, I wanted to go back. I think there was a lot of discussion on the strength of gasoline, and you talked about potentially maximizing distillate and gasoline depending on the market dynamics. If my model is set up correctly, it looks like you've been trending at a product yield toward gasoline to the tune of about 48% pretty consistently. Can you remind us what kind of flexibility you actually have to swing that back and forth?

This is Lane. I'll give it a shot. So right now with naphtha so dislocated, normally we'd flex that in and out of the distillate pool, but you really need to compare it to jet. So if you say if it's really discounted we're going to take that out of the mix. We have about probably a 4% ability to change our gasoline to distillate mix. If you were to be in a posture where you have been trying to make naphtha, it would be even bigger than that. It would be more like 8% to 9%. But today, we've been trying to minimize naphtha just because of where the market is on naphtha.

So, Lane, is it fair to think going into 3Q we may see a little bit higher yield on gasoline just given its strength here?

Gary alluded to it earlier. We run our models and we have a forward view and we run our assets into that forward view. And I think seasonally, most of it – somewhere in October-ish we normally see a switch in the signals where we'll maximize diesel at the expense of gasoline.

So, Blake, are you trying to understand, are we maximized on gasoline today at a 48% yield?

Yes, yes.

The answer to that is yes.

You bet.

Just one thing I would add to the question earlier on capital spending for 2016, obviously it's first, the energy market is something we're continuing to watch, and so we need to be thoughtful about our capital allocation in light of that. I don’t want to get ahead of us, but we are also looking to put cash to work that creates long-term value for our shareholders as well.

If you were asking about M&A on the parent side, we'd definitely look at all opportunities; we've always looked at them outside the context of our capital budget. And we are in a ballpark where we can absorb acquisitions without weighing heavily on the balance sheet. It's just that the returns have to add value in that situation. We haven't found those opportunities yet.

Okay, we appreciate all of those who called in today and everyone listening. If you have any additional questions, please contact me or Karen. Thank you.