Welcome to the Valero Energy Corporation Report 2015 second quarter earnings conference call. My name is Tiffany, and I will 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. Mr. Locke, you may begin.
Thank you, Tiffany. Good morning, and welcome to Valero Energy Corporation 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 at valero.com. Also attached to the earnings release are tables that provide additional financial information on our business segments. If you have any questions after reviewing these tables, please feel free to contact our investor relations team after the call. I would like to direct your attention to the forward-looking statement disclaimer contained in the press release.
In summary, it says that statements in the press release and on this conference call that state the company's or management's expectations or predictions of the future are forward-looking statements intended to be covered by the safe harbor provisions under federal securities laws. There are many factors that could cause actual results to differ from our expectations, including those we've described in our filings with the SEC. I'll return the call over to Joe for a few opening remarks.
Well, 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, and 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 previously identified. 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. With that, John, I'll hand it back over to you.
Great. Thank you, Joe. 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. Year-to-date, we 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-$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.
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 hash key. If you are 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 are standing by for questions. Our first question comes from Neil Mehta of Goldman Sachs. Neil, you may go ahead.
Good morning.
Morning, Neal.
Joey, 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 of months or even into 2016, where gasoline stays strong and diesel stays weak? Can you talk about the demand dynamics you're seeing from the product side between those two different categories?
You bet, Neal. It would probably be best if Gary Simmons spoke to that. He is closest to the market.
Yeah, Neal. I guess what I would say is we certainly expected some price demand elasticity for gasoline with the fall in flat price, and we have seen that. We did not really know exactly what the magnitude of the pent-up demand would be, and it has 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 have been historically. It is just mainly the strength in gasoline. We would see that there goes some seasonality as we get out of driving season. We would certainly expect some fall off in gasoline demand. As long as we see the lower prices, I think we expect the demand response to continue to be good.
Very good. A 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.
Yeah. Hey, so Neil, this is Lane. Just a reminder on the fundamentals of that project. It's really a natural gas to liquids project. 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 the way up through gate 3. The project still looks good, 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. 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 you were looking for?
No, I think that covers it. Neil, honestly the project looks good, the guys have now identified what the capital might look like. 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 be a 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. Again, we continue to advance it. I would tell you, we feel pretty good about it, 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.
Thank you. Our next question comes from Paul Cheng of Barclays. Paul, you may go ahead.
Hey, guys. Good morning.
Good morning, Paul.
Joe, one of your competitor recently did a deal using their pre-high currency MLP vehicle there to buy another MLP, and the end result for the C corporation has been quite excellent. Last year, the other competitor of yours did something similar. I know that you guys have been focusing on the drop-down, 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 the drop-down?
You know, Paul, I didn't see the transaction that you're talking about. I'm teasing you. 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 drop-downs. We'll execute the second drop-down transaction later this year, I think that you could expect that going into next year, that drop-downs will probably be accelerated somewhat further. It's always a matter of opportunity and timing, 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.
We believe that right now, the most prudent thing to do is to execute the strategy that we've laid out, then longer term, we'll look for opportunities. Obviously, these deals seem to be a double-edged sword. They do create significant value at the C corporation, but they've also had a fairly questionable effect on the LP. In a perfect world, we could get a transaction that would benefit both. Right now, our focus is on continuing to do the drop-downs.
Okay. Second question, maybe this is for you or for Simmons. There seems to be a tightness in the Alky or the high octane component in the market today, just want to see whether you guys agree with that assessment. Secondly, that if it is, how you think it may impact on the industry gasoline supply as well as the gasoline crack. Thank you.
Yes, Paul. This is Gary. We certainly do see that all heavy octane components are trading at a significant premium. I think there's several driving factors here that are causing that to occur. One, you have a very wide spread between Naphtha and gasoline. 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 reformers and Alky units throughout the industry. Some of it is supply related. Finally, some of these export markets, in particular Mexico, we're seeing a lot of good demand from Mexico for gasoline.
Although the octane requirements in Mexico are comparable to what we have here in the U.S., they have an olefin spec on their gasoline, 10 PPM olefins, that forces you to blend a lot more reformate and Alky and less cat gasoline in order to sell your product into that market. 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-Mars discount right now is over $4 and LLS-Mars price at $50, it seems like you guys must be printing money in processing the medium sour, especially comparing to the Maya discount is not really attractive. Do you think that it will ultimately force the Maya discount to rewiden out or that you're actually going to see the Mars discount narrow from here?
No, 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 curve by another $1.50. 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.
I see. Thank you.
Thanks, Paul.
Thank you. Our next question comes from Edward Westlake of Credit Suisse. You may go ahead, Ed.
I think gasoline is going to be a theme. 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. How possible is it, do you think, and obviously specs have tightened as well around the world, particularly for summer grades. 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. As you've mentioned, we're having trouble keeping up with gasoline inventory. I think it will be here for an extended period.
Coming back 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.
Let's put VLP to the side for just a minute. 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 now that we've created a competition within Valero for the use of that cash. 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 them. 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'll have spent somewhere around $800 million on, excluding tanks and infrastructure to support those. Those two projects will be on 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. 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.
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. 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. Our next question is from Paul Sankey of Wolfe. Paul, you may go ahead.
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, then if you've got any observations on how you see the industry running, that would be helpful. Thanks.
Hey, Paul. This is Lane. 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. I do think you're going to see a pretty heavy turnaround season in the first and second quarter next year. If you think back, we had the USW strikes, which caused many of our counterparts to delay much of their turnaround activity. Talking to our maintenance 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 through this earnings season by the strength of U.S. oil production through Q2. 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? How sustainable do you think the import story is going to be? Thanks.
Paul, I'm going to have to defer to my esteemed colleague, Mr. Simmons, on that. He'll answer that.
Yeah. 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 WTI spread comes in and incentivizes people to start importing foreign light sweet. As we've 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 WTI spread got narrow enough that we even took some foreign light sweet into St. James. You see the same dynamic hold on the medium sours. We maximize Mars and domestic medium sour production into our refineries.
As the differentials come in, we actually brought in some Brazilian grades to compete with that when the margins get tight. I think as long as you see this volatility, you'll continue to see windows where it supports imports of crudes into the market.
Yeah, sure. I assume basically 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 at least to an extent, turn around the U.S. refining system?
We're sitting on a pretty good overhang of crude oil inventory here in the U.S. We're 90 million above where we were last year. With that overhang, and then heading into a typical maintenance period where refinery demand is down, you would think that that would have pressure on the price of crude oil.
Yeah, just checking. Thank you.
Thank you. Our next question comes from Evan Calio of Morgan Stanley. Evan, you may go ahead.
Hi. Yeah. Good morning, guys. I look forward to the VLP strategy evolution over time. Look, my question, it may be a follow-up on the buyback. Given the cash position, especially with the drop downs, and I know you raised that potential today, your net debt to cap is at 6%. Does that really imply that while active, you're pacing the buyback so you can continue at maybe at a similar rate even in 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?
Yeah. When we look at our rate on our buybacks, this is Mike, we do look at our future capital and working capital requirements, then also what we've committed to to date. We do realize that we had a great quarter. Our cash balance built despite doubling our buyback rate.
Yeah.
We will continue to look at these things as we move through the year.
Evan, though, the tail on your question addressed 2016 CapEx. We haven't gone through the process of reviewing 2016 details with the board of directors yet, we don't want to get ahead of ourselves.
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. 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 kind of Alky unit proceeding?
Yeah. 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.
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. Okay. 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. 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, okay, 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. That's really our view on that. You want to speak to Alky at all?
Yeah. Evan, it's Lane. The Alky's still in the gated process. It still looks okay. We're going to reach sort of a funding decision, yes or no, somewhere in the first quarter of next year.
Great. That's good news, guys. If I could just, maybe 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 of the year? Thanks.
All right. Evan, this is Lane. I'll answer McKee. I'll let Gary answer Line 9. McKee, we should have the project entirely complete in September. That's a +25,000 barrel a day crude throughput. That's sort of the status of that project.
Good.
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. We don't know what will happen with the hydro test. 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.
Thank you. Our next question is from Jeff Dietert of Simmons. Jeff, you may go ahead.
Good morning.
Hey, 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? Perhaps talk about opportunities to sell gasoline out of the Gulf Coast into California as well.
Yeah, Jeff, this is Gary. Our export volumes of gasoline were down a little bit in the second quarter. 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, Latin America. A small amount of it went to Eastern Canada. On the distillate side, we did 235,000 barrels a day of diesel. We did another 45,000 barrels a day of jet kero. Total distillates were 280,000 barrels a day. Most of that to Latin America. We also sent some of that to Europe. Over 60% of it to Latin America, though. As far as your question on Gulf Coast exports to the West Coast. The way that optimization works is we generally supply West Coast barrels from our Pembroke refinery.
We did do that in the second quarter, Pembroke blended CARB gasoline, which we took to the West Coast.
Got you. Secondly, the industry's focused on distillate yield over time with a historical growth rate that was more rapid for diesel than for gasoline. Recently, it seems 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?
Yeah. I think the big driver for the gasoline demand has just been the lower flat price and demand elasticity and the response to the lower flat price. I think as long as we're in this lower price environment, we'll see good gasoline demand moving forward.
Got you. Finally, you've got the Houston alkylation unit projects that you've been talking about, with the tightness in octane, do you see other projects developing to bring more octane into your portfolio?
Hey, this is Lane. Obviously reformer margins are very wide. Naphtha's very discounted. We're focused on getting our reforming 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 octane besides that.
Okay. Thanks for your comments.
Thank you. Our next question is from Chi Chow of Tudor, Pickering & Holt. You may go ahead.
Great. Thanks a lot.
Hi, Chi.
Hey, Joe. How you doing?
Good.
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. That's an economic optimization. We put our Corpus doc 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. I think that's been the biggest reason.
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 got with Line 9?
Yes, we certainly see that that will be the case. If you looked 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. If this holds, it would be a fairly significant uplift.
Good to hear. Okay. What's your outlook for refining dynamics in Europe going forward here for Pembroke?
Pembroke's a little bit unique, I would say, Chi, in that it's really satisfying the domestic market in the U.K. with some export capability. It tends to not be as exposed to import barrels, for example, as some of the other European refineries might be. I think our view is the same, that 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.
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 through the balance of the year?
It's difficult to predict. Certainly, as you know, 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. 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 remains.
Your plants are running well at this point out there?
Yeah. Chi, this is Lane. I got a knock on wood. They've been running very well.
Yeah. It shows up in the second quarter, so. Okay, thanks a lot.
Good.
Thank you. Our next question comes from Faisel Khan of Citigroup. You may go ahead.
Thanks. Good morning.
Hey, Faisel.
How are you, Faisel?
All right. 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. 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 kind of wait and see, or should we expect something similar in that range? I appreciate all the commentary around capital spending and everything.
Well, we're in the process of running our strategic plan and budget for next year, 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 something special about this year versus the forward years that makes the payout ratio at 75% this year different than I'm just trying to understand how you guys are philosophically looking at the outlook on this payout ratio?
To achieve a minimum of 50% payout ratio. I think you can 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, 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. The other thing we can tell you is that we don't plan to raffle cash. Depending on the performance in the business, we would look at returning surplus cash flows to shareholders. That being said, there's other opportunities that may come up that from quarter to quarter, we want to change that.
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. We're going to let the investment-grade rating overall govern this. 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. Thanks. The last question. I believe you received sort of the last set of rail cars, the 5,300 you purchased. Just trying to understand, how is our fleet being utilized now? I know the differentials have been pretty narrow, but just trying to understand sort of 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've been seeing in the past. However, the differentials are coming back up, and so we see that we'll start ramping up volumes at our Lucas terminal. We're still taking volumes to Memphis via rail, St. Charles as well. 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.
Okay.
Yeah. This is Martin Parish. On the ethanol, we run at least 2,800 cars there routinely, and that business we don't see that changing. We've got a lot of room there for rail cars.
Great. Thanks for the time, guys. Appreciate it.
Thank you. Our next question comes from Phil Gresh of J.P. Morgan. Philip, you may go ahead.
Hi, good morning. Just one follow-up first on the distillate exports. Obviously, the trends have softened over in Asia the past month or so. I was just kind of wondering what you're seeing more recently relative to the Q2 trends 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 this break even, and it's still about there. The big thing that's impacting that is freight. The freight has been varying anywhere from $0.07-$0.11, and depending on freight, it means the arb is either open or closed. I would tell you today, it's about break even.
Got it. Okay. On the commentary about potentially accelerating drops, curious how you're thinking about the capacity for drops right now. If you accelerated, how much more would you be able to do? How much could the market handle in your view?
Well, it wasn't really commentary. It was just a comment. Okay? 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 probably as good as our sense on how big that market is. We think that we can execute the transactions and do the drops on the pace that we're thinking about without rattling the market. Rich, is there anything that you'd add to that?
No, I think that's kind of the plan. To grow distributions, and that targeted 25%-
Right
average range.
Yeah. Yeah. Phil, we just haven't wavered on that. 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. 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 drop capital on top of that. In terms of buybacks, I believe that's something you said in the past. Just wanted to confirm that.
Let me say what we've said in the past was 50% plus the cash proceeds for buybacks. All right? Resetting the target to 75% of net income is now going to be 75% of net income. All right? Mike, you want to elaborate on that?
No. That's pretty much it.
The drops, of course, and you know this, Phil, we haven't taken a lot of free cash in on these drops yet. 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. From our perspective, what we've done is just simplify the way to look at this, and we're saying 75% of net income.
Okay, fair enough. 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. 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? Is it more of a let's wait and see how it goes for the next year and not really looking at those types 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.
Yeah, Phil, we're not opposed at all to acquisitions. We tend to look at everything that's out there. We're well-positioned to do acquisitions, but we just haven't found one yet that we think adds value for Valero shareholders.
Fair enough. Okay, thanks.
Thank you. Our next question comes from Doug Leggate of Bank of America Merrill Lynch. You may go ahead.
Thank you. Good morning, everybody.
Thanks, Doug.
Joe, periodically you've talked about whether the West Coast was strategic for Valero, and obviously it's been the I guess with the Torrance situation in February, the sector's never really looked back against the strong gasoline demand. I'm just curious, does your view on the strategic importance of the West Coast change given recent events? Just a general update as to how you're thinking about that.
Okay. Well, Doug, honestly, I think that 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's 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. It does provide a very interesting option for periods like this, where we've got basically extraordinary cracks. 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 to get your sense as to what you're really seeing in this market currently. We've not made any secret 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. I guess what I'm really getting at is that last year, gasoline cracks were zero in December. We're probably going to see a half a million barrel a day drop in demand in gasoline, let's say seasonally, between now and the end of the year. 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?
Well, not so much from your peers, but from yourselves as far as what your plan would be. If your LP's still telling you to max gasoline, do you keep running that until it flips, even though the gasoline demand drops? Obviously that is a harbinger for weaker gasoline cracks in the second half of the year. 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, you want to?
Yeah. Overall, the way our optimization works is, it would be like you suggested. We would continue to maximize gasoline as long as the pump 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 distillate 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. As it falls below $15, that's when you start to see utilization in Europe fall.
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 ask a quick follow-up on that topic. There's been a lot of chatter about delays and ultimately startups finally coming in Middle East refining. That obviously is probably going to back into the Atlantic Basin, some European products. 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? If so, how you see it impacting the current market environment? I'll leave it there. Thank you.
Yeah. 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. 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.
Doesn't that back into the Atlantic Basin, though?
It could. Again, we have not seen any indication of that as of yet.
Doug, the other thing to keep in mind is that U.S. Gulf Coast refining is very competitive. Your concern is that ultimately these barrels get pushed back at us, which you do is have some rationalization. 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.
Appreciate the answers, guys. Thank you.
Thank you. Our next question comes from Roger Read of Wells Fargo. You may go ahead.
Hey, 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. If I look at Q3 guidance for throughput, it's 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. 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 3 projects that'll be on stream certainly by the beginning of next year. We got the 2 crude toppers, Corpus and Houston, those will produce significant returns for our shareholders. 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 in our refineries, we haven't received the benefit of that yet. We've got those 3 things that are clearly in hand. Down the road, we've got the Diamond Pipeline, which will certainly add benefit to the Memphis refinery. As I mentioned, we've got the methanol project that we continue to look at. Lane's got some other smaller, that you'd almost call self-help or optimization projects, which we're running the traps on.
Martin Parish has some of those similar type of projects for the ethanol business. There's no hydrocracker project that's coming on that's going to create some step change in what we're looking at. 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, we'll see continued growth as a result of that.
Appreciate the answer. Getting back to the questions that have been asked earlier on the distillate side. Small part of the overall complex, jet inventories have really increased significantly over the last several months. Just wondering if there's any color you can provide on that. I'm talking about total U.S., 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. What's driving that?
All right. Good enough for me. Thanks, guys.
Thank you.
Thank you. Our next question comes from Blake Fernandez of Howard Weil. You may go ahead.
Hey, guys. Good morning. Hope you're doing well.
Thanks, Blake.
Gary, I wanted to go back. There was a lot of discussion on the strength in gasoline, 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?
Go ahead.
This is Lane. I'll give it a shot. Right now with naphtha so dislocated, normally we'd flex that in and out of a distillate pool, you really need to compare it to jet. You say, "Well, 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 had been trying to make naphtha, it'd even be bigger than that. It'd be more like 8%-9%. To date, we've been trying to minimize naphtha just because of where the market is on naphtha.
Lane, is it fair to think going into 3Q, we may see a little bit higher yield on gasoline, just given its strength here?
Well, Gary alluded to it earlier. We run our models, and we have a forward view, and we run our assets into that forward view. I think seasonally, somewhere in October-ish, we normally see a switch in the signals where we'll maximize diesel at the expense of gasoline.
Okay.
Blake, are you trying to understand, are we maximized on gasoline today at a 48% yield?
Yes.
The answer to that is yes.
Okay. Yeah, I'm just trying to get a step change going moving forward, Joe. Joe, you briefly touched on M&A at the parent company level, and I guess as I look at the equity price moving higher as a result of these aggressive buybacks, I'm just curious, is it fair to think that as the stock price moves higher and you have considerations of what to do with capital, does asset-based M&A become more likely as Valero shares move higher?
I wouldn't say it's more likely because Blake, we always have an eye towards it, and historically done this, too. We've tended to look at M&A opportunities outside of the context of the capital budget. Mike's got a balance sheet here that's gold-plated, and so we have plenty of opportunity here without using the equity to do that. Our real focus here has been twofold, and we've talked with you about this. Number one, try to demonstrate the earnings potential for the company through excellent operations and try to get our multiple to the point where we're not trading at a discount to the peer group. That's number one focus. Number two, what that does is provides you with the opportunity to do something with the equity if you ever choose to do a very significant transaction.
Although we don't have anything like that on the radar screen today, we could do fairly sizable transactions with the balance sheet as it sits today, and in this case, they'd be highly accretive transactions without negatively impacting things. Now that being said, we've looked at the market, we've looked at what's out there, and we just haven't seen anything yet that warrants us to do that.
Okay. Very clear. Thank you.
Thank you. Our next question comes from Brad Heffern of RBC. Brad, you may go ahead.
Yeah. Good morning, everybody. Maybe one for Gary. Thinking about McKee, you guys have obviously made some strides into getting more Midland barrels into that refinery. Do you have any thoughts on Midland trading at a premium right now, whether you think that's sustainable, and whether you guys are optimizing the Midland out of that refinery and going back to Cushing, or how you're dealing with it?
Yeah. We don't have a lot of flexibility at McKee to swing between the Midland and Cushing markets. A lot of what we have are term contracts with producers that are tied to one market or the other. I think we're probably in a realm where Midland stays fairly strong because there's a lot of takeaway capacity from that market. Our view would be that Midland stays pretty close to parity to the Cushing market or could trade at a slight premium to it.
Okay. Thanks for that. Joe, any thoughts on the proposed Renewable Volume Obligations at this point?
It's very interesting, I'm sure you've read some of the same stuff that we've read here recently. The notion of shifting the obligation seems to be being recognized as a potential positive. I think that there was a letter that was put out here this past week that somebody shot across my desk, which talked about the fact that shifting the obligation might actually lead to incremental blending of ethanol. That certainly would be a huge benefit to us if that were to take place. Martin, is there anything you'd like to add?
I think on the RVOs itself, certainly for 2015 is pretty achievable. You get a little tighter to the blend wall in 2016, but with the carryover RINs, we don't see that as a real big issue. The question, as Joe said, where does the obligated party go, and what happens in 2017?
That's more of a long-term solution for us than the short-term relief. We're hopeful. We always are.
Understood. Thank you.
Thank you. Our final question comes from Paul Cheng of Barclays. You may go ahead.
Hey, guys. Two quick follow-up. One, in the past, Joe, I think that Valero raised dividend two times a year, and the second time is around this time. On a going forward basis, have you guys changed the process to become more of an annual process?
Oh, Paul. We have raised it two times a year. Typically, they've been a little more modest than the one that we did back in January. I can let Mike speak to this a little bit. You want to take a shot?
Well, I guess, we had a very significant increase in the dividend in January. As I'd mentioned earlier, obviously, we've got a material amount of cash. We will be looking at our options to utilize that cash over the next few months.
One of them, obviously, is the dividend.
Right. I guess, Mike or Joe, that what I'm asking is that, is there an intent effort from management that changed that become an annual consideration or that this is more ad hoc, that we shouldn't really look at, say, in the past, it's two times a year, and now that you look like this year is one time. I mean, just to see if there's a process or a schedule we should know.
Yeah. No, I understand, Paul. Let me just say this. Bi-annual increases in the distribution, in the dividend, wasn't something that we've institutionalized. In this case, the large increase we had back in January was because we were lagging. I think we have a sense that there's opportunity to raise the dividend again. Now, what I don't want you to do is hold me to something going forward that we're going to continue to raise the dividend twice a year into perpetuity. I do think it's safe to say, as Mike described, that we're taking a good hard look at it. Paul, you know how devastating it is if anyone ever has to cut the dividend. We're more deliberate on that.
It's obviously easier for us and provides more flexibility to buy back shares and return cash that way, we are looking at the dividend.
Sure. Second one is for Martin. To see if there's any opportunity in the bottleneck for your alkylate or reformer units in your system, or that you already max out, there's really not much of a bottleneck opportunity there?
Hey, Paul. Yeah, I alluded to this earlier. This was unusual versus where the signals to run the reformers had been in a couple of years. We had to relearn in terms of where we could run the reformers. We've always been max optimizing alkylate. Alkylation units have been very good for several years now. We are at our maximum reformate and alkylate capacity today.
Have you gone into and see whether you can make some small investment and be able to expand the capacity on those units inside your system? That you haven't done that process yet?
We are. We did a robust look at all of our Alkys. We started really looking at our alkylation units about three years ago and figuring out where we want to spend, where we wanted to put the dollars, and that's where we sort of landed on this Houston alkylation project. Obviously, it's an iterated process. As Joe's mentioned several times in the call, we have a list of smaller projects that we're working. We're being careful not to try to tout them ahead of when they would be ready for showtime. There's clearly an opportunity to address this octane shortfall in the market. We're obviously working those projects.
Thank you.
Thanks, Paul.
Thank you.
Yes.
Yes. We have no further questions at this time. You may proceed with closing remarks.
Okay. We appreciate all those who called in today and everyone listening. If you have any additional questions, please contact me or Karen. Thank you.
Thank you. Thank you, ladies and gentlemen. This does conclude today's conference. Thank you for participating. You may now disconnect.