Good morning. Welcome to Valero Energy Corporation's second quarter 2014 earnings conference call. With me today are Joe Gorder, our CEO and President, Mike Ciskowski, our Executive Vice President and CFO, Lane Riggs, our Executive Vice President of Refining Operations, 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. Now 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. As noted in the release, we reported second quarter 2014 earnings from continuing operations of $651 million, or $1.22 per share. For all periods shown in the tables that accompany the earnings release, our results of operations reflect our Aruba refinery as discontinued operations, and we recognized $63 million of charges in the second quarter of 2014 associated with recording asset retirement and other obligations related to our Aruba refinery.
Second quarter 2014 operating income improved over second quarter 2013, with gains in the refining and ethanol segments partly offset by a decrease in the retail segment due to the spin-off of CST Brands in May 2013. The refining segment throughput margin in the second quarter of 2014 was $9.84 per barrel, which is an increase of $0.58 per barrel versus the second quarter of 2013. Decreases in gasoline and distillate margins relative to Brent in most regions and narrower WTI discounts in the Midcontinent relative to Brent were more than offset by wider discounts on light sweet, medium sour, and heavy crude oil in the Gulf Coast. Also contributing to the higher throughput margin was our Quebec City refinery's increased consumption of North American light crude in the second quarter.
North American grades composed 83% of the refinery's feedstock diet, up from 45% in the first quarter of 2014 and up from 8% in the second quarter of 2013. Additionally, at our St. Charles refinery, we began processing Canadian bitumen via our new crude-by-rail unloading facility. The U.S. crude supply landscape continued to transition in the second quarter, with oil stocks shifting from the Midcontinent to the Gulf Coast. The inventory reduction in Cushing and corresponding oil supply growth in the Gulf Coast led to a $2.49 per barrel decline in the WTI discount to Brent and a $5.19 per barrel increase in the LLS discount to Brent compared to the second quarter of 2013. Gulf Coast sour crude oil differentials to Brent also widened over the same time period due to the increasing supply of crude oil.
The discounts for Mars and Maya relative to Brent increased by $4.69 per barrel and $8.49 per barrel, respectively. Refining throughput volumes averaged 2.7 MMbpd in the second quarter of 2014, which is an increase of 115,000 bpd versus the second quarter of 2013. Less turnaround activity and higher utilization rates spurred by the increased availability of discounted North American light crude in the Gulf Coast led to the increase in refining throughput volumes. Refining cash operating expenses in the second quarter of 2014 were $3.90 per barrel, which is $0.07 per barrel greater than the second quarter of 2013, due mainly to higher energy costs. The ethanol segment generated $187 million of operating income in the second quarter of 2014 versus $95 million of operating income in the second quarter of 2013.
The increase in operating income was mainly due to a $0.39 per gallon increase in gross margin, which was driven by lower corn prices on an abundant corn crop and low industry ethanol inventories at the start of the quarter. Ethanol production volumes averaged 3.3 million gallons per day in the second quarter of 2014, which were lower than the second quarter of 2013 due to production slowdowns caused by lingering rail congestion in the Midcontinent. Now looking at the third quarter for ethanol, we expect volumes to increase with the startup of our recently acquired plant in Mount Vernon, Indiana. Given the favorable ethanol margin environment, we look forward to this plant's contributions. General and administrative expenses excluding corporate depreciation were $170 million in the second quarter of 2014. Net interest expense was $98 million, and total depreciation and amortization expense was $414 million.
The effective tax rate was 34.3%. Now with respect to our balance sheet, at quarter end, total debt was $6.4 billion, and cash and temporary cash investments were $3.5 billion, of which $382 million was held by Valero Energy Partners. Valero's debt-to-capitalization ratio net of cash was 14.1%, excluding cash held by Valero Energy Partners. Valero had approximately $5.8 billion and Valero Energy Partners had $300 million of available liquidity in a debt- $806 million of capital expenditures, of which $240 million was for turnarounds and catalysts. We also repaid $200 million of debt that matured in April. In the second quarter, we returned $361 million in cash to our shareholders, which included $133 million in dividend payments and $228 million in purchases of approximately 4 million shares of Valero common stock.
Subsequent to the second quarter, we continued to return cash to stockholders by purchasing an additional 2.0 million shares of common stock for $104 million. We also increased our regular quarterly dividend for the third quarter of 2014 by $0.025 per share to $0.275 per share, or $1.10 per share annualized. Also in the second quarter, we announced the sale of the McKee Crude System, the Three Rivers Crude System, and the Wynnewood Product System to Valero Energy Partners for $154 million. This transaction closed on July 1st and is an example of executing our strategy to create stockholder value through Valero Energy Partners. For 2014, we maintain our guidance for capital expenditures, including turnarounds and catalysts, at approximately $3 billion.
We expect stay-in-business capital to account for slightly under 50% of total spending and for the remainder to be allocated to strategic growth investments, primarily for logistics and advantage crude oil processing capability. I should add that approximately $870 million of Valero's estimated strategic capital spend for 2014 is on logistics, and most of this is expected to be eligible for drop-down into Valero Energy Partners. Now for modeling our third quarter operations, we expect throughput volumes to fall within the following ranges: Gulf Coast at 1.5 MMbpd-1.55 MMbpd, Mid-Continent at 410,000 bpd-430,000 bpd, West Coast at 260,000 bpd-280,000 bpd, and North Atlantic at 440,000 bpd-460,000 bpd. We expect refining cash operating expenses in the third quarter to be around $4 per barrel.
For our ethanol operations in the third quarter, we expect total production volumes of 3.6 million gallons per day, and operating expenses should average $0.40 per gallon, which includes $0.04 per gallon for non-cash costs such as depreciation and amortization. We expect G&A expense, excluding depreciation for the third quarter, to be around $165 million, and net interest expense should be about $95 million. Total depreciation and amortization expense in the third quarter should be approximately $420 million, and our effective tax rate should be around 35%. Okay, so we have concluded our opening remarks. In a moment, we'll open the call to questions. During this segment, we request that our callers limit each turn to two questions. They may rejoin the queue with additional questions after that.
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 remove from the queue, please press the pound sign or the hash key. If you're using a speakerphone, you may need to pick up the handset first before pressing the numbers. Once again, if you have a question, please press star then one on your touch-tone phone, and we'll stand by for questions. Our first question comes from Jeff Dietert from Simmons.
Good morning.
Morning, Jeff.
I was hoping to hit on capital spending. You are staying consistent with your $3 billion forecast for 2014. I was curious, as you look forward, it continues to be an opportunity-rich environment, in your view, more light processing, more logistics. Perhaps on the logistics side, do you see that as a steady trend or a trend that is accelerating as far as logistics investment opportunities?
Hey, good morning, Jeff. This is Joe. I will tell you raise a very good point. If you look at it broadly, we are going to maintain a very balanced approach with the use of cash, returning it to shareholders via the dividends and buybacks, and then investing to maintain the quality assets, which is a core part of our capital program. We are also investing to take advantage of this natural resource advantage we are enjoying. Relative to the investment in logistics assets, I think what you would see now is a bit of a shift in the strategic capital from, for example, we shifted some of the spending for the proposed methanol plant out to 2015, and we moved the crude-by-rail facility up into 2014.
As the percentage, I think that we have now is 54% of our strategic capital now is focused on logistics, whereas previously, Jeff, it was in the high 40s. The point that you make is one that we clearly agree with and recognize, so we have seen a shift in that capital.
Secondly, could you talk a little bit about your historical capital investment and what types of returns you are seeing so far from some of those investments? Maybe hit on the hydrocracker investments at Port Arthur and St. Charles. What kind of returns are you seeing there based on their performance to date?
Yeah, go ahead.
No, I was saying
Yeah. Jeff, I tell you what, you
complex and determine specifically what the return of that is because of all the interrelationships in the plant. I think we've said in the past, and we would continue to say that the hydrocracker projects were very good investments. The units are running very well, and Lane can speak to that. The products that we're getting out of the units are good, high-quality diesel fuel that we're able to export as EN 590 grades versus a conventional diesel fuel. Although I don't have a specific return on the hydrocracker projects per se for you, I'll tell you we're pleased with the investment. We think they have improved the quality of the portfolio, and they're performing very well.
Yeah. So Jeff, this is Lane. The combined units average 120,000 bbl in the second quarter. They've definitely run very well. These are great units. We're currently in the process of performing a test run at our St. Charles refinery. I would be careful not to say where we are on that, but it certainly allows us to look at a very limited opportunistic capital investment in those units to really bring them up to essentially reval the equipment and the sizes of it. But they've ran fantastically in the second quarter.
Thanks, guys.
Thanks, Jeff.
Our next question comes from Paul Cheng from Barclays.
Hey, guys. Two questions. Joe, and maybe Lane, maybe you already covered it. Do you have a preliminary CapEx outlook for 2015 and 2016?
No, Paul, we don't. I'll tell you what we're doing right now is we're going through the strategic planning process here at Valero, and part of that obviously is a review of any kind of growth projects that we might be looking forward to doing in 2015, in addition to what we've got base loaded. We're spending $1.4 billion, $1.5 billion a year on maintenance and reliability turnarounds. That is going to continue and be fundamentally part of what we're doing. But we haven't settled in on the growth projects that we want to carry forward other than that we continue to pursue the crude units, and we continue to look at the methanol plant. Then as you would expect, there's a host of logistics projects that we're evaluating. But we haven't settled in on the number yet.
Do you have settled into a direction at least? This year is three. Are we talking about from a direction standpoint, flat, up, or down?
Yeah, Paul, it won't be up.
Okay. The second question, do you have an estimated downtime cost in the second quarter in terms of the actual incremental cost, and also if you have it would be helpful there for two numbers. One is the actual incremental cost, and the second one is the opportunity cost that you lost.
I'll answer that.
Hi, Paul. This is Lane. Our unscheduled downtime cost in the second quarter was $103 million.
Okay. $103 million. Is that pre-tax or after tax, Lane?
That's really EBITDA.
Is that opportunity cost or just actual cost? I'm sorry.
That was what we would call our volume variance, which is basically if the units would've performed the way we had planned them, they would've generated another $103 million.
Right. That is the opportunity cost.
Yes.
How about the actual incremental cost? Because I presume that you probably have some, because of all the downtime, you have some additional maintenance costs and all that.
Yeah. It is really that is embedded inside our performance. We would have to get back with you on that exact number.
Okay, will do. Thank you.
The next question comes from Paul Sankey from Wolfe Research.
Hi. Morning, everybody.
Morning, Paul.
Guys, your throughputs in the quarter beat your guidance in every region. You have effectively raised your guidance for 3Q to be more in line with the better performance in Q2. Could you talk a little bit more about the dynamics of how you are coming in so much higher, really within weeks and months of having set the guidance, you are coming in about 10% + higher in terms of throughputs. Could you just talk a bit more about, firstly, the technicalities of that, secondly, the implications, and thirdly, where we might go given the CapEx you have highlighted this year for processing yet more light sweet? Thanks.
Okay. Paul, this is Ashley. On actual throughput runs versus guidance. Guidance, it's a conservative estimate based on planned downtime and turnaround, things like that. Often what you can do is get some throughput. It might be a lower margin throughput because you're buying higher-priced intermediates or other feedstocks to keep downstream units going. Generally, that's where you're going to see deltas.
It's not a function of you running more light sweet and therefore pushing more crude through the refineries?
No, I think we had generally planned to run the amount of light sweet that we expected a few months ago. It more has to do with planned downtime.
Okay. So actually what you're pretty clearly saying is that the better performance is simply due to a conservative guidance that you beat.
Because of relatively heavy planned turnaround activity.
Right. The final part of my question was, does your current CapEx program expand the capacity, or is it a shift mix internally?
Paul, we'll let Lane talk about the crude units and what the impact will be.
Yeah. Paul, this is Lane Riggs. Again, we have our two announced crude units, one in Corpus Christi and one in Houston, with a combined capacity of incremental sweet capability of about 160,000 barrels a day. Then we'll finish our McKee expansion, which is an incremental 25 a day in next year. Those are really the planned expansions on light crude processing capability. With that said, we still are learning the limits of our system on how much light sweet crude we can run, particularly on the Gulf Coast, where it's available. We still optimize those crudes into our system versus our alternative medium sour and heavy sour and Canadian heavy and all these others. We can still optimize and run more if the economic signals are there.
The final part of this whole question is for me to ask you, in the past you said that you need a 10% light heavy differential to run a coker, I think is the guidance. You talked about the sensitivities. Can you give us a sense for what the price differentials need to be for you to be running more or less on lights?
Sure. You're saying to Lane, Paul, this is Lane. So you're saying that we've given guidance in the past that we need a light heavy differential of 10% versus.
Yeah, kind of a rule of thumb for what causes you to run more light sweet in a mix against, for example, a medium sour.
To back out heavy and run.
Yeah, back out heavy and run sweet. It is probably fair somewhere in that number. Today, we definitely have incentive to run all three. They all have slightly pretty similar margins into our crude capacity and/or into an open coker. I think today, if you were to look at them, they are fairly reflective of what the relative values in the refineries are.
Today, you can find 13% off of Brent, right? It is in that general range, and it still would signal us to run the heavy sour crudes versus pushing more light sweet into the plant.
Yes. Correct.
Okay, guys. That is helpful. Thank you.
You bet.
Our next question comes from Sam Margolin from Cowen and Company.
Good morning. I guess I will just touch on the condensate export issue. It seems like it has come into flux a little bit over the past couple of days. I was wondering, as we await the BIS public guidance as far as what the requirements will be in processing, if you have identified any opportunities at Corpus Christi, maybe either on the midstream side or sourced at the VLO level for that kind of processing capacity where you can lean into some regulatory shifts that might nominally work against you, but with VLP, could actually become a revenue and margin driver over time.
Well, Sam, we look at these projects all the time. Right now, we do not have a condensate splitter project on the board. We are very focused on the two crude units that we have talked about and really nothing beyond that at this point in time.
Sam, this is Lane. I will follow up a little bit. The two crude units that we have designed have a designed API gravity of 50. So these two crude units are fairly long on what we would say the equipment necessary to run a pretty light diet. We could run condensate in them. It is just going to be a matter of, again, what the economic signal and how distressed it is. But in our economics, we had LLS and Brent parity, and we had to export naphtha out of the U.S. Gulf Coast to the Far East. So that stream, whether it is condensate, it is naphtha, whatever form it takes, has got to find a market, whether it is Western Europe or the Far East. The value of naphtha and the value of these condensates, it will be interesting to see how it unfolds.
Okay. Even if they are taking up to 50, they will still produce some VGO for the hydrocrackers and some of the other downstream units too?
Yes, but not as much, right? Because it is lighter.
Okay.
That will be included in our economics because our alternative would be the intermediates to fill out our conversion units.
Okay, thanks. I just wanted to touch on differentials in the Gulf, too. There has been a lot of volatility. I think last year, when LLS spiked to that Brent premium briefly in July and August, you guys had highlighted the fact that some barrels were coming in on Longhorn off spec, and the spot market for LLS in Houston got very tight because of that. Is there any single piece of infrastructure development that we can be mindful of here over the last couple of weeks, aside from just very high utilization in the Gulf, maybe the delay in BridgeTex or something of that nature that might explain that LLS pop a couple of weeks ago?
Yeah. Hey, Sam. This is Joe. Randy Hawkins is with us this morning, and Randy is our Senior Vice President of Crude and Feedstock Supply, and he will be able to answer that for you.
All right. Thanks.
Sam, I think you touched on it already, the high utilization rates that led to some of the spike that we saw in LLS at the end of the August trade month. I think you hit it on the nose. The thing that we are looking ahead is the BridgeTex that will bring some of this distressed Midland-type barrels to the Gulf Coast. It should help to provide some of the barrels that the Gulf Coast needs.
Okay, great. I think it is delayed, right? Is there some planned barrels or something that people were missing and sort of a spot market issue, maybe?
Yeah. I think there were maybe some people that were anticipating BridgeTex being a bit earlier, and I think overall, just the high run rate, people were just a bit short and falling inventories as well led to that.
All right. Thank you so much.
The next question comes from Blake Fernandez from Howard Weil.
Guys, good morning. Thanks for taking the question. I had two for you, one bigger picture and then one more specific. The big picture, Joe, as you transition into your new role, I am just curious if there is any low-hanging fruit or any strategic shifts that you see on the radar screen that you really want to address out of the gate.
Blake, good morning. That is a fair question, but quite honestly, I think that this management team that is in the room today has been working with Bill for a long time, and the plans that we put in place are plans that we are all very comfortable with. If you look at what we have got on the burner with the crude units and the logistics investments, then you look at some of the projects that are being contemplated, like the methanol plant, these are all projects that this team feel pretty good about and that we are continuing to advance the conversations around. From an investment perspective, there is not. From a use of cash perspective, we have maintained for some time now that we are going to try to maintain a balanced program between investment in capital projects for growth and return of cash to shareholders.
I think we are going to continue to do that. Very clearly, the fact now that we have had our second dividend increase this year would support the fact that we are committed to increasing the cash returns to shareholders. To date, we bought back about 10.4 million shares, and we will continue to do that throughout the year as cash flow is available to do it. I would say there are no major shifts right now. The ox cart is not in the ditch, and as I mentioned earlier, we are going through the process of pulling together our strategic plan for the next several years. Included in that will be the capital plan. I think we are in a pretty good position.
All right. That is great. The second question, I hope this is one question, but your runs up at Quebec of North American crude have hit 83%. I was hoping you can give us a breakdown of how much of that is being barged from the Gulf Coast and how much is actually piped, I guess, from Canada. I guess similarly on the rail to St. Charles, just trying to understand, should we be thinking about the economics on that as far as once you pay for transport, is that competitive with Maya or even more competitive? Just some general feel about how we should be thinking about the margin impact there. Thanks.
Blake, this is Randy Hawkins again, at Quebec. The split of our North American crude is around 50 a day by rail and about 100 a day via shifts from the U.S. Gulf Coast into Quebec. Could you repeat the question on the Canadian?
Yeah. Basically, it looks like you have started railing bitumen into St. Charles, and I guess I just view that as competing maybe with Maya, and I did not know if by the time you pay for transport to rail it down from Canada, if we should be viewing that as more competitive, in other words, discounted to what you could access Maya at or at par.
Yeah. I would say that the stuff we are railing down from Canada would be on par or better than Maya. The volumes for Q2 are fairly small, but we anticipate those increasing as we move into Q3.
Yeah, Blake, the refinery was turned around in the second quarter, so we really are not going to see the effect of any of that bitumen movement until the third quarter.
Okay, great. Thank you so much.
The next question comes from Faisel Khan from Citigroup.
Good morning. It's Faisel from Citi. Just a question to follow up on Blake's question on Canadian heavy. I guess with the rail capacity at St. Charles and even some of your other facilities, then with the connection to Keystone from Port Arthur, how much Canadian heavy do you guys envision having the ability to access by the end of the year? Then, how are you thinking of that versus your term contracts with Pemex? As you have flexibility to arbitrage those barrels between each other.
Sure. Faisel, this is Randy Hawkins again. On our Canadian volume, we do anticipate with our rail facility in Lucas coming up later in the year that we will increase the amount of rail dilbit that we're taking into our Port Arthur facility. We also buy regularly Canadian heavy off of the pipeline systems coming out of Cushing as well. Right now, we don't anticipate that impacting our volumes with Mexico and more is backing out from the spot heavy that we're doing elsewhere from around the region.
Okay. How much capacity for Canadian heavy do you think you guys will have the ability to run by the end of the year with all this pipeline and rail capacity?
I can't logistics literally.
Yeah. I think for now, we are going to be limited by logistics more so than refinery configuration.
Okay. Fair enough. My last question is on the changes in the rail regulations that we've seen from the DOT and also the Canadian regulators. Is that going to have any impact on the volumes you guys are moving around your system by rail?
Yeah. Faisel, I think we're all waiting to see what those regulations end up settling in at. If you look at the things that are being proposed with the shell thickness and the top lane protection systems and the braking systems, there's going to be a lot of retrofitting activity and modifications to already planned cars that are going to have to take place. Frankly, the rail fleet that's in service today is very large, and depending on the timeline for these retrofits, it's going to have an effect on rail movements just in general. We don't have a good estimate yet as to what the overall impact is going to be. We are in the process of working the issues ourselves, specifically working with the AFPM and formulating a response to the DOT and to Transport Canada's proposal.
But it's probably just a little bit early for us to give you any idea as to what the impact might be.
Okay, understood. Thanks. I'll get back in the queue.
Our next question comes from Doug Leggate from Bank of America.
Hey, guys. It's Jason Smith on for Doug. If we could maybe touch on throughput from the product side. With you guys in the industry seemingly running at a higher overall level, and in the release, I think you highlighted product prices versus Brent. Can you talk about what the implications of a self-sufficient U.S. system are, particularly on gasoline, where I think we're exporting as much as we're importing at this point?
All right. We're looking at each other trying to figure out exactly what it is that you're trying to understand here. You're saying, at what utilization rates do we satisfy U.S. demand?
No, I'm trying to say, we've talked about product prices pricing off Brent. As we become more self-sufficient on the gasoline side, is there a risk that we potentially price off of LLS?
I see.
How do you see that playing out? We are producing about 9.5 million a day of gasoline today. We are exporting as much as we are importing.
Right. No, that is an interesting question. Scott Lively is with us today, and he is our Senior Vice President of Products, Supply, and Trading. Maybe he can just give you some thoughts on that.
Hey, Doug. How are you doing?
Good.
I guess the way that I think about it, I do not think about necessarily what price products have to price off of as a feedstock. I just think you have got prices that are around the globe, and we have to compete. Barrels either arb into those markets or they do not arb into those markets. You can say, are we priced against Brent? Are we priced against something else? We are running a lot more WTI-based crudes in the Gulf Coast, so that region sees more of a WTI-like margin. Whereas something on the East Coast of New York refineries, say, might price more against a West African, a Canadian that moves eastward. I think you are going to see pockets of differentiation based on what crude types people run.
I don't know that I necessarily think about it the way that you're trying to describe with pricing against Brent specifically or WTI specifically.
Yeah. We do talk about the incremental barrel into a refiner being a light, sweet, waterborne barrel, which would be a Brent-type barrel. As long as that's the incremental barrel, you're going to be pricing products off of Brent.
You have to get rid of all the gasoline production in those marginal refineries, which that's a lot of European and African and South American refineries. Those would have to be backed out and shut down before you're pricing the marginal barrel off of LLS or WTI. That's a significant amount. So those are the price setters. Now, yes, you're going to have times where U.S. low-quality gasoline in the winter is going to trade cheaper than it does in the summer. You always have seasonality. But the marginal barrel is still going to be priced out of the U.S., and that's going to set the prices.
Got it. And just how is the shift to a lighter crude slate, how is it impacting your gasoline yield? Are you seeing more gasoline out of the crude at this point?
This is Lane. No, we are pretty much still running, making almost within the noise of our system, the same amount of gasoline that we were. That is because of the flexibility of the system and how we can change endpoints and whether we make naphtha or gasoline, there are just a lot of optimization points that we still have.
Got it. Okay. My follow-up is on the West Coast. One of your peers recently announced a petrochem feedstock project. Are there any opportunities for projects like that within your portfolio? Also, if you can maybe just give us an update on the Benicia Rail project and where that stands right now.
Okay, this is Lane again. I will start with the Benicia Rail project. It is currently in the EIR is out during the comment period. We expect to close on that. The comment period will close September 15. We are still confident that we will get a permit. Of course, we will certainly, along with the city of Benicia, we will have to help answer all the questions that come out of the EIR.
On the first point, we are not looking at a lot of projects like the ones that you are talking about, and I think we are fairly skeptical that it would be tough to get permits, I think, at the end of the day. It would take a while to develop a project and get permits pushed through. It is quite an effort, as you can see with the crude by rail project on the West Coast.
Okay. Thanks, guys. Appreciate it.
Our next question comes from Roger Read from Wells Fargo.
Hey, hello. Good morning.
Morning, Roger.
Well, I guess I wanted to ask a little bit about the export market, what you see for volumes as we head into the fourth quarter, traditionally the strongest part of the year. If you could give us a recap of what you've seen in the diesel market year-to-date. If we looked at where the futures were a year ago versus what we realized, margins came in a lot lower, I am just speaking from a general or generic term. Can you walk us through what you're seeing out there in the diesel market, both domestically and in the export side, and whether or not that has any particular concerns as we look to the end of the year?
Hi, Roger. This is Scott again. Over the quarter, we exported 210 a day of diesel. I would say that that is pretty flat with where we were in 1Q. We still see continued global demand growth in that fuel, so we feel pretty positive about our ability to export, number one, and having those markets to export into, number two. You did have a little bit of a hangover effect of the mild winter that Europe had, which really particularly kept German stocks from drawing down. But those stocks are coming back more in line, and those guys look like they are going to need to be building going into the winter. So we fully expect that these export rates that we have had to continue out into 3Q and 4Q.
Okay. Something that got beat up on last year. We keep waiting for the EPA to give us the official numbers. Can you give us an idea of what you are seeing in the RINs market? We all know where the prices are, but what you have been doing about buying RINs, what your plans are if they make changes, presumably an upwards revision to the ethanol and other biofuel requirements, as has been rumored in the press, is we maybe get something next month, certainly, hopefully see something by the October-November period.
Well, we do, of course, keep our eye on the markets, and we are participants. I think it would probably put me at a competitive disadvantage if I said exactly what we were doing or what I planned on doing if we got an idea that they were actually going to raise to or above the blend wall as John and potentially Gina McCarthy have alluded to. I think we just have to sit back just like everyone else and wait for them to come out with their final decision on what the obligation is going to be. Hopefully, it is sooner rather than later, because obviously as the time horizon shrinks, that shrinks the time horizon for you to be able to go out there and procure the RINs that you are obligated to in arrears.
Yeah, I think the one thing that we do have going right now, though, is that there is probably as much ethanol being blended into the gasoline pool as could possibly be blended. As a result, the supply of RINs is there. So the economics are supporting it and the ethanol market in general is favorable to blend.
Right. Unfortunately, it's not always an economic-driven story where RINs are concerned in ethanol. I guess one final question, just as a follow-up on that. Have we heard anything about 2015 volumes or adjustments or any of that, or is the expectation that that may come out with the revised 2014 numbers?
I think that's what their expectation is that it comes out. It'd be interesting to have '14s and '15s come out. Well, it'd be interesting to just have 2015 come out in 2014. I would think that that hasn't been their past practice, but I don't think there's anything that we've heard through the grapevine that's given us any indication of what 2015 might be.
Okay. That's it for me. Thank you.
Our next question comes from Ed Westlake from Credit Suisse.
Good morning, everyone. Just on, I guess, a bigger picture strategic question. $1.5 billion of growth CapEx, of which around 50% going into logistics. You've got VLP out there, $2.6 billion. It's a relatively small MLP, but Valero's market cap has got a currency of its own, and obviously you can drop down assets into VLP over time. Just get a sense of the color of how big you see the organic suite of opportunities in logistics. Then maybe even any comments on using your equity to be more assertive, perhaps in the inorganic M&A space.
Okay. Well, I think we've stated before that we at Valero Energy have about $800 million of EBITDA that could be dropped to VLP. It's a very significant number. We completed the first drop here at the beginning of the third quarter on July 1st, I think it was, and that was a $154 million transaction. I think it's fair to expect, Ed, that we're working the subsequent drop transactions as we go forward. I think we recognize very clearly the value of the interrelationships of the two entities and the multiple pickup we get when we drop from Valero Energy down to VLP. We have a lot of projects, as you mentioned, that are in our current growth capital that we're working on, which will be assets that would add to the base of assets that can be dropped.
So really, the question that we're working through is the pace and the timing on those. We said we're going to grow VLP's distributions at 20%-plus a year. We still are intending to do that and so our drop schedule at a minimum would be able to accommodate that growth rate.
It just seems that there is a large opportunity for companies in your space who have the skills to be very large and successful infrastructure companies against the shale revolution to continue to shift assertively into that direction, given the relative multiples. So appreciate you might be going through the planning process now, but any thoughts about the direction you wanted to take the company?
Yeah. No, I think we are looking at a host of different logistics projects that are in development that would allow us to take advantage of what you have described. This great opportunity with the shale plays. But I do not have anything specifically to share with you right now.
Okay. Then maybe a question for Randy just on crude. Obviously LLS spiked last year, and then LLS collapsed in the fourth quarter. The spike is, let us hope it is history, and let us focus on the future where we could see perhaps a repeat of what we saw in the fourth quarter. A couple of things happened, seemed to happen last year. Obviously, we built gasoline for a hurricane that did not happen. There were lots of imports during the period. There was a rapid rise in inventories seasonally. And you folks and others in the industry were trying to reduce inventories for the usual year-end planning purposes. So, the question, you mentioned BridgeTex earlier, but is there anything different that you see happening this year, or do you think this is just a new seasonality that is going to set in for the Gulf Coast crude prices?
Yeah. Thanks for that. I think the biggest difference that I see is that crude runs are so much higher than what they have been as of late. Which we go through some seasonal turnarounds as we head into Q3, Q4. So my thoughts is that this thing looks back to normal. And as we are seeing September contract trade today, and we see LLS back down $2-$3 under Brent and ASCI $7 under Brent. So things are starting to look more normalized.
Yeah. Then maybe one tiny follow-on. Obviously in winter there is a difficulty pushing gasoline into the U.S. market, so you try and export the product into other markets. How are we in terms of the ability for you to say, maintenance aside, run at a higher utilization than you would have done in the past because of the ability to export more product and outcompete other refineries around the world? Any color there?
This is Scott again. As you have noted, those gasoline exports are seasonal. So we do export less in 2Q and tend to export more in 3Q and 4Q, especially as we have more availability and butane works itself back into the pool. I think that we are going to be cost advantaged, and we do see plenty of opportunities with growth in markets in Central America, South America, and in Mexico. We still see plenty of opportunity to put barrels down in those regions. So we still feel pretty good about our position to export and keep refinery rates high in our system as a result of those exports.
Hey, Ed, this is Lane. What I will comment, one last thing I will add was Scott just said, to your point, the U.S. Gulf Coast capacity is the most competitive capacity in the world. We can chase any market. We have low natural gas prices. We have an efficient labor force, and we are well positioned to maintain our assets as high utilization as we can find. We are not really up against any export logistics per se, so we do not really see that being a limit.
Thank you.
Our next question comes from Evan Calio from Morgan Stanley.
Hi. Good morning, guys. Maybe a more specific follow-up on Ed's question. I know you're not providing 2015 CapEx guidance at this point, and it was asked and answered. Yet, given you have the MLP and given midstream spending is an increased percentage of CapEx, how do MLP drop-downs relate to your consideration of CapEx? As it would appear to me that they're direct offsets in potential distributable cash flows. Follow-up. Thanks.
Well, Evan, that's the million-dollar question right there, isn't it?
Then the subsequent question to that is at what point in time do we start doing these logistics projects in VLP itself and not in Valero Energy for drop-down? We have a lot of good projects that we're looking at. We're trying to understand this whole notion around, do you look at a gross capital or a net capital number, to be quite honest with you. We have a very good feel for, I believe, what we're going to be spending on the refining side of the business. The wild card here is how much do we spend on the logistics side. I know you'd love to have a number, and there'll be a point where we give it to you, but I'm just not prepared to share it today.
Mm-hmm. Let me ask you a question. When you're evaluating midstream projects, and what ultimately goes into the EBITDA that you're characterizing as MLP-able EBITDA, do you consider the relative cap rate versus the MLP drop rate in the overall calculation of the IRR? For instance, they're very different, and more color there I think would help us. I'm just curious if that's an element of your evaluation of what to proceed on.
Yeah, I believe it is.
Mm-hmm. Maybe lastly then, for me, any update on the timing. I will keep it a midstream focus here, but any update on the timing of a potential methanol facility decision, and given Westlake Chemical Partners MLP IPO that uses a fixed rate structure versus variable and I think it is up 25% this morning, well through the range. How does a structure like that factor into that project consideration, which I know is under review? I will leave it at that. Thanks.
Okay. Well, honestly, we mentioned earlier that we continue to take a look at the project, and we are advancing the engineering. Lane and his team are trying to get our arms around exactly what the scope of the project is. I haven't had a chance yet to look at the transaction you mentioned to know the impact of it. We will take a look, and then perhaps we can loop back with you and have Ashley involved, and John.
Hey, Evan.
Sure.
Specifically, we are in phase II. We are doing all the sort of engineering, the major equipment, so we can nail down the cost estimate, and we will have that review in the fourth quarter. That is where we are in the process.
Okay, and that's the process prior to reaching FID. Is that accurate?
That's the process. I'm sorry, can you say that again?
Oh, I'm sorry. Is that the step after that phase is complete, is that when you then decide whether or not to go to a final investment decision?
That phase, we'll make a decision whether we feel so good about it that we'll go ahead and order long lead equipment which would expedite the project. That's really the critical decision that we'll make in the fourth quarter.
Great. All right, guys. Appreciate the information. Thanks.
Our next question comes from Allen Good from Morningstar.
Good morning, everyone. I wonder if I just come back to the export question and maybe get your longer-term outlook. There seems to be a lot of changes underfoot there with a lot of the refining capacity additions in Asia and the Middle East, potential improvement in European competitiveness given exports of maybe heavy crude over there or maybe even light crude. I think you have a bunch of your peers increasing exports as well. Can you just talk a little bit about your long-term outlook there and how you think the export market for U.S. refineries and Valero particularly will develop?
Allen, this is Scott again. I think that we are a bit ahead of the curve versus Europe, of course, on running those price-advantaged crudes. So, depending upon how long that takes to work its way in, you can still see more closures in Europe. Clearly, Europe is in a pinch point between the United States and mostly the U.S. and Russia. Like I said before, I still feel pretty good about our ability to export into these markets. A lot was made about Jubail coming online. You can see a sprinkling of cargoes go here and there, but so far, what we have seen is those cargoes from Jubail have mostly gone into internal demand and stayed on the east coast of Africa.
So going forward, there are more refineries that are going to come online, and by way of China, there's going to be more capacity in the U.S., but you should see that tempered with refinery closures, especially those ones that are marginal. As we said before, we still see the prospect of world demand growth for diesel.
Okay. Then just switching to the condensate export question. Just looking at your recent investor presentation, and you had some notes in there saying that at the end of the day, less condensate from the crude stream could ultimately be beneficial for Valero given some of the utilization rates and yield. Have you been able to quantify exactly what the loss on utilization or yield may have been over the past couple of years as those crude streams did get lighter with additional condensates?
This is Lane. I'm not sure I can give you exactly the loss. It hasn't been large. But what we do, we're very careful in terms of how we articulate the quality of those suppliers. We have deducts and maybe, I know we can't give you numbers, but we have standard deductions as API gravity goes up to try to offset any sort of financial penalty we might have. But as refiners, we personally would like to see the condensate out of the blended crude. But that's going to take a considerable infrastructure build-out to try to get the condensate in whatever location such that that can happen. So we're not necessarily opposed to condensate being segregated out of the crude streams. But to date, we haven't had any real major constraints based on these gravities that we certainly have.
The way we purchase our crude, we certainly attempt to offset it.
And just to follow up from an earlier comment regarding that, you are not interested in making any of those investments that would separate the two?
Well, again, our two crude units have the capacity to We have designed them for 50 API. We could certainly run them at a slightly reduced capacity to run even more. I think that is just the way we do things. We will compare condensate versus our alternative crude economics, and that will determine how much we are going to run. I think what I was trying to pose earlier was I think the industry and everybody making this stream is going to have to find a market. Whether it is slightly altered condensate, processed condensate, ME condensate, I am not sure. That is going to have to find a home somewhere. Our assessment was it was going to be the Far East, but we will certainly arb that relationship of condensate to crude out as it becomes more available.
Okay, great. Thank you.
Our next question comes from Faisel Khan from Citigroup.
Yeah. Hi, guys. Just a couple of small questions. First one, Ed, with the Cushing inventory reaching bottom, is there any sort of impact to McKee and Ardmore for you guys? Or do you have enough inventory within the refining gate to basically not be impacted by lower inventories at Cushing?
Faisel, this is Randy again. At McKee specifically, it is mostly a Midland market, which is flush with crude oil at the moment. Similarly, Ardmore also takes some barrels out of that market as well. So we are really not seeing any impact on supply or being able to source barrels.
Is it fair to say that because of where production is that you just do not need the inventory levels because you have got enough growth in production to offset the balancing impact of having storage in place in previous years?
Yeah, I think definitely, and the market is also backwardated, so there is no incentive for people to hold barrels there.
Okay. Yep, fair enough. Last question, actually two more questions. On the Corpus Christi dock, could that dock be used for condensate exports? Have you guys sort of looked at that?
Yes. This is Rich Lashway. We've looked at that, and it could be used for condensate.
Okay, fair enough. Last question is on getting barrels into Louisiana from Houston. Are you guys having any issues, or are you pretty much able to get as much crude from the western side of Houston into Louisiana? Any sort of constraints that you guys are seeing?
No, this is Randy again. No real constraints. I mean, it's moving via pipe on the Ho-Ho and barging and ships in through LOOP. All that's satisfying, and the rail's continuing to come down as well from the Bakken. Same change we saw with the pipe.
Great. Thanks a lot, guys. Appreciate the time.
Sure, Faisel.
Thanks, Faisel. Thanks, Sylvia. I think with that, we appreciate everyone calling in and those listening to our call today. If you have additional questions, please contact our IR department. Thank you.
Thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect.