Welcome to the Valero Energy Corporation reports 2013 third quarter results conference call. My name is Chris 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 would now like to turn the call over to your host, Ashley Smith. Ashley, you may begin.
Hey, thanks, Chris, and good morning. With me today are Bill Klesse, our Chairman and CEO; Joe Gorder, President and COO; Mike Ciskowski, our CFO; Gene Edwards, our Chief Development Officer; 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 me after the call. Before we get started, 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 have described in our filings with the SEC. Okay, as noted in the release, we reported third quarter 2013 earnings of $312 million, or $0.57 per share compared to adjusted earnings of $1.1 billion or $1.93 per share in the third quarter of 2012. Without the adjustments noted in the release, our reported earnings for the third quarter of 2012 were $674 million or $1.21 per share.
Operating income was $532 million compared to $1.3 billion of operating income in the third quarter of 2012 or $1.7 billion when adjusted for the items noted in the release. The decrease was mainly due to lower refining margins across all of our refining operating regions. Our third quarter 2013 refining throughput margin of $7.76 per barrel declined more than $5 per barrel versus the third quarter 2012 margin of $13.12 per barrel. The decrease was primarily due to significantly lower gasoline and lower diesel margins. For example, the Gulf Coast gasoline margin on Brent crude fell 57% from $9.33 per barrel in the third quarter of 2012 to $3.97 per barrel in the third quarter of 2013. While the Gulf Coast diesel margin dropped by $2.74 per barrel or 14% to $16.86 per barrel. Despite the decline, diesel margins were still quite strong in the third quarter of 2013.
To capture these strong margins, Valero increased its distillates production by 16% to 1,047,000 bpd , which also represented an increase in the percentage yield of distillates versus the third quarter of 2012. This favorable yield shift is mainly attributed to the operation of our new hydrocrackers at Port Arthur and St. Charles. Also contributing to the lower refining throughput margins were narrower discounts relative to Brent crude oil for light sweet, medium, and heavy sour crudes. For a light sweet crude example, the WTI discount fell sharply by $13.44 per barrel from $17.30 per barrel in the third quarter of 2012 to $3.86 per barrel in the third quarter of 2013.
Additionally, light sweet crude on the Gulf Coast was more expensive, with the premium for LLS crude relative to Brent higher by $0.66 per barrel in the third quarter of 2013 versus the third quarter of 2012. Heavy sour crude oil discounts also narrowed, with the Maya crude discount $1.68 per barrel smaller in the third quarter of 2013 compared to the third quarter of 2012. In the fourth quarter, crude oil discounts to Brent have improved versus the third quarter. WTI discounts have widened by $4.46 per barrel, and LLS has improved by $6.46 per barrel, going from a premium to a discount versus Brent. Also, the Maya heavy sour discount has widened by $6.14 per barrel since the third quarter.
Refining throughput margins were also negatively impacted in the third quarter of 2013 by the higher cost of Renewable Identification Numbers, or RINs, needed to comply with the U.S. Federal Renewable Fuel Standard. The reported compliance costs were $185 million in the third quarter of 2013 versus $70 million in the third quarter of 2012. Given the recent drop in RINs prices following news of the EPA's potentially favorable revisions to the 2014 Renewable Volume Obligation, we have reduced our estimated costs for complying with the Renewable Fuel Standard to a range of $500 million - $600 million for the full year 2013. Our third quarter 2013 refining throughput volumes averaged 2.8 MMbpd for an increase of 172,000 bpd from the third quarter of 2012. Refining throughput volumes were higher due to fewer unplanned refinery maintenance events and less weather-related downtime.
You may recall that Hurricane Isaac negatively impacted operating rates at our Louisiana refineries in the third quarter of 2012. Refining cash operating expenses in the third quarter of 2013 were $3.74 per barrel, similar to the third quarter of 2012. Although natural gas prices increased year-over-year, our higher throughput volumes in the third quarter of 2013 favorably offset the higher energy cost per barrel. Our ethanol segment reported operating income of $113 million in the third quarter of 2013, an increase of $186 million from the third quarter of 2012, mainly due to higher gross margins per gallon and higher production volumes. Production averaged 3.4 MMgpd in the third quarter of 2013, for an increase of 992,000 gpd compared to the third quarter of 2012. We increased our ethanol production to capture the higher gross margins available to us.
In the third quarter of 2013, general and administrative expenses, excluding corporate depreciation, were $170 million. Net interest expense was $102 million, and total depreciation and amortization expense was $448 million. The effective tax rate was 27.5%, which was lower than guidance primarily due to an adjustment in deferred taxes as a result of a U.K. tax law change. Regarding cash flows in the third quarter of 2013, capital expenditures were $557 million, including $78 million for turnarounds and catalysts. We returned $151 million in cash to our stockholders by paying $122 million in dividends and by purchasing approximately 800,000 shares of Valero common stock for $29 million. We ended the third quarter with approximately $3 billion remaining under our stock purchase authorization. Subsequent to the third quarter, we bought approximately 2.6 million shares of Valero common stock for approximately $90 million.
This brings our total year-to-date stock purchases to almost 17 million shares for a total of $675 million. With respect to our balance sheet at the end of the quarter, cash was $1.9 billion. Total debt was $6.6 billion. Our debt to capitalization ratio net of cash was 20.2%, and we had over $5 billion of available liquidity in addition to cash. We maintain our guidance for capital expenditures, including turnaround and catalysts, at approximately $2.85 billion for full year 2013 and approximately $3 billion for 2014. For modeling our fourth quarter operations, you should expect refinery throughput volumes to fall within the following ranges: U.S. Gulf Coast at 1.45 MMbpd - 1.5 MMbpd, U.S. Mid-Continent at 420,000 bpd- 440,000 bpd , U.S. West Coast at 245,000 bpd- 255,000 bpd , and North Atlantic at 450,000 bpd- 470,000 bpd .
We expect refining cash operating expenses in the fourth quarter to be around $4 per barrel. For our ethanol operations in the fourth quarter, we expect total production volumes of 3.5 MMgpd, and operating expenses should average $0.38 per gallon, which includes $0.04 per gallon for non-cash costs such as depreciation and amortization. Also in the fourth quarter, we expect G&A expense, excluding depreciation, to be around $175 million, and net interest expense should be about $100 million. Total depreciation and amortization expense in the fourth quarter should be around $425 million. Our effective tax rate in the fourth quarter should be approximately 37%.
Okay, Chris, we have concluded our opening remarks. We will now open the call to questions.
Thank you.
During this segment. Hold on one sec, Chris.
All right.
We just want to point out that we request that our callers limit each turn in the queue to two questions. They can rejoin the queue with additional questions after that initial volley. Okay, Chris.
Thank you. We will now begin the question-and-answer session. If you have a question, please press star then one on your touch-tone phone. If you wish to be removed from the queue, please press the pound sign or the hash key. There will be a delay before the first question is announced. 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. Standing by for question. Our first question comes from Doug Leggate from Bank of America. Doug, your line is open.
Thanks. Good morning, everybody. I'm going to take my full quota of two, if I may. One specific for Valero and one industry, if I may. Actually, I don't know if I missed this in your remarks, but can you quantify, please, how the hydrocrackers contributed to EBITDA in the quarter? If you could put it in the context of the guidance that you had given us for your expected run rate when these projects were underwa? I've got a follow-up on the industry, please.
Yeah, Doug, the St. Charles hydrocracker came up in July of the third quarter and pretty much hit full run rates by mid-August. Both hydrocrackers performed very well, particularly given relative to expectations in this margin environment. Specific EBITDA performance, we're not going to provide on these units or pretty much any other unit going forward. We've got hundreds of units throughout our refineries, and it's just too tough to reconcile and manage expectations and to audit each of those. Those units have performed well.
But in the context, you did give us specific guidance for what you thought they would contribute. Can you at least frame the contribution relative to that former guidance?
Yeah. Given the margin environment, because the guidance was in terms of a margin set, under certain margin sets, they performed within guidance, within expectations of that guidance.
Okay, thanks. My industry question, I am going to leave someone else to talk about RINs, but my issue is on utilization rates for the industry. The context I really want to set here is that we have obviously still got very low feedstock prices, particularly natural gas, but we have also got some refineries that have expanded and refineries that have been given something of a reprieve on the East Coast. What I am curious about is your thoughts on overall gasoline capacity in the U.S. against a weak demand backdrop, and whether or not you think the weakness we saw in margins in the third quarter could be something of a new dynamic that might have us reset lower expectations for mid-cycle margins? I know it is a bit of a broad question, but just curious on your thoughts on that. Thanks.
Okay. Doug, this is Gene. In general, I think the margins in the third quarter were getting squeezed and I think you probably saw some economic run cuts towards the end of the quarter in September primarily, but you also had turnarounds coming into play. Then, moving forward in the fourth quarter, I think you really got to look at what type of crude you are running. If you are running imported sweet crude, your margins are pretty bad right now. But on domestic crude with the differentials blowing out, I think you are seeing better margins in the U.S. I think you will see utilization rates in the U.S. higher versus Europe going forward because of the crude advantage and the natural gas advantage.
How does that impact your thinking then about incremental use of cash on a go-forward basis if the margin environment is going to be more challenging? I am thinking about your decision to move forward with another step-up in your spending.
Well, I think the margin environment in the U.S. is going to be better. It is going to be squeezed in Europe because of, again, the crude advantage. Where you have advantaged crude, you are going to have better than average worldwide margins. Where you do not have advantaged crude, you are probably going to be a little bit below mid-cycle.
This is Klesse. The step up in our spending, let's get it in context from the guidance I've given, is about $500 million. This is guidance. The market is giving us opportunities in the sense of increased crude oil production that's at discounts. The light sweet crude is at a discount to Brent and widening. We have the NGLs that are clearly coming to the entire industry, whether it's petrochemicals or refining. Then you look at what we're doing. We're spending a lot of money on logistics because of the part of your question actually dealt with exports, let's be honest, and that is a huge part of the future for the refining. So maybe at the most, we're talking about guidance of a $500 million , and frankly, we've disclosed this in our last presentation, how it's split out.
We gave that guidance. It shows a lot of its logistics and $1.5 billion is economic. But we're still in this period of time where we're scoping these projects. But in our endeavor to keep you all informed, we told you guys what we were looking at. That's how we justify. But clearly in the view of this industry in the U.S., as Gene just was speaking, you have to be able to export. Operating rate will be higher because we think that the U.S. industry, certainly between the Appalachian Mountains and the Rocky Mountains, is extremely competitive in the world environment.
Appreciate the answers, guys. Thank you.
Our next question comes from Jeff Dietert from Simmons & Company. Jeff, your line is open.
Hey, Jeff.
Yes.
All right. We are ready to receive. You are up.
All right. Very good. With LLS and Mars prices being soft here early in the fourth quarter, there is a great advantage for Valero on the Gulf Coast and also a strong disincentive to import crude into the Gulf Coast. Could you talk about how these discounted light and medium prices in the Gulf Coast are impacting your crude imports, and how you think it might impact the industry as a whole imports into the Gulf Coast?
Well, Jeff, this is Joe. Obviously, they have backed off our waterborne light sweet imports. We basically were there months ago. The only time that we brought in any light sweet waterborne imports into the Gulf Coast is when there were distressed cargos out there that we could buy and take advantage of operating with. This is not a new phenomenon here. It is just a continuation. If we talk specifically about the light sweets, we have got production, and it is a fundamental issue. We have got production way up 7.9 MMbpd . Past three inventories are now at 194 MMbbl , which is 10 MMbbl above last year, and it is at five-year highs. Although we have seen draws in Cushing that have brought them down, we have seen builds over the last couple of weeks.
But essentially what you've got is supply of domestic light sweet crude exceeding demand in the Mid-Continent. That crude with all the pipelines that we've been talking about for some time now flowing to the U.S. Gulf Coast, and it's creating length down there. It is pressuring those margins, and we expect that's going to continue for some time. Medium sour has got to compete for space in the refinery. The Mid-Continent production pushing down there is pressuring Mars, and that's where it is today. Then as Ho-Ho comes on, and you're going to be able to move more Mid-Continent barrels over to the Louisiana markets, I think you're going to see even more pressure on it. So I think we're in for an extended period of discount of light sweet crude on the Gulf Coast, as well as solid medium sour discounts.
Then you didn't ask about heavy sour, but it all ties in to the same issue. You've got heavy sour discounts looking very attractive right now. A lot of it has to do with fuel oil weakness because we've got weak Asian demand. Then, you've got more supply of fuel oil coming into the market with the Middle Eastern and Russian production increases. So the inventories of fuel oil are way up. You got WTS, which we benefited on discounts improving lately because of refinery outages. Then you had Longhorn barrels now that are coming to the Gulf that in the past quarter were headed to the Cushing market. So you're seeing more medium sour head to the Gulf, but the WTS discounts are coming off a bit. You got the K-factor. You've got very solid discounts on your heavy sours, on your medium sours, and on your light sweets.
And we're starting to see those barrels run through the plants in October, and we're seeing much more significant discounts headed for us in November. So we're very optimistic about where the crude discounts are. Long answer.
Yeah. Secondly, you guys have been successful moving Eagle Ford barrels out of Corpus Christi to Quebec. I believe you are permitted to move 100,000 bpd. That arbitrage is wide open. Eastern Canada imports about 600,000 bpd of light crude. Will more crude move from Corpus, Houston, St. James, up to Eastern Canada, given the arbitrage where they are today? Could you discuss that and maybe some of the constraining factors?
Well, Jeff, it is. Yes. You will see more of the domestic crude moving up to Canada. I think, I do not know, Gene, I do not know if you know, but I do not know how much they can feasibly run up there. I can tell you that for us, we are running Eagle Ford crude in the Quebec City refinery today, and we got WTI crude headed that direction. We are doing what we can to go ahead and move barrels up there. We are learning how to run these crudes at Quebec City as we go. You want to speak to the-
Well, some of the other refineries up there, they are predominantly medium sour type refineries. I imagine they have some capability to run sweet, but I just do not know what. I am sure they are running their LP models, and they are trying to optimize that as well.
Thanks, Joe. Thanks, Gene.
Thanks, Jeff.
Our next question comes from Robert Kessler of Tudor, Pickering, Holt & Co. Robert, your line is open.
Good morning, guys. I wanted to see if we could touch a little bit more on this U.S. versus Europe dynamic. Looking, for example, at your North Atlantic margin contribution or operating income, I am wondering if you could split out that income in the third quarter between, say, Quebec City on this side of the pond and Pembroke on the other side?
Hey, Robert. We are not going to break out those details. We will report by region, but we are not going to give results by refinery.
Any color you could provide on the market? Your volume guidance for the North Atlantic region for the fourth quarter would imply you are still going to keep the European side running. Where are you relative to cash cost on a crack spread today at that plant? Can you give some color there?
We do not have any guidance for you on that either.
I think we will just stick with the general stuff that you read in the industry, and that is, until this dip the other day in Brent pricing, it was reported there were a lot of cutbacks in throughput rates in Europe. Then there was a cutback, and it says that in the industry data, everyone says there is some profit in Europe. Our system is a little unique in the sense is we do try to run an Atlantic basin strategy, and we do have marketing in the U.K. and Ireland. We will leave it at that.
Okay. I guess my second question then. Third quarter exports for you of gasoline and diesel out of the U.S.?
Yeah, we exported 193,000 bpd of diesel and 91,000 bpd of gasoline. Those numbers are looking larger for the fourth quarter so far. We continue to have low inventories. We got global demand growth, and we got very consistent demand out of Latin America. We're seeing it industry-wide and from Valero's perspective. Right now, Rob, the diesel arbitrage to Europe is open, ignoring the RIN. That's the first time it's been like this here in a while. We're very optimistic about the ongoing pull of products out of the Gulf to Europe and Latin America.
Thanks for that. I think your capacity to export on the diesel side is 280,000 bpd, moving to 400,000 bpd or 425,000 bpd. When do you move up to that 400,000+ bpd?
Well, we've got all these capital projects that Bill referred to earlier, the logistics projects. It'll be over the next several years. I would tell you, today we're probably at maybe a capacity of about 325,000 bpd for distillate.
Okay. Thanks so much.
Our next question comes from Roger Read from Wells Fargo. Roger, your line is open.
Yep, good morning.
Hey, good morning, Roger.
I guess taking on some of the other questions that have been asked, we look at the light heavy spread along the Gulf Coast, and this came up on the last call. You need, I believe, an 8% discount between the lights and the heavy sours. If we look at LLS, we've stayed in that line. If we look at Brent, it's clearly blown out quite considerably. What is, at this point, given that there aren't much in the way of light barrels being imported to the Gulf Coast, which one is the better indicator? How do you work around that if LLS is the barrel, but I guess you would say the refined products are being priced off of Brent still?
Yeah. We look at Brent as being the benchmark. This is Gene again, Roger. Brent as being the benchmark, then you got two components to your margin. You got your feedstock discounts. We are really not running any Brent, obviously. Brent today, we have a LLS discount that is in the $7 range, and then you add your crack to it. Our medium sours are probably more in the $14 range. You think about a medium sour to Brent, $14-$15, but to LLS, it is $7-$8. It is very good numbers, which is what we have been saying all along. A lot of people were concerned that LLS would get cheap, and it would sell cheaper than medium sours. It clearly is not happening. We are seeing pressure on the medium sours as well.
As you start to move forward on moving more barrels from the Texas coast to, say, Eastern Canada or wherever else they may eventually go, how long before we would see an impact then on Gulf Coast prices having to come up, obviously reflect whatever the transportation costs are, but come up and meet more of a global price issue? Can we move enough barrels to Canada? Is there an appetite, let us just say, from the Gulf Coast to get the permits from the Department of Commerce to make that happen?
Right. Well, first of all, the arbitrage, like we talked about earlier, to Canada is wide open for our facility. We mentioned too that the competitors up there sometimes are medium sour, so they are going to be looking at light sweet from the Gulf Coast. But they are still going to be looking at medium sours, and medium sours are starting to be discounted on an international basis to compete in the Gulf Coast. They will have to optimize based on that. You also see the arbitrage at current pricing that you could use a U.S. flag vessel and take crude up to the East Coast refineries, but there is limited amounts of these U.S. flag vessels available. So right now, I am not sure it does get solved in the short term. I think all these barrels are competing against each other.
There is more crude than the market needs in the U.S. But there are market pressures to try to solve them, but there are limitations on all of those. On top of that, you got more and more domestic suite being produced every day. The Bakken numbers, the Eagle Ford numbers, the Permian numbers just keep ramping up month after month. So I am not sure exactly how the situation gets solved right now.
Well, Roger, and just to add to Gene's point, we've got the production coming on stream, but it was just this last week that Longhorn started running now at higher rates. I think they are up to 225,000 bpd. They were running between 90,000 bpd and 170,000 bpd, I think, for some period of time. When Marketlink comes on stream later this year, you are going to have another significant slug of these barrels moving out of the Midcontinent into the Gulf. The pressure continues to build, as Gene said, higher production, more takeaway capacity out of the Midcontinent to the Gulf. It is just going to continue to build.
Obviously, the rail economics from the Bakken area to the coast is wide open as well. There is a lot of market pressures to try to correct this. The big question is: Is there enough of it to really solve it? We don't think there is right now.
Thank you.
Our next question comes from Sam Margolin from Cowen and Company. Sam, your line is open.
Good morning. I was hoping to touch on the light oil units you guys are building in the Gulf Coast. I know it is pretty far out, but if there is anything you could share about current pricing, feedstock replacement, differentials that are maybe off benchmark right now that can help us get a better picture of the economics once those start running and help us model it out?
Sam, the premise behind these, there are a couple of toppers at specific units that leverage some other infrastructure at those plants. We are not just doing crude expansions. We are doing it to fill up some downstream units that are currently importing feedstocks. That is basically it, but it is too soon to give out details to model it specifically. We are still evaluating the cases, evaluating the investment needed and the various margins that are going to drive it. We think they look good, but still evaluating. Too soon to get into model specifics.
Okay. Well, maybe this is a little more near term. In the past, you have talked about the West Coast. Those assets have been up for review a couple of times. It was obviously a really tough quarter out there this past period. I was wondering if you could shed any light on the way you are thinking about that asset base now. I do not know, maybe the MLP changes things in terms of what is out there to drop down and remonetize? You might not want to lose it, but what is your latest thinking on that region?
Well, it is obvious that we are not making a lot of income or cash flow on the West Coast, and so we are looking at our options and continue to look at them from improved operations. Benicia this year has not run very well for the whole year. Working there, we work on our cost structure. I think you know we have a rail facility planned at Benicia to run this sweet crudes, domestic crudes. But now we are stuck into an environmental review, or I guess it is an assessment. So now that project slipped on us, where we thought we would have it done at the end of this year, it is probably the end of next year. So we are doing a lot of different things to try to improve our situation.
But when you get all said and done with that conversation, PADD 5, if we broaden the focus, is just long refining capacity relative to product demand, which has not come close to recovering from the pre-recession period. We just keep looking at all of the above.
Okay. I think last year sort of demonstrated that that region goes from long to short very quickly. Is there any resistance as far as rationalizing capacity there, or it is all up to you?
I suppose you mean resistance being from politicians or somebody?
Yeah.
Oh, well, I am sure there would be resistance.
Okay.
You saw what happened with Tesoro in Hawaii.
Yeah.
But the truth is, the whole PADD 5 seems to be one or two refineries long. So when one or two refineries go down, you make a lot of money.
All right. Well, thanks for the time.
Sure Sam.
Then our next question comes from Paul Cheng from Barclays. Paul, your line is open.
Hey, gentlemen. Good morning.
Morning, Paul.
Two questions. Maybe this is for Gene. Gene, have you railed in any Bakken and WCS into any part of your system in the third quarter, and how did that look in the fourth quarter?
Joe will answer you, Paul.
Yeah, Paul. Yeah, absolutely. We have railed Bakken in. We've railed heavy sour crudes in also. We've got bitumen that has gone into St. Charles, and we're probably doing 20 a day of that. The Bakken is actually, I would tell you all of Memphis' volume is theoretically railed Bakken. It goes down to the U.S. Gulf Coast to St. James, and then we bring it back up on Capline, but it's railed down there. At Quebec, we started up the rail loading facility, and that's going very well.
You must be printing money because the Brent to Bakken is like $25 discount on the wellhead. How much is the total Bakken that you are railing? Any rough estimate in the fourth quarter?
Let me see. I will tell you, in the third quarter, it was 130,000 bpd , and that is primarily Memphis volumes. It will increase. I do not have the number of Bakken versus other crudes that we are going to be running in Quebec. Maybe another 40,000 bpd or 50,000 bpd on top of that.
Call it 200,000 bpd?
Sure. 180,000 bpd- 200,000 bpd.
You must be extremely profitable on those. Joe, it looked like the LLS delivery price is even lower than the spot at this point. So when people looking at in Bloomberg, say, LLS 6321, they actually is underestimating the margin. Is it?
Yeah, it is very close, Paul, but it might be a buck.
Then a final one. When I am looking at that sequentially from the third to the fourth quarter with the lower RIN price and look like better wholesale margin. So far, quarter-to-date, is it safe for us to assume your margin capture rate in your system is actually better in the fourth quarter compared to the third quarter?
Yeah. You are talking about on just our income, Paul, specifically?
On your gross margin that compared to the benchmark you guys provide in your website.
Yeah.
Should we assume that the third quarter looked like may have hit the low point, at least in the near term, and fourth quarter look like it is much better?
Right. That is true. The lag effect in our crude pricing is going to give us better discounts going into the fourth quarter, and it is going to help our economics. They are significantly better. We saw a little bit of it in October, but we are seeing a lot more of it in November.
Yeah. The point we are trying to make here, Paul, is you are asking, obviously, for a little guidance here. What we would tell you is that October generally is not that much better than September. Because of the lag in the system, for all us guys in this business, November and December look a lot better. On a gross margin basis, fourth quarter does look better than third quarter, but it is lag. It is a lag.
Perfect. Joe, when I am looking at your guidance, say, the RIN cost for the full year at $500 million-$600 million.
Right.
First quarter, you are 75,000 bpd, second quarter, 125,000 bpd third quarter, 185,000 bpd. You are suggesting that the fourth quarter is still at $115 million - $215 million, given that the RIN cost seems like drop down into the $0.30 compared to the $0.80, $0.85 in the second and third quarter. Are we missing something, or that is just that you are being conservative?
Well, I will tell you, the numbers that I have do not really sync up with the numbers that you just stated. I would tell you that the number that we have got to achieve compliance is probably a lower number than you have.
Paul, this is Mike. The year-to-date number through September is $439 million. So to get to the $500 million the bottom end of the range, you are looking at $60 million bucks.
I see. Perfect. Thank you.
Our next question comes from Blake Fernandez from Howard Weil. Blake, your line is open.
Guys, good morning. Question for you on McKee. I had seen some press reports suggesting there was a rupture at the crude unit. Obviously, Ashley has already given us throughput guidance for Q4. I am just trying to confirm that there is no major issue or anything that we need to be aware of there.
Hey, this is Lane Riggs. Yeah, in fact, the crude is back in today. We are going to be at full rates in about another two days. So in terms of the forward guidance on throughputs, Ashley's numbers are fine.
Okay, good deal.
I want to be clear, it wasn't per se a rupture. We were doing maintenance work, and we had a stopple, and the stopple didn't hold, and that's what happened. We didn't have a piece of pipe just break or something. We were doing maintenance work, which we're looking at our procedures in tremendous detail here as to how that could have happened.
Okay, got it. Thanks, Bill. The second question was on the unloading facility at Quebec. I'm trying to see if we can help quantify maybe the potential shift in feedstock. Do you have any kind of clarity you could provide or ways to think about maybe the cost of transporting up there via rail and maybe the discounts you're getting. Any color you could provide would be helpful. Thanks.
All right. Blake, this is Joe. You know I can't tell you everything you want to know here, right. But I'll tell you from a volumetric perspective, the rail facility was available to us in August. In September, we started ramping up volumes a bit. I would tell you, we might've run 15 a day of rail crude in September. By later this year, we'll be running 50 a day of rail crude. We've got it set up now so we can take 100 car strings, which is a block, which basically gives you a unit train operation, which is the best economics that we can achieve on this. You know what the rail cost is to the East Coast out of these producing regions in western Canada, and the rail cost into Quebec is cheaper.
I would tell you, if you wanted to use $10-$12 a barrel, you could probably use that. You can see what the discounts are for Bakken and the Syncrude over in that market and come up with what the benefit might look like right now. In addition to the rail crudes we got going in there, though we also then have the waterborne crudes. I said earlier we're moving WTI. We're actually moving Eagle Ford and Bakken crudes up there. We expect that we'll be doing somewhere around 50 a day by the end of the year. So 45-50 a day. We're getting a lot of North American crude into the Quebec refinery.
Then we had a call yesterday with our Canadian guys and discussed the status of Line 9, and it looks like everything's going well and the project's progressing. We're encouraged by the fact that some of the reviews, for example, in Ontario, they were going to review the project on an independent basis. They've canceled that review. Everybody seems to be getting more comfortable with that pipe, and at that point in time, when that line comes out, we'll be running all North American crude to Quebec. We'll back out the foreign barrels.
That's perfect.
Blake, this is Klesse. This even goes back to Paul's question, and maybe I'm trying to manage expectations a little here. There is no question running domestic crude oil or North American crude oil is very advantageous. We give up some of that by the cost, but clearly shipping from the Gulf Coast to Canada is a couple bucks. The rail, it's in our handout, we have all those rates in there. All this is extremely profitable. On the other side, though, the gasoline crack still isn't really that good. Actually, it's crummy. Butanes, we make a lot of other stuff besides just diesel and gasoline and jet, and a lot of those markets are weak. Yes, the crude is clearly an advantage, but some of the other products are not contributing here.
I'm just trying to manage it because I can see with your question, Paul's question. Yeah, it's better than it was in the third quarter, but there are things that are negative.
Got it. Okay. Thanks for the color, guys. Appreciate it.
Our next question comes from Ed Westlake from Credit Suisse. Ed, your line is open.
Okay, yes. Good morning. Just coming back to the crude side. Obviously, great conditions down in the Gulf at the moment. Are you seeing from, say, some of the medium importers, sort of 1.5 MMbpd comes into the Gulf, and I appreciate you're more heavy, but are you seeing some of those medium imports? I'm thinking mainly the Middle East start to try and redirect the cargoes. How do you think that's going to pan out with the growing supply that's coming down the pipes?
Ed, I don't know. I don't know that we've seen Middle Eastern cargoes redirected. I know we haven't.
I haven't. They really price those Argus of- Yeah the ASCI index, which is a common medium power. They're pricing based on U.S. basis. Do they have better opportunities to move them into Asia? We haven't really-
Well, historically they have, right?
They always have. Yeah.
Yeah.
There is still a lot of barrels that need to clear to the Gulf Coast to clear those markets.
I guess just thinking about the $8 spread at the moment between LLS, it is the only decent benchmark we have. How has that changed your thinking about the industry expectations, say, a year ago of sort of $2-$5 per barrel as being the right kind of discount to encourage those to move to other markets?
Well, Ed, this is Gene again. When a market gets oversupplied, it is hard to really pick the right number. Why did WTI and Brent go to $25 last year? When it is oversupplied, $2-$5, to me, fundamentally is no different than $8. It is just a matter of where the market shakes out. The market is clearly long. It is hard to say what the right number is.
We think, we still stay to our position that things will eventually evolve to transportation costs. You have to have what Gene just said. You have to have adequate ways of adequate capacity in the transportation area. Until you get that, then what Gene said, what is the number? Yes, are we a little surprised it has blown out this much? Of course, we are. I think for long term, it does not really change our thinking.
Switching to that idea of transport, obviously $1.5 billion, I think, is your CapEx for strategic, and obviously a chunk of that's methanol, but a chunk of that is going to be on the logistics. Could you give us an update on what type of, I'm thinking to make it simple, EV, EBITDA that you're investing at. Obviously, we know the MLPs trade at high multiples, but what sort of return do you think you're getting on your organic logistic investments?
Yeah, Ed, so this is Ashley. We don't have returns for each project. You can slice these different ways because, does the refinery get the benefit or does the rail car get the benefit? There's a lot of ways you can look at it. How will that return then go in. If that asset was going to go into a logistics partnership, where do you put the return? Directionally, they're all beneficial. Most of them are pretty high return projects, especially because they're bringing advantage crude to refineries. But giving specific returns by each dock, by each rail car, we're not going to provide.
Yeah, I'm just fishing to try and help us get an estimate of how much logistics EBITDA you'll have down the road after you've spent a lot of this capital.
It's a fair question. Part of the problem is what Ashley said. The other piece of it is we're very convinced the future in this business, just strategically, is you got to be able to move stuff around and you got to be able to load ships. Some of these projects, like our dock at Corpus Christi, we just say we got to have it. Docks at St. Charles, building a new dock over there, maybe. The stuff at Port Arthur. We're just saying this is the way the future has to be, just like some of our competitors are saying the same thing. With the MLP, obviously, you have a cost structure that permits them to be dropped at a reasonable rate. So it all fits together, we think, as a management team very well.
But it is hard for us to tell you, as Ashley said, this project yields that, this project yields that.
M aybe one—
They are all going to be above cost of capital, and they are all going to fit very nicely in this portfolio.
Maybe one final thing then. Is there a constraint on moving even faster in terms of growing these logistics or spending more money in that area?
I don't see us doing that. I guess it's just our capability to do things, and we think we're doing the right projects now that work on our strategy. That's not. We've given you guidance for next year, and that's the guidance we're sticking.
Right. Okay, thanks very much.
Our next question comes from Doug Terreson from ISI Group. Doug, your line is open.
Good morning, everybody.
Morning, Doug.
I have a couple of questions. First, the capture rate seemed a little bit low in relation to Q3 of years past. I think we talked about how it's going to rebound, but just wanted to see if there were any color you could provide into those results. Second, this morning, BP highlighted normal seasonal factors, and I think growth in competitive capacity is the driver of weakness in global gross margins recently, meaning exclusive of the positive feed stock points that Ashley, Gene, and Joe made about Valero's system in the U.S. This might be a question for Bill, but I just wanted to see whether you think the recent weakness in global margins is seasonal, cyclical, or both, and also whether or not there are any other issues that may help to explain some of these recent global trends.
Hey, Doug, let me start with your capture rate stuff.
Okay.
I'll give a couple of generalities because everyone models differently and has got different assumptions, so it's hard to reconcile subjective stuff like that on an earnings call.
Sure.
Key factors that are not in a typical indicator are RINs cost. Not everyone captures butanes and naphthas and things like that. Those had wild depressed swings in the third quarter that impacted what you would normally see in prior periods when those were not a factor. Those are probably the biggest ones, probably across the entire industry.
Okay.
Any other detail, we would have to do it one-on-one because that—
That is fine, actually.
—on your model.
Yep.
Doug, this is Gene. On the global margins, I guess the way we view it is with the new capacity coming on in Saudi and some of the Chinese refineries, there is going to be pressure on certain refineries in the world to make room for that. I think that includes some of the Asian refineries, in Japan and Korea and Australia. Some of those have been rationalizing. On Europe, because Europe's going to have to make room for not only the U.S. exports, but the new Saudi refinery exports. Europe's only advantage really is distillate demand, and that can be supplied cheaper from other sources. So we think global margins are off a little bit. If you look at past 2011, 2012 margins, 2013 margins are a little weak or are definitely weaker and it's moving in the fourth quarter.
I guess we say that pattern continues next year. Now, I don't think margins are going to be so bad as they are right now in the fourth quarter, where every refinery in Europe loses money. That's too far, right? So it's somewhere you'll get some bounce back, but I think you'll see weaker margins in Europe than we have over the last couple of years.
Okay, Gene. Thanks a lot.
Our next question comes from Paul Sankey from Deutsche Bank. Paul, your line is open.
Good morning, all. You gave us the product export numbers which, Bill, you said in the past is really the key to the whole bull case here, given the weakness of U.S. demand. I was interested that you've got more capacity to export seemingly, or correct me if you don't. But given the weakness of, as you said, crummy gasoline cracks, I was wondering why there wasn't more export, if you like, or what the constraint was on exports? I understand you also said that net exports are up this quarter.
Yeah. This is Joe, Paul. Economics dictate a lot of our export volume. We take into consideration not only the margin that we can get on the barrel that's going out, but also then the RIN effect. Clearly, in the third quarter, that would have encouraged exports to be as aggressive as possible. The distillate export volume we had was very much what we expect. It is going up significantly in October. Again, with the arbitrage being open to Europe, we're going to see that be much stronger, I think, in the fourth quarter. The gasoline exports, we moved most of that volume out of our Corpus Christi refinery, and a lot of it's termed up. It went into Mexico, and some of it went into South America.
But that is part of our business that as we look at it going forward, we're very focused on expanding. Strategically, we have initiatives that we have underway to try to create additional opportunities for ourself to move those barrels out. But it wasn't there yet today. Even though we've got capacity to export, you've got to have a market to move it into, and there's got to be demand for it. We moved as much as we could economically move versus the alternative.
Yeah. It's all versus the alternative, Paul. After net backs and different grades in those different markets. We're constantly optimizing around that.
But I guess what you are saying is that diesel is great, right? You can export it with the allowance for RINs to Europe, and that is maxed out. On gasoline, the alternative is a competitor, essentially? Is that what you are saying? That has a lower price than you?
I think what we are going to say to you is you are optimizing the refinery to make distillates. Even our distillates are up. It is not necessarily that we are sparing the cats, but if you look at our operating rates, our operating rates in the whole industry have been, with the turnarounds that Gene mentioned earlier, have been very good. So operating rates are okay. They have come down some on crude units, but generally they are okay. So we are making the product slate that maximizes our profit on the back end of the refinery. Then we have this gasoline, we place it in the domestic market, and some has to go out of the country. As Joe said, some of them are refinery at Corpus Christi. But we are not necessarily sparing gasoline units, but the gasoline margin is poor, so we are optimizing to jet diesel on those streams.
Yeah, I get that and it is—
I know you do.
I think to go back to what Joe said, just to re-clarify it. Can you just go over again why there's not more gasoline export, Joe? Sorry, I know you kind of answered, but if you could just totally clarify it for me.
Where would the next 50,000 bbl of gasoline go at? Would it be a loss or would it be a marginal economics? That's basically the question.
That would be set by the bid from a buyer abroad.
That's right.
And net backs and shipping and grades. All that.
Yeah. Paul, remember, I think we had shipping rates that were very high during the third quarter. I think we were $0.115 a gallon versus $0.075. $0.07 today. There are a lot of factors that come into play, but again, it is economics.
Well, let me. We had a little side conversation here. We obviously have export capability, so then it turns into either a quality or the refinery economics. As we run our economics in the refinery, basically, we are always in balance, right? Because you adjust operating rate. We did not find it attractive to make more gasoline. It is because of the economics. If the economics for gasoline had been really strong, we would have figured out how to make more gasoline.
Yeah. Just to clarify you—
That is the answer. The economics in the refinery didn't drive us to make more gasoline. The marketing groups dispose of it to the best way they can.
Yeah, I get it. Did you say that your export capacity is now 350,000? We were running with a 280,000 number, and if I add the 193,000 bpd distillate plus the 91,000 bpd gasoline, I get obviously to 284,000 bpd. But then I think you said your capacity to export is actually 350,000 bpd, or am I wrong?
All right. Gasoline, we would say that our gasoline export capabilities, logistically, is 225,000 bpd and logistically on diesel is 325,000 bpd today.
Great.
Okay. The point, I guess, Paul, is if we're not logistically constrained, it goes back to Bill's point about economics.
Right. That's exactly what I was trying to get at. Yeah, I think I get it. I think it's all an Atlantic Basin thing that we're going to have to think about, right? And the RINs you're referring to, obviously, is European RINs, right? In terms of export economic.
Well, no, U.S. RIN.
No, we're talking about the RINs, cost of RINs. In the U.S., when we sell product in the U.S., we're the obligated party. When you export, you don't have that obligation. Joe was telling you that works into the math.
Yeah, I'm going to take this offline, but I'm getting there. It's just so important, obviously, to the outlook, how much we can export and how much we can grow that going forward. Just separately, the DD&A jumped up. Even with high throughputs, DD&A per barrel jumped up. Is there anything to add on that?
Yeah. It was up about $40 million from the prior quarter. It relates to accelerated depreciation that we took on some of our logistics assets as we were finalizing the financial statements for the MLP. Then we also had St. Charles hydrocracker startup. So we had added depreciation from that project.
Great. Thanks very much. So that's not going to be an ongoing. We don't obviously forecast that to keep growing at that rate.
No. The guidance I think Ashley gave was $425 million, so it's going to be about $30 million less than what the third quarter was.
Perfect. That's two questions. Thanks.
Our next question comes from Chi Chow from Macquarie Capital. Chi, your line is open.
Great. Thank you. Got a question back on the cost advantage crudes. In your, I think, latest presentation, you have a slide showing the Gulf Coast. You have advantage crudes processed by region, and I was just noticing your Gulf Coast capacity. It looks like its first quarter, second quarter of this year is around 320,000 bpd, maybe 25,000 bpd. Do you have that same metric for the third quarter?
Let me see here. Capacity. Yeah, it's about the same. It was running. We estimated capacity to process light crudes was in 2Q, around 280,000 bpd, 290,000 bpd. We estimate it's up around 310,000 bpd now for the third quarter.
Okay. Are you maxed out in the Gulf Coast at this point on the advantage crudes until Corpus and Houston, those projects come on, or are there just more opportunities to kind of tweak the volumes higher in the meantime?
Hi, Chi. This is Lane. We still have the opportunity to optimize these domestic suites versus really, I would say, medium sour imports. We haven't entirely used all of our capacity yet to put these domestic crudes into our refineries. We still have some capacity left, even beyond these projects we're looking at.
Lane, do you have an estimate on volumes on how much more you can optimize towards?
Yes. Our capacity right now is around 415,000 bpd to run these crudes.
In the Gulf?
In the Gulf.
Remember, you are displacing medium sours in some of this, though, that we still have better economics on medium sours. That is the reason we are only running the 310,000 bpd versus the 400,000 bpd capacity is because we still have better economics on the mediums.
Right. Okay. Thanks, Gene. I guess second question back on this RIN issue. Bill, do you have any comment on this supposed leaked EPA document? What is the outlook on your end into 2014 and what the mandate might look at? Have you had any discussions with regulators or the administration lately, and any feel for how they are thinking about next year?
Yeah. Chi, this is Joe. I think the answer to all your questions is yes. Obviously, the leaked information, along with other things that the EPA has said have led to the decline in RIN prices. They recognize clearly that the blend wall is an issue, and they said they are going to address it. They extended the deadline for compliance for 2013 to June of 2014, and then the leaked memo comes out, and it has a fairly significant reduction in 2014 statutory levels to what they proposed in 2014. That being said, none of us know if this is true or not, but it certainly had the effect of taking the pressure off of the RIN market, and that is why we saw it drop from the mid -$1.40 to $0.20 or sub- $0.20 today. If we look out, the EPA gave us a short-term relief.
If we look out, there has been a lot of activity on the legislative front. There are many bipartisan groups that are working on amendments, rewrites, essentially, of the RFS. They are kind of across the continuum as you would expect. Although we think it is poor legislation and it should be repealed, it is really much more probable that it gets amended and it becomes palatable and it puts the RINs where they should be, which is a compliance tool and not something that economically affects compliance with the RFS. Bill has had many meetings on this in D.C. and other places, and I have had one also. We continue to work the issue, and we do think that we are going to get some relief in 2014, and hopefully longer term with legislative relief.
Okay. Thanks, Joe. Do you think these legislative actions on the rewrites, does the EPA just short-circuit that effort by just taking the rug out of 2014? Is this going to be just a year-by-year rolling uncertainty as we go into the RFS for the following year? Or do you really believe there will be a rewrite at some point on the RFS?
Okay. First of all, I think the EPA did what they could, and they acted within their authority to do what they needed to do for 2013, 2014. Okay? Looking out, I do think that there's enough attention on this issue that you are going to get a legislative fix. I'm hopeful that you are, and there are a lot of people working it. I expect that we're going to see something. I'm not sure when it'll be. It certainly won't be this year, but hopefully we see it sometime in the early to mid part of next year.
Okay. Thanks, Joe. I really appreciate it.
Hey, Chi, it's Ashley.
Yeah.
I want to clarify on your first question. I was just talking about the light crude capacities and what we're processing. When you add in the Canadian stuff, and this better matches that chart you were referring to in the appendix of our slide deck.
Yep.
It has been improving. Q1 was $331,000 a day. This is all Gulf Coast.
Yep.
$331,000 a day. Q2 was $336,000. Q3 was $346,000.
$346,000.
It's mostly light, but we're getting some advantaged Canadian heavier stuff too.
Okay. Okay, great. Thanks, Ashley.
Our next question comes from Allen Good of Morningstar. Allen, your line is open.
Good morning. I want to first come back to the export issue and just get your thoughts on the market, maybe a bit longer term. It would seem that every refiner and cleaner selves are betting on maintaining high utilization through exports. As a result, you're building that export capacity. But if we look at the U.S., it seems like the oversupply will be in gasoline. If you think about globally, it seems Europe will bear the brunt of the refinery closures, and that's not really a gasoline market. I'm just wondering, where do you see that extra demand for gasoline coming from, given it seems like gasoline exports will need to increase over the next few years? Is it simply a fact of increasing demand in Latin America, or do you think you can grow markets elsewhere?
More importantly, how do you think Valero maintains its market share of exports, considering your peers are really jumping into the export market with additional capacity as well?
Okay, this is Gene. As far as Europe not importing gasoline, you're right, they don't. But they do export a lot of gasoline when they run the refineries full out. I think when you get the rationalization in Europe, they'll reduce their gasoline exports in places like West Africa and Latin America to make room for the U.S. barrels, which have a big cost advantage.
What do you think as far as with peers increasing as well, do you think there will be enough of that lost supply from Europe really to accommodate all U.S. refiners who are looking to export more products?
Well, it is more than just Europe. We talked a little earlier about the whole global market. There are also refineries going down in Australia, Korea, Japan, the European refineries. Anyone that has disadvantaged crude without a market. If you are importing crude, exporting products, and you are on LNG natural gas, you are pretty much disadvantaged, and those are refineries that will make room for the more competitive refineries.
In gasoline demand in Latin America, you have population growth, you have economies growing, and you have increased demand. You have operations that historically anyway, have not been very good. In Mexico, they have decent operations, but structurally, they are short gasoline, and they continue to grow. Venezuela has had significant refinery operating issues in the Caribbean, which have affected gasoline supply and which I do not know get resolved anytime soon. Although I think Gene's comments on Europe are right, and I also think we are fairly comfortable that with low-cost, efficient refineries in the Gulf Coast and the natural resource advantages that we are enjoying there, we are going to be able to continue to be very competitive exporters, not only to Europe but also to Latin America.
Okay, great. Thanks for that. If I could just come back to capital spending, I guess a couple of years ago, it was assumed once the hydrocrackers were completed, that you would see capital spending fall. Clearly, you mentioned earlier that the market is presenting a lot of opportunities for you to continue to reinvest in the business. If we were to assume that your current market conditions hold going forward, do you think your queue of potential projects is deep enough where we could assume that this $1.5 billion on growth will continue, and maybe that $3 billion total for capital spending would be a safe run rate over the next few years? Or do you expect you will extinguish some of these current opportunities over the next year or two, and we will see capital spending maybe fall back down once we get three, four years out?
Well, we are only given the guidance for 2014, but a big part of the 2014 spending is logistics, and those projects get completed. As they fall off, it remains to be seen. We think part of our job is to add shareholder value, and there are these opportunities. We are not just saying, "Hey, capital spending is going up, up." What we did is we raised our 2014 guidance basically $0.5 billion- $3 billion, because of really a lot of logistics stuff we are trying to get done. A lot of it does get done next year.
Okay, great. Thanks. If I could, one quick follow-up. I guess share repurchases fell off in the third quarter. It seems that on your run rate for the fourth, you are back to about a little bit less than $300 million per quarter. Should we assume that run rate going forward until you extinguish the $3 billion, or would you look to potentially add to the $3 billion once we get closer to the end or extinguishment of that level?
Yeah. Hey, Allen, this is Ashley. We do not have guidance on how much specific buyback activity we are going to do going forward, except that we do consider that a priority return of cash to shareholders, along with the recurring dividend. We will not provide specific guidance.
Just to reiterate what Ashley said in his comments, we spent $675 million buying our shares this year. We raised our dividends. Our dividend is going to approach, I think, $400 million on an annual rate. So that is over $1 billion. We spun off CST. This management team, for any of the people that are still on the call, this management team has been very focused on returning value to the shareholder.
Great. Thank you very much.
Our next question comes from Matt Carter-Tracy of Goldman Sachs. Matt, your line is open.
Great. Thank you. Just one additional question on crude exports. I know you addressed the product export constraints in some depth, but I am curious as you are looking at both railing Bakken crude into Quebec and also shipping Eagle Ford crude by tanker, is there actually any logistical strengths that would keep you from shipping more Gulf Coast crude to Quebec if the differentials became favorable to doing that?
Well, on the water there are not, because we are supplying Quebec on the water today with foreign light sweet crude. So there certainly would not be on the water. On the rail side, I think we are probably going to be maxed out somewhere around 65,000 bpd. But then, we are also going to be a shipper on Line 9, and those barrels will deliver in on the water. But they will come from Canada. So I would say no.
Joe said that earlier that once all those projects he just mentioned get finished, and we've said it on previous calls, that the Quebec refinery is going to evolve into a North American crude supplied refinery where it used to be 100% foreign, but you'll still have this economic opportunity because you have the hardware. Over the next year, we're still importing crude into Quebec. And we've told you guys in the past, we run Saharan out of Algeria, CPC, some Azeri, there's probably some West African thrown in there. To run out the whole 240,000 bpd or so of our capacity there, for the next year, we'll still be an importer of crude. Because you do wind up with some refining hardware capability here. Eagle Ford is very paraffinic. It gives the whole industry problems in the crude heater.
You do wind up with some processing limitations, which then we all try to address here through hardware. But for the next year, we're still going to run some foreign crude there.
Understood. Thank you.
We have no further questions at this time. I would like to turn the call back over to Valero Energy Corporation's management for closing remarks.
Okay. Thank you, Chris. We thank the callers and listeners for joining the call today. If you have any other questions, please call investor relations. Thank you.
Thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect.