Welcome to the Valero Energy Corporation reports third quarter 2012 earnings conference call. My name is Christine and I will be your operator for today's call. At this time, all participants are in a listen-only mode. Later, we will conduct a question and answer session. Please note that this conference is being recorded. I will now turn the call over to Ashley Smith. You may begin.
Hey, thank you, Christine, and good morning. Welcome to our earnings call. With me today are Bill Klesse, our Chairman and CEO, Mike Ciskowski, our CFO, Gene Edwards, our Chief Development Officer, Kim Bowers, our Executive Vice President and General Counsel, and several other members of our 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, feel free to contact me after the call. Before we begin, 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 describe in our filings with the SEC. Now I'll turn the call over to Mike.
Thanks, Ashley, and thank you for joining us today. As noted in the release, we reported third quarter 2012 earnings of $674 million or $1.21 per share. This includes an after-tax non-cash asset impairment loss of $341 million or $0.62 per share, and after-tax severance expense of $41 million or $0.07 per share, primarily related to the Aruba refinery as described in the earnings release financial tables under notes D and E. Excluding these two items, third quarter earnings were $1.1 billion or $1.90 per share. Operating income was $1.3 billion versus operating income of $2 billion in the third quarter of 2011. Excluding the previously mentioned items, third quarter 2012 operating income was $1.7 billion. The decrease in operating income was mainly due to lower refining margins in the U.S. Gulf Coast, West Coast, and Mid-Continent regions.
A decline in retail and ethanol margins also contributed to the decrease in operating income. These declines were somewhat offset by significantly higher refining margins in the North Atlantic region. Our third quarter refining throughput margin was $3.12 per barrel, which is a slight decrease versus third quarter 2011 of $13.24 per barrel. The decrease in refining throughput margin was mainly due to lower discounts on crude oils and feedstocks, and lower margins for other products such as petrochemical feedstocks and propane. However, we saw higher margins for gasoline and diesel in all of our regions, and diesel had the highest margins among our major products. Our third quarter 2012 refining throughput volume averaged 2.6 MMbpd. That was up 8,000 bpd from the third quarter of 2011.
The increase in throughput volumes was mainly due to the acquisitions of the Pembroke and Meraux refineries in 2011, which was nearly offset by the lack of throughput at Aruba, hurricane-related downtime and slowdowns at our St. Charles, Memphis, and Meraux refineries, and unplanned downtime at our Meraux refinery as a result of the crude unit fire in July. The Meraux refinery restarted its crude unit in mid-October. Excluding the Aruba severance expense, refining cash operating expenses in the third quarter of 2012 were $3.72 per barrel, which was higher than the second quarter of 2012, mainly due to higher energy costs and increased maintenance expense. Operating expense, though, was lower than guidance due to lower than anticipated cost for catalyst and energy.
Our retail business reported quarterly operating income of $41 million, which includes a $12 million non-cash asset impairment loss as described in note E to the financial tables. Retail operating income was $17 million in the U.S. and $24 million in Canada. The rising crude price environment squeezed retail fuel margins in both regions. Fuel volumes declined slightly compared to third quarter 2011 as weak gasoline demand impacted sales. Our plan to separate our retail business and unlock value for our shareholders is moving forward. In October, we submitted our request to the IRS for a private letter ruling on a tax-efficient distribution of our retail business to our shareholders. Later this quarter, we expect to file a registration statement with the SEC. Given the timing of these events, we expect to complete the retail separation late in the first quarter or early second quarter of 2013.
Our ethanol segment reported a $73 million operating loss in the quarter, which was down $180 million from the third quarter of 2011, mainly due to much lower gross margins as high corn prices and excess ethanol inventories squeezed the margins to very low levels. As a result of the low margins, we reduced our ethanol production to average 2.4 million gallons per day in the third quarter of 2012, a decline of nearly 900,000 gallons per day compared to the third quarter of 2011. In the third quarter, general and administrative expenses excluding corporate depreciation were $174 million, which was in line with our guidance. Depreciation and amortization expense was $402 million, and net interest expense was $70 million. The effective tax rate in the third quarter was 46%, but excluding the asset impairment losses and the Aruba severance expense, the tax rate was 35%.
Regarding cash flows in the third quarter, capital spending was $784 million, which includes the $75 million of turnaround in catalyst expenditures. We reduced our capital spending guidance for the full-year 2012 to approximately $3.5 billion versus prior guidance of around $3.6 billion. We expect 2013 capital spending to be $2.5 billion, and that includes approximately $200 million for our retail segment. Also, in the third quarter, we paid $97 million in cash dividends to our shareholders. With respect to our balance sheet at the end of September, total debt was $7 billion, cash was $2.5 billion, and our debt to cap ratio net of cash was 20.6%. At the end of the third quarter, we also had nearly $5.7 billion of additional liquidity available. Our key growth projects continue to move closer to startup.
This week, we expect to begin commissioning activities at our Port Arthur hydrocracker project, and this unit should be operational in December. The St. Charles hydrocracker project remains on schedule to be fully operational in the second quarter of 2013. On the macro side, we believe that Valero and other U.S. Gulf Coast refiners have several competitive advantages versus other Atlantic Basin refiners, including low cost to natural gas, increasing access to discounted domestic crude oil, and larger, more complex and reliable refineries. These competitive advantages have enabled us to profitably take market share from less competitive Atlantic Basin refiners. This is exemplified by the high utilization rates in PADD III refiners and continued solid export demand for U.S. Gulf Coast products. Now I'll turn it over to Ashley to cover the earnings model assumptions.
Okay. Thanks, Mike. For modeling our fourth quarter operations, you should expect the refinery throughput volumes to fall within the following ranges. The Gulf Coast at 1.45 MMbpd- 1.5 MMbpd. Mid-Continent at 440,000 bpd- 450,000 bpd. West Coast at 275,000 bpd- 285,000 bpd. North Atlantic at 320,000 bpd- 330,000 bpd, which is lower than the third quarter due to a plant-wide turnaround at the Pembroke refinery during most of October. Refining cash operating expenses in the fourth quarter are expected to be around $3.85 per barrel. Regarding our ethanol operations in the fourth quarter, we expect total throughput volumes of 2.5 million gallons per day, and operating expenses should average approximately $0.40 per gallon, which includes [inaudible] and amortization.
Also, we expect G&A expense excluding depreciation to be around $190 million, and net interest expense should be around $70 million. Total depreciation and amortization expense in the fourth quarter should be around $405 million, and our effective tax rate in the fourth quarter should be approximately 36%. Okay, Christine, that concludes our opening remarks. We'll now open the call for questions.
Thank you. 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. If you are using a speakerphone, you may need to pick up the handset first before pressing the numbers. Once again, if you have a question, please press star, then one on your touch-tone phone. Our first question is from Evan Calio of Morgan Stanley. Please go ahead.
Hi, this is Manav for Evan today. I have just a couple of quick questions. One was on the West Coast refining margins. They came in slightly below the indicative margins. Just trying to understand what happened there.
Okay. We really didn't have margin guidance, so I'm not sure what to reconcile for you. Maybe we could talk about it offline with a little more clarity on what you want us to reconcile to.
I'm just trying to understand because sequentially they were slightly lower while the gasoline prices were higher in that region. So I'm trying to understand what happened there.
Yeah. Well, okay. Go on.
I guess one would be that we sell branded prices as well as unbranded, and you would be looking at the spot market prices. As some of the markets were moving, and a lot of that occurred in October, but it did occur some in September, our average for our gasoline products would be less than the spot market than what we actually sold.
That is a contributing factor. Also, some of our feedstock costs. We run a lot of VGO out there, even ANS. Some of those prices relative to benchmarks may not have kept up, so margins were impacted there, but there is no one key driver.
Okay.
They split by gas oil somewhat on the 70/30 split, so that would raise our gas oil cost.
Okay
as Ashley points out.
One more quick question. In the first quarter of next year, you have pipelines connecting the Permian Basin down to the Gulf Coast, whether it's Permian Express or reversal of Longhorn. How would your refineries benefit from that?
Well, this is Gene Edwards. These are WTI type crudes, sweet crudes, and those pipelines come into the Houston area, so we could run those crudes in our Houston refinery, along with the Eagle Ford crude or any other crudes, domestic sweet crudes are in that area.
Okay.
We also run some of them out into our Texas City refinery as well.
Okay. Thanks, guys.
Okay.
Thank you. Our next question comes from Jeff Dietert of Simmons. Please go ahead.
Good morning.
Morning, Jeff.
You guys provided some capital spending guidance. 2012, a little bit lower, 2013, maybe a little bit higher than previously discussed. Could you talk about opportunities for growth CapEx in maybe the major buckets that you see opportunity, infrastructure, flexibility to use more light crudes, and anything else that you might see on the growth CapEx front?
Well, Ashley's looking for some numbers, Jeff, but the guidance that we've given you for 2013 has always been $2 billion- $2.5 billion.
As far as I'm concerned, we're still within our guidance. We've also pointed out that retail spending in that number is about $188 million. I think we rounded to $200 million. As far as I'm concerned, we're still within our guidance. Now, some clearly, and I've said this, our St. Charles project is we've lost about two to three months from our original schedule. Based on what I gave, maybe on the last call, we're on time with that, but from the original schedule, we're behind. So we have some carryover into 2013 from that project, and that's largely this $100 million reduction for this year sliding into next year. But basically, I consider us still within our range. Ashley has some numbers for you.
Yeah, Jeff. So next year looks like we'll spend between $950 million and $1 billion on strategic projects. It's distributed across several areas, several segments, but mostly that's in refining. In those strategic buckets, there's some crude expansions and some flexibility projects, as Bill mentioned at McKee and Port Arthur, Houston, just small spending across several of those. Looking at projects that might allow us to get some more throughput through those hydrocrackers, the new ones at St. Charles and Port Arthur, plus Meraux. There's other various logistics and biodiesel and retail and pipelines and terminals and things like that.
All right. Thank you. Secondly, in shifting Aruba towards a terminal, what do you see profitability looking like as a terminal in 2013, and how does that compare to the cost of Aruba in 2012? How do we think about year-on-year change?
Well, we lost over the last several quarters somewhere in the $8 million - $10 million a month in Aruba. This year we lost over the last year or two in the order of, on average, around $100 million, $120 million. One year was higher than the other. We don't usually give that kind of info out, but we've had a loss in Aruba. We believe that a terminal operation will be a good project for us there. We're still fixing some tanks, fixing the dock, things that we're doing and have been doing. But we expect the business that it'll cash flow for us in 2013. With all the volatility we see in these markets, the forward curve, once it gets into contango in certain products, there's just a lot of opportunity to store. Aruba has very deep water.
You can pull a VLCC right into the dock. We think it's a good project.
Thanks for your comments.
Okay. Thanks, Jeff.
Thank you. Our next question is from Robert Kessler of TPH. Please go ahead.
Hi. Good morning, everyone.
Morning, Robert.
I had two questions for you. One is, with the near elimination of light crude imports into the Gulf Coast, it begs a question in my mind, and that is ultimately, do you see the capability of loading some Gulf Coast-located light crude on a ship and moving it up to Quebec City and ultimately processing it there? I know it probably wouldn't work at today's spreads, but what sort of logistics might be involved, and what spread, let's say, between LLS and Brent or whatever benchmark you think is appropriate might you need to make that happen? The other question is just if you would remind me what your thoughts are on buybacks and when you might see a material program there.
On the first question on Quebec, some crude has already moved from the Gulf Coast to Canada, some out of Corpus Christi as well. That's actually where some of the economics work better. Freight costs average is maybe $2 a barrel or a little less. It's all economic driven compared, as long as you have their license to export into Canada, and some has already moved. This is something that Valero will do too, as other companies are looking at. We can run in Quebec somewhere in the 85%-90% of our charge there could all be basically light sweet crude. Today, even though it's a Canadian refinery, it runs imported oil, Algerian, CPC, North Sea, West African. It runs all those kind of crudes today.
For us, as we look at it, as the crude continues to come to the Gulf Coast, and we're quite convinced that the original premise we had a year or so ago is actually going to happen. There's going to be lots of light sweet crude on the U.S. Gulf Coast. It's going to be looking for a home.
Yep. I think some people forget that refinery way up there might stand to benefit from this. Thanks for that information. Can you tell me, do you guys have any kind of market analysis on what you think the Eastern coast of Canada, the refineries on the eastern side of Canada could ultimately take as far as Gulf Coast-based light crude?
Well, there's four refineries up there, and some run some medium sours as well, Irving.
Yep.
But really, you need to look that up. We would have an opinion, but we know better what we can do. Just to be totally so that you understand the whole situation, we expect to take lighter crude oil, syncrude, and other crudes from the West as well, moving it into Montreal and then getting it up to the Quebec refinery. So the feedstock slate for our Quebec refinery is going to change.
Understood. Thank you. Then buybacks?
Well, I said all along that we think our stock, and actually it's the whole refining industry, but us in particular, we're undervalued when you're selling it four times EBITDA. We have these projects coming on that I think separate us from the pack, so that when you Our two hydrocrackers by the second quarter of next year will be major contributors. They are absolutely the right project for the right time. So we think our stock is undervalued. But if I go to a ranking of, and this is, I believe, absolutely consistent with what we've said in the past, it's always safety and reliability first. We're improving our reliability around the system, and we continue to spend money to do that. Investment-grade rating is absolutely key. We have adequate cash to fund this business.
As Mike said in his notes, we ended the quarter with $2.5 billion of cash. We have lots of liquidity, as he also said. We are going to fund our projects to completion here. The Diamond Green Diesel project spills over, and frankly, we will expand both our hydrocrackers pretty much right out of the chute here as we get our permits. We continue to look for excellent investment opportunities. To be honest, some of our shareholders want to see the cash, and some of our shareholders want us to invest in good projects. We continue to look for that. But we match that up against the comment I started with that our shares are undervalued. We get to returning our cash to the shareholder. We have raised our dividends several times.
I have said that we want to have a yield that is among the highest in our peer group. We have purchased our stock. We did not purchase any stock in the third quarter as we have got our retail separation underway here, and we were building some liquidity. But last year we bought 17 million shares, and this year we have already bought 6 million shares. We have actually demonstrated that as well. I think that is pretty well. I think we have been very consistent as to what we are doing.
Thanks for that. Just quick follow-up. Anything that precludes you from buying back stock between now and the time of the retail spin?
No, there is nothing that does.
Got you. Thank you.
Thank you. Our next question is from Doug Leggate from Bank of America. Please go ahead.
Thanks, Doug. Good morning, fellas.
Morning, Doug.
I've got two or three quick ones, hopefully. We haven't really seen wide light, heavy differentials in quite a while. We seem to be seeing them right now. I'm wondering if you can talk a little bit about what you're seeing in the market to cause that. On the same token, if you look at your runs, it looks like you upped your heavy runs this quarter and also your light runs. So a little bit, maybe some color around how those two things are interacting, and I've got a couple of quick follow-ups, please.
Okay, Doug, this is Gene again. I think what's driving light heavy, resid has gotten a little bit weaker compared to where we had been. So resid's running about $16 discount to Brent. So you're seeing all the crudes follow that, including the Maya, the heavy sours. Probably more importantly, the medium sours, those have been running in the $7, $8 range discount to Brent over the last month or so, which is good. WTS is also cheaper, so you throw all those in there, it's just giving us better discounts on medium and heavy sour crudes.
Are you meaningfully changing your slate, Gene, to adjust to that?
Well, we're always optimizing. We run economics every day, cargo by cargo, whether we Because sweets are cheap too. LLS is trading about even to Brent. And remember that Brent is before transportation, so LLS is a big discount to foreign suites. So we're always optimizing our slate every day because we have a lot of flexibility in the system. We're just, like I said, we're taking advantage of all.
Great stuff. My follow-ups are really two strategic questions. I am going to group them together and see how best you can and as much as you are able to answer them. The first one is, I think, Bill, in the past, you have talked backwards and forwards about whether California was actually a core region for you going forward, given the regulatory spending. There was a little bit of chatter in the markets a few weeks back that maybe there was some movement in that regard. I wonder if you could comment on that. In the same vein, Mike and I had the opportunity to talk a little bit about what was going on in the summertime over the MLPs that were being listed in the form of refining, namely Northern Tier.
Now we have seen that thing wash out with a fairly substantial multiple uplift for a refiner, which I think was a little different than it was early in the summer. I am wondering how that might have changed your view around, for example, Ardmore and McKee, some of the high cash flowing assets, and whether that is something you might want to consider down the road. I will leave it at those two, please. Thanks.
Well, Doug, on California, I have said that we continue to look at our options. We work for the shareholder, and we think that the regulatory environment in California is not constructive to the California economy, it is not constructive to the working person, and it is not constructive to our industry. Whether it is AB 32 or whatever regulations we are faced with, but in AB 32 particularly, the academics and the extremists have hijacked the process, and they are coming up with regulations that are totally not workable.
We look at our options, and we continue to look at our options. But on the other hand, we do not comment on rumors. On MLP, our organization is really working on the retail separation. We would still consolidate. There is some financial theory here in that we borrow, borrowing costs are very low. We are not in need of any cash.
There is a good discussion about this from the company's perspective as obtaining funds at the lowest cost. However, in acquisitions, it is clear that the MLP is an excellent acquisition vehicle. The market clearly likes that approach. We have some pipelines and terminals that we can contribute to an MLP. Our strategy is to finish our retail separation, and then, as I think Mike probably told you, and we have said in the past, that we are going to look at the MLP. The third part of your question is on the refining, and clearly NTI has traded better here because initially it did not trade that well. But these type of assets, as you know, and as the others on the call know, their high cash flow is, in fact, tied to the WTI LLS or Brent spread.
Refining is all about location today, and if you are in the right location, your cash flows are huge. But there is a forward curve or a forward expectation, so you get into a conversation of what you could actually realize doing that today. We think that would not necessarily result in an advantage to our shareholders.
That is very clear, Bill. I appreciate the answer. Could I push you a little bit on the pipelines and terminals? Because obviously, NuStar, I guess, has all the legacy stuff. What is the appetite and what is the potential scale in terms of current EBITDA that you would associate with those pipelines and terminals? Because I was under the impression you did not have a whole heck of a lot left.
Well, we would have somewhere between $50 million and $100 million of EBITDA just dealing straight, like just taking terminals and pipelines. Remember, we are partners with Kinder Morgan on the Parkway Pipeline. We have our big pipeline project in Canada, which is just about finished here and getting ready to start up. So we have assets in our system, but also we have tankage and other things that are being dropped in MLPs as well. So it would be a small MLP, but it would not be any smaller, I guess, than a couple of the others out there. We would have the opportunity to drop other assets as we go through the future. So we will look at it. We have said we were going to look at it, but our focus today is really on the retail separation, because we do believe that adds significant shareholder value.
Terrific. Thanks for the answers.
Okay, thanks, Doug.
I might add, we don't think our stock reflects that value.
Okay, Christine? Christine?
Yes.
We are ready for another question.
Fantastic. The next question is from Paul Cheng of Barclays. Please go ahead.
Hey, guys. Good morning.
Hey, good morning, Paul.
A number of quick questions. Actually, can you remind me, the retail spin-off, if the ethanol facility is going to be included or is going to stay with Valero?
Ethanol segment?
Yes.
is going to stay with Valero.
That is not part of the planned asset.
The retail spin in the U.S., the retail separation in the U.S. is the company-operated stores. It is 1,025, and it is the 775 stores, 250 of which we own, and the rest where we control the price or manage the price at the pump in Canada. That is the business that we are separating, including home heat and card lock in Canada.
Okay, perfect. Secondly, if I look at the number, next year, CapEx is $2.5 billion, and I think Ashley said that strategic is about in the $950 million to $1 billion, and $200 million is for retail. That means that the remaining sustaining capital is about $1.3 billion for the refining and the ethanol together. Is that a reasonable proxy as ongoing sustaining capital, or that next year is particular high or particular low?
I've given out in the past with our business, and I would say DD&A runs for us about $1.4 billion. It's going to change a little bit with the hydrocrackers, obviously. It'll go up probably $100 million. Then we have retail come out. I think the sustaining capital is really in the $1.5 billion, $1.6 billion, and that's the number that I've given to people, $1.5 billion, $1.6 billion, $1.7 billion in all the past. Next year, we're finishing some projects. It might be a little lower next year. Turnarounds catalysts are $600 million a year for us. So I think this $1.5 billion- $1.7 billion, the numbers we've given in the past are the right numbers.
Bill, the $1.5 billion- $1.7 billion, is that including retail or not including retail?
Well, sustaining capital, it would include retail in my conversation.
The retail sustaining is probably $150 million-$200 million, right?
It is very small for retail as sustaining capital. It is very small. I think my range of this $1.5 billion-$1.7 billion is a good range for you guys to think of us as sustaining capital for the refining pipeline terminal business that we have.
I see. Very good. On the North Atlantic, the sequential margin up about $5 from the second quarter. If I look at the benchmark indicator, whether it is in Europe or in the Northeast market, does not go up by $5. The question is there any one-off benefit in the North Atlantic that we should take into consideration, or that you think is really that running well and is more like a normal run rate that we can base on going forward?
In the North Atlantic, I think the marketing operations performed fairly well during this period, which would have given it a little bit of margin above that.
Okay. I see. In the press release, you guys mentioned that you have unplanned downtime, both related to Isaac and the unplanned outage in Meraux. Do you have any kind of cost estimate and opportunity cost estimate related to those downtime in the quarter?
Well, the lost revenue for Meraux, which some spilled into October, was $53 million. It took us about $16 million for the repair.
$16 million?
$16 million for the repair. Now, we did a lot of reliability work while the unit was down.
The lost opportunity was $53 million?
$53 million for the crude, and then another $13 million just for the hurricane impact.
Okay.
Between the two, okay. $66 million between the two events just for Meraux.
Just for Meraux. How about the Isaac impact on the other facility?
St. Charles was shut down, and it was about a $34 million impact on gross margin.
From the hurricane.
Yep, from the hurricane.
Okay. Can you guys share with us some maybe market data about the retail in your own retail network that the gasoline same-store sales in October, how does that look? Also how is the export so far in October comparing to the third quarter?
On this retail store sales in October, how do they look compared to September?
No, comparing to the year-ago October on a same-store year-over-year.
We are running flat.
Running flat?
To last year.
How about export?
Okay. Now export, back to the refining group. Exports right now are back up from the third quarter level for diesel. In the third quarter, exports were down as the arb was closed for part of the time. On gasoline, they are running this 75,000 barrel a day range.
Okay. For the hydrocracker, Bill, you are delayed, as you say that for maybe two or three months. Is that resulting in any change in your overall cost estimate, or it is pretty much still about the same?
No, it has changed our cost estimate. Again, these are numbers, they are not changed I think from when I saw you. At our Port Arthur, we still expect to underrun that project. At St. Charles, we are overrunning the project. On total, they are on budget when you add them both together. Very close to being on budget. Clearly the delay at St. Charles is costing us additional money.
I see.
Now, all I say to you is for Valero, I know Exxon and these guys do big projects. For Valero, these are huge projects for us, and our people are managing these pretty doggone well.
But we're just a few months behind.
Mm-hmm. Two final question. One, do you have any committed to the Enbridge Line 9B reversal to ship barrel, so that you can take it from there, from Montreal up into Quebec City? The second, yep.
Well, the answer is yes, we do. Assuming they can get their permits to reverse the pipeline into Montreal, this was why I added that to the other question earlier. We have a commitment to ship on that line, along with Suncor.
Bill, can you share with us then how big is that commitment?
Petro-Canada, I am sorry.
Okay. Final one. On the hydrocracker, I guess that with the
Suncor
with the dividend growth, the next dividend increase or reconsideration by the board, do we need to wait until the hydrocracker, both of them come on stream? Or that even after Port Arthur will come on stream, you will feel more confident about your cash flow and will be able to re-look at your regular dividend? Given, I think a lot of your long-only accounts perhaps that may be more inclined to like the regular dividend than the share buyback.
Right now on the dividend, management will have a recommendation, either to hold it or stay the same, but it is a board item. We'll go through our forecast with our board. Our hydrocrackers, they're not up and running yet. Those are, as you properly stated, are significant. So, this will be a board discussion.
Is that discussion going to be, say, have to wait until after both of them come on stream, or even after one of them come on stream that we have that discussion already?
Paul, I respect your question, and I understand what you're asking. But I'm going to answer you that you're not going to be satisfied. What I'm going to say is, we as management will have a recommendation for our board, and we will discuss it at the board meeting. We want a dividend that we can sustain. We also want a dividend that's going to yield, as I said, the highest among our peers. We'll look at that as well as my other comment, where we think our stock is undervalued. So I am just going to say to you that it's a board item, and it'll be discussed.
Thank you.
Thank you. Our next question is from Blake Fernandez of Howard Weil. Please go ahead.
Good morning, folks. I had two questions for you. One was on the retail. If I understood correctly, you were previously evaluating either a spin or a sale. It sounds like if I am reading correctly, you have eliminated the sale option and now just simply pursuing the spin. Is that correct?
That is not correct. We are pursuing a separation, but our board has only authorized us to do the analysis around this. I know we use the words that things are moving forward, but we do not even have board approval for a separation. We have board approval to look at this, and we all realize that there is the shareholder value creation that we have spoken about. But we are going through here to make sure that we maximize shareholder value and at the same time, treat the business and our people correctly as well.
Got it. Okay. The second was on M&A. I guess it is a twofold question. One, obviously, Murphy seems to be a little bit more aggressive in exiting the R&M business, and it has always been, I guess, envisioned that Valero is a natural buyer of Milford Haven. Just curious if you have any thoughts there. Secondly, just from a broader M&A standpoint, now that Texas City is off the market and Alliance has been removed, it seems like most of the major assets have been plucked off at this point. I am just curious, Valero, you have been historically fairly active on the acquisition front. Is it fair to think that we move away from that and more just to a free cash flow generator? Thanks.
Well, there was a lot of issues there, Blake. As far as specific assets, whether it is Murphy, Milford Haven, or other things that are in the market, we tend to look at these acquisitions, are they going to integrate with our system? That is why we liked Meraux as it integrated with St. Charles and frankly, our other Gulf Coast plants. We are of the mind in the U.S. that demand is not going to grow, certainly for gasoline. Maybe there is some bounce if people get back to work, but long term, gasoline is not growing. Diesel will have some growth, but it still has not recovered from the Great Recession, and it will be years before it does. Whatever we tend to look at, we are looking at, in a way, the Atlantic basin and being able to be a stronger competitor in the export business.
All the things that we look at, we want to be able to say at the end of the day that we have been able to integrate this and actually are lowering the cost from the womb to the tomb. We continue to look, and at least our experience here would be that other assets will come to the market because the refining industry is going to continue to consolidate in the United States and Western Europe. There is just no doubt in my mind about that. We will continue to look. I would not say that we are not an active player, but we are after things that make us more competitive as we have to deal in the export market.
Okay. Thanks a lot. Appreciate it.
Thank you. Our next question is from Roger Read of Wells Fargo. Please go ahead.
Good morning.
Morning, Roger.
Just to, I guess, follow up a little bit on the export and maybe talk a little bit about global capacity you see on the horizon in 2013. If I understood correctly, 75,000 barrels a day of gasoline in Q3. I didn't catch the distillate number. What do you see as the capability to grow that in 2013? What are you going to be pushing against in terms of identified global growth that may be pushing back, could impact margins, et cetera?
Well, our exports in the third quarter were about 118,000 on diesel, just so you have it.
correct.
118,000 barrels a day. That was actually down from where we have been averaging, which is somewhere just on average, 175,000 barrels a day. Our industry then has been exporting 1 million barrels a day of diesel and somewhere in the 300,000 to 500,000 barrels a day of gasoline. So Valero is somewhere in the range of 20% or so of the export business in that range. There is capacity that comes into the market. Refining capacity is being built. Also, the world demand is going up. We still expect for next year, because you were talking about 2013, that the world will increase we think maybe 1 million to 1.2 million barrels a day of consumption, so it can absorb some of this additional capacity. The U.S. is the most economic place here. Low natural gas costs.
Some discounts or at least parity with world prices for sweet crude. We also have very fine operating people. So we think we can compete in the business, and the business grows. It does not change my statement, though, that I have made in the past, and that is Western Europe is long refining for sure. Without exports, the United States is long refining for sure. So things will continue to rationalize in those markets going forward. But we think we can compete, one as a company and two as an industry, and the markets continue to grow. The third thing I would add to that conversation is all the Brazilian refineries that you read so much about, they are late, and they are costing them a lot more.
One is getting done here, but the others, they are going to spend a huge amount of money if they actually proceed with them. The Venezuelan refineries are in disarray. Certainly, the debate continues as to what Mexico does, and the facts are, the Mexican economy is growing, the Brazilian economy is growing. So for companies like us located on the Gulf Coast, we think we can get into these markets and be doggone competitive. Europe continues to be systemically short diesel on an annual basis.
Okay. So as a follow-up to that, where do you think your export volumes can go next year? Obviously, you have the hydrocrackers coming online, which are going to grow volumes for you. Nobody, I think, believes the U.S. is going to be in a robust growth mode next year. So, the exports are very much the outlet. Where are you in terms of actual quayside capacity and ability to roll this out?
That is a very fair question. As a general statement, because Motiva will eventually be back as well. So Europe will basically take somewhere around half of our diesel exports, and the rest of the diesel exports will go into the Caribbean and other places. On gasoline, primarily Mexico, Colombia, Brazil, and then you may see a cargo or two go over to West Africa. Our Quebec refinery, just as a little side note, has been able to export diesel into New York Harbor. But clearly, it is the same places as they continue to grow. Reaching out further, they would all be ad hoc. But remember, the Gulf Coast market is an extremely liquid market.
Absolutely. Okay, then my last question for you. On ethanol, obviously a really tough quarter. Looking at the volumes you ran in the third quarter and what you are indicating as reasonable volumes for the fourth quarter, what changes, if anything, versus the fairly significant loss we saw in the third quarter as we look at the fourth? If volumes are going to be slightly higher, is that an indication that there is a little bit better margin story here than what we have been seeing?
Gene again. We got good margins in probably five of our plants. We have two plants that are basically down. We're keeping the enzymes active, so we'll start up a couple of days a month on those, but there's two of them down, and there's three plants that are cut back. We're running 2.4, 2.5 million gallons a day. Our capacity is about 3.6. We're running probably about right at 2/3 utilization. We've seen margins improve. We had the big loss in the third quarter. We're about break-even on an EBITDA basis now at the plants on a consolidated basis. Still not nearly as good as it was last year in the fourth quarter. Inventories are still basically 17.3 million barrels, which are up by about 1.5 million barrels from last year.
Until we work that off, I don't see we're going to get a big pop in margins. We did draw about 240,000 barrels a day last week. If we keep drawing at that pace, in a month or two, we can clean some of this up. It just depends on demand. Imports have been the big factor. We had a lot of imports from Brazil recently. They've announced they're going to go from 20% of their gasoline pool to 25%. I think you'll see some of these imports slow down a little bit. Plus, they're at the end of their harvest season for sugar. I think that should diminish. I think the market will continue to clean itself up. It's just taking longer than it normally has.
For us, corn prices have stabilized, where they were moving around so much. They've kind of stabilized here at the $7.40 a bushel area.
Okay. Just a little follow-up on that. How quickly can you react within your ethanol plants to those market conditions changing? Are you as agile as in refining, it's literally a daily basis change or any help along those lines on your flexibility?
Yeah, it's pretty quick because if the margins were to improve next week, we can source more corn. The plants that are running can obviously just start increasing right away, and then the other two plants that have been down, we have been doing these monthly refreshes to keep the enzymes active so you can get them started up on short notice. What we'll probably decide going into the winter, though, when it gets colder weather there, with the plants down, that's a big problem. There's a lot of water in the system, so we'll probably have to make a decision in the next month or so, whether we're going to try to start up during the winter or just leave those two plants down throughout the rest of the winter. We'll be watching the market closely over the next few weeks on that.
Okay, thanks.
Thank you. Our next question is from Rakesh Advani of Credit Suisse. Please go ahead.
Hi there. It's Ed Westlake, actually. Thanks for my question this morning. So you mentioned an interesting number, which is $2 to get crude from, I guess, the Gulf up to your Canadian facilities. That seems low for a Jones Act ship. Is there something funny going on? And maybe talk to how much crude you could move with the existing shipping that's available on that route, and then I have a follow-on question. Thanks.
Well, Ed, I am surprised with you on the Jones Act ships. Canada is not the U.S. It is still part of the British Commonwealth, though.
Right. Yes, indeed. My wife is Canadian, so I should know that. Effectively, you could use just regular shipping, and that is why it is so cheap. Would you have a number if you had to ship crude up to, do you think if the industry had to ship crude up to the East Coast?
Well, sure. It would be three times.
You figure
It's very, very expensive. Go ahead. You had a number.
Well, Phillips has announced something. It was in the press that they're shipping barrels up to their Bayway refinery, and I think they got a deal for $4.50 a barrel.
Right. That's helpful. Thanks. The follow-on question is around the advantage position you have even in the Gulf. I think around 900,000 barrels a day capacity in Texas. Obviously, with the Eagle Ford and the Permian growing quickly, those refineries are kind of in the line of fire of that crude growth, whereas it probably costs a little bit more, and there may be some bottlenecks to get crude over to the Louisiana refineries. Do you have any numbers for us that could help in terms of quantifying how much of a dollar a barrel advantage you'd have in West Texas?
I would say to you that, and Gene and I will try to answer you. It's probably a buck. Once you put it on the ship, you've got to load it. You have all these costs to get on the ship. So if you're sending sweet crude over, say, from Corpus Christi to Meraux, I would say you'd have at least a dollar advantage at Corpus.
Yeah, I think it's more like two.
All right.
Furthermore, Houston and Corpus are probably going to be somewhat parity. What's going to clear the Houston to St. James market is going to be the SOHO line, which is going to be, they're quoting tariffs, $2 a barrel on that. I think you got at least $1 a barrel to Houston, probably $2 to Corpus Christi, kind of the minimum. Then as you get up to McKee, obviously, the numbers get even more discounted because you've got to clear the Seaway Pipeline tariff or the Longhorn reversal or any of these type of tariffs, too, as an added advantage for McKee and our board.
Yeah. So generally, you'd say that West Texas, about a $2 discount to LLS in Louisiana, and then maybe some additional advantages for being initial off-takers for some of the crude providers from the Permian and Eagle Ford?
Now, we want to be clear on this. Once you get it to the water, Gene was speaking, if you have crude in West Texas, you have that tariff to get it to Houston or Cushing, and then Cushing to Houston. That tariff on these pipelines being built. I thought we were answering your question as moving it on the Gulf Coast. You have it already in Eagle Ford to Corpus Christi, or you have a crude in Houston, and those are the numbers Gene was giving you. If you are talking about Midland or Cushing, you have to incur that tariff as well.
Yeah. No, I was just talking about moving stuff along the Gulf, so it has been very helpful.
Okay. Good enough then.
Yeah. A follow-up to that. We were talking to our crude traders about that. Taking crude from Corpus to Louisiana by U.S. Flag is about $2 a barrel, is about the same as foreign flag into Canada at $2 a barrel. It is kind of amazing.
Okay. Thanks very much for your help, guys.
All right. Take care, Ed.
Thank you. Our next question is from Doug Terreson of ISI. Please go ahead.
Congratulations on great results, everybody.
Hey. Thanks, Doug.
Bill, the delivered cost advantage for U.S. exporters is pretty clear, but just to clarify something you said a minute ago, did you say that your exports were a little weaker recently? If I heard that correctly, were there regional markets that were taking less product and why, or was it something else?
In the third quarter, our distillate exports were down from the second and down from what we expect in the fourth.
Okay.
That had to do with the ARB. It had to do with inventories. There was just a lot of reasons.
Also, the hurricane outage on the Gulf Coast.
Gene's right. We had the hurricane on the Gulf Coast as well.
Okay.
What happened is the domestic markets were very strong.
Yep.
The ARB wasn't open.
Sure.
We run on economics.
High-quality problem. Also, in California, you have been very consistent over the years with your views on the regulatory regime. When you make your strategic assessment on your positions out there, is it the compliance cost for the new standards in 2013 or 2015 that represent the greatest concern, or is it something more broad? Either way, is there an order of magnitude that you can give us as it relates to cost structure that would be likely related to the new regulations in California?
Well, it is an excellent question. Actually, this AB 32, so the cap-and-trade program that is starting now, and the Low Carbon Fuel Standard that tend to restrict which types of crudes you can run, these programs are all starting. The basic issue on low profitability on the West Coast has actually been crude sourcing. Do people have an advantaged crude source? Secondly, we still have over 10% unemployment in California. California is 2/3 of the pack. When you start to look at this, demand is down and there is too much refining capacity. You see this, Doug, and as the others on the call see, when there is an operating issue in California, the market quickly balances. Margins improve.
When everybody is back and running, we all tend to run down to cash cost.
Right.
As you would imagine, that is what happens. My concern and the concern of Valero and our management team here is longer term, the policies that are being discussed, the way they are talking about implementing them is bad, as I said earlier, for people, for business, and certainly for our industry. That is a longer term concern. The shorter term is really just basic supply and demand in a very sluggish economy in the West Coast.
Okay. Those are all good answers. Thanks a lot.
Thank you. Our next question is from Faisel Khan of Citigroup. Please go ahead.
Thanks. Good morning. Just a quick question on the Northeast market. We saw pretty wide basis differentials in the Northeast this last quarter. Just trying to figure out exactly how much product you guys are pushing into the Northeast. You talked about the ARB closing, but I wonder if you can elaborate a little bit more in terms of how much gasoline you were pushing into the Northeast to take advantage of that wide basis differential that we saw.
I don't think we would have that number. Remember, we tend to sell in the Gulf Coast markets and into the Southeast. Canada services its local market and has been able, as I said a few minutes ago, put some barrels into New York Harbor. We're not per se pushing anything domestically into the East Coast. From Pembroke, we export to the U.S. East Coast.
Yep.
I don't think I know that number.
The only thing I'd add, we do sell to other people that ship on the Colonial Pipeline, and they may be taking our barrels East Coast, but it's after we've already relinquished control.
Okay. Understood. You're selling the barrels at the Gulf Coast and somebody else is moving those barrels farther north and taking advantage of that differential to some degree.
They have pipeline space on the pipeline, so I guess that is right.
Okay.
Now, we would have gotten advantage of it for Pembroke.
Okay, understood.
All right.
Thank you.
Thank you. Our next question is from Paul Sankey of Deutsche Bank. Please go ahead.
Hi, everyone. Apologies for being a little bit out of the loop here. I am phoning from downtown Manhattan. Bill, on the hydrocrackers, when will be the first quarter for each hydrocracker of complete uptime, if you want? When do we now expect them to be running at full operations?
Port Arthur, the full quarter would be the first quarter of 2013.
So that would be a full quarter?
Full quarter. We expect to be up in December. At St. Charles, to answer your question, the first full quarter might be the third quarter, but we expect to be up in April. Okay? But I'm answering your question.
Right, so the first
Full quarter, it'll be the third quarter of St. Charles.
Right. Then you, sorry.
If things go a little better, we could have the second quarter, but as I've said, I don't know when you joined the call, these are very large projects for us and we're getting them done, and we're getting them done safely.
Yeah. You've been pretty clear with the guidance on what they'll make based on some fairly conservative assumptions. Could you just remind me what those would be if the guidance still remains the same, what your expectation for, let's say, the quarterly or annual earnings will be for each unit or for each project? Then if you could also roll that forward, if possible, into what they would be making in the current environment, that would be great.
Ashley may have some numbers, but we typically have been giving you guides. We give you all the assumptions in our appendix of our presentations, but it's about $1 billion worth of EBITDA. We give you all the assumptions, and you can see it when we have a case. I think it was $1.2 billion. We had another one, and I don't know what it would be today, but it's $1 billion of EBITDA, and we think they're going to contribute over a dollar share to our earnings.
Yeah.
Remember, it's natural gas to hydrogen to distillates primarily, and we have a good distillate crack as well.
Obviously, the main thing is just to get them running. Again, I just
On that, we all agree, but we're going to do it in a very orderly manner here.
Surely. Forgive me. You increased your CapEx guidance for next year? I know that's a bit of a Mickey Mouse question, but could you just confirm what went on with the CapEx numbers? I don't have full access to information here.
Now, Paul, my opinion is, and I got the question earlier, we did not increase our guidance. I have said all along, $2 billion - $2.5 billion.
Right.
All we are doing here is saying we are at $2.5 billion. In that $2.5 billion is $188 million that has to do with retail. Assuming that we proceed with the separation of retail, and we are saying if that all happens, it is a second quarter event, late first quarter, early second quarter, then that amount of the capital would come down programmed here for spending.
Yeah. I was listening to [inaudible]. You have kicked around some numbers as for what we could assume, I know it is early, but for 2014. Assuming that you are going to basically pursue a strategy now more oriented towards capital limitation and more towards cash return to shareholders.
Well, I would say that in 2013, we have given you the guidance, and it has been consistent with what we have been saying here for the last six months. We have said that we want to have a dividend yield that is among the highest with our peer group. I am not giving any guidance for 2014.
Okay. Just an observation that Sandy, I think, is going to have a pretty significant demand impact. If you can imagine, there's no traffic lights right now on Manhattan, which obviously conjures up a nightmarish image. At the same time, there's so few cars around that it's actually more or less safe to drive. I guess again, you've made some observations on your best guess of what the impact will be, right?
Well, I don't think we would know any more than you. You're very astute at this. Obviously, the refineries either shut down or reduced significantly. But the facts are demand is going to be way off as well. I don't think we would have any better insight at this point than you do. Obviously, demand is off, as well as the refineries. I will say this, at least reading some of the commentary, and this is good for people and everything, that some of the refineries did not incur any damage.
Yeah. What I would think is that because the PADD 1 is essentially import-dependent from other places, that the demand impact is more important than the supply impact, which doesn't seem that bad, but.
That's correct.
Yeah. Well, thanks for taking the question, guys. Thank you.
Sure. Paul reminds me, for all of you on the call here with this Hurricane Sandy, we thank you all for calling in, and we hope you didn't incur any damage or your loved ones or families. Hope everything's okay as you get your power back and everything else that goes with these.
Okay. Our next question is from Chi Chow of Macquarie Capital. Please go ahead.
Great. Thank you. Back on the retail separation. Bill, in the event of a spin-off to shareholders, does Valero intend to retain any interest in that new retail entity?
We are working all options as you would expect us to. If we did, it would be in the financing vein, but we are today looking at cases of complete separation. We have financing options.
Okay. I guess there is some chatter from the credit agencies when you made the announcement on possible changes to their ratings for Valero with the separation of retail. Are you concerned about that at all? Have you had further discussions with the agencies? Can you talk a little bit about that?
Sure. Yes, one of the agencies did have some concern, and as we get our case solidified here, we will go in and visit with them and show them our numbers. We ended the quarter with $2.5 billion in cash, so I think we are very strong financially. Our net debt to cap is 20%. We are going to go in, and we will show them our numbers, and we will have the discussion that you would expect us to have.
Okay. In the event of any changes, does that change your position on buybacks going forward?
Well, I don't know the answer to the first question.
Right.
We think our stock is undervalued.
Okay.
I've also consistently, and Mike has said this as well, and Ashley, we believe with our size and the way we deal with our suppliers, that having investment-grade debt rating is extremely important to our business.
Right. Okay. Thanks for that. On your comments on the growth CapEx, you mentioned you've got some projects looking at increasing crude throughput capacity. Do you have any details on the specific plants and incremental capacity you're contemplating?
No, but these would only be in situations where we are out of balance with feedstocks, so that we, for instance, at Corpus Christi, when you look at our capacity relative to our crude, our conversion capacity relative to our crude capacity, it is out of balance. Yet now we are in a world where there is a lot more crude oil production coming at us locally that is advantaged. Instead of buying imported feedstocks, we need to be looking at generating our own feedstocks. So we have quite a study going on, for instance, at Corpus Christi and our Houston refinery, where at the Houston refinery, we have a very large cat cracker, yet we do not have a lot of crude capacity.
These are the things that tie to our whole strategy statement that I spoke about earlier, where we look at things that continue to, in essence, lower our overall cost to produce from the womb to the tomb. Those are the kind of things we are looking at. Now, the key, we have talked about it for about two years. We are getting closer to getting some of these permits, but we have said we wanted to expand McKee, and that has been out there, and I think you guys are tired of hearing me talk about it. But we have broken the project into two pieces. There is an energy project, but there is a crude expansion piece, and we do not have the permit for the crude expansion piece, and it is tied into perpetuity.
Yeah. That makes a lot of sense. Okay. Thanks for the comments, Bill.
Okay, Christine, we are ready for another question.
Fantastic. Our next question is from Harry Mateer of Barclays. Please go ahead.
Hi, guys.
Harry.
It sounds like you think your financial leverage is at an appropriate level. Do you see scope for further debt reduction? I guess related to that, how should we be thinking about the, I guess it's $480 million of maturities in the first half of next year. Are you thinking that's a use of cash or more likely to be refinanced?
No, our plan today would be to take out the $480 million. Like $180 million's in January?
Right. $300 million in June.
$300 million in June, July. Our plan today is to take it out. That will take our long-term debt down to $6.5 billion. Yes, we will be very strong financially. That is our plan for that specific item. You asked general debt. We do not have any other debt that we find economic to call or to redeem. In 2014, we only have $200 million of debt that is due. In our particular case, we do not have debt that we can go out and retire economically. We do the $480 million, and 2014, we do the $200 million, but that is where we are.
Got it. Thanks very much.
Thank you. Our next question is a follow-up from Doug Leggate of Bank of America. Please go ahead.
Hey. Sorry, guys, for the follow-up. It is a very quick one, Bill. I wanted to come back to AB 32. I know it is a bit of a thorn in your side, but in the event that you have to incur meaningful capital expenditure, at what point would you have to start implementing those projects? In other words, how early before 2020 does this actually become an issue for spending? If you could quantify it, that would be really appreciated.
Okay, I am going to answer you, Doug, that there. We are all whispering here. There is no capital per se. Part of the regulation is 1/3 of your power costs is going to come from renewables in 2020. Our cost in California today for power is $0.12 per kilowatt, and that is like three times the cost of McKee. As you go to these renewables, and this would be at Wilmington, so L.A., as you go toward this direction, our power costs will increase more because renewables are not economic. We have some options to generate our own power and are looking at that project. As a philosophy, right now, Valero is very reluctant to spend any capital in California. The other piece of this, to give you the whole nine yards, we generate hydrogen at our Benicia refinery.
The facts are we could build another hydrogen plant there that would be $200 million-$300 million and would reduce our carbon footprint. Again, I would say those are out in the future here because quite frankly, these rules are not even set yet. At least some people in California are now starting to talk about the financial impact this is going to have in the state on everybody. I think some of it remains to be seen. Generally speaking, there are no capital. There are expenditures if you have to start paying for tailpipe carbon and certainly our stationary source. I do not mind saying, I think the last number we have, our California stationary source is like 3.7 million metric tons a year, so you can start figuring out those kind of numbers as well.
All it is going to do is we are going to pass it through.
Got it. That is really helpful, Bill. Thanks.
Uh-huh. Well
And we- Sorry.
No, go ahead.
I was just going to say, we have no further questions at this time, so I'll now turn the call back over to Ashley Smith.
Let me just say to everybody, because we know that a lot of you on the East Coast had issues. So thank you for making an effort to join our call. As I said earlier, we hope that you have not incurred too much damage to your home or any of your friends or relatives.
Yes. Thanks, Bill. We wish all you guys in the Northeast a safe and speedy recovery back to your normal situation. Thank you for listening to the call. If you have any questions or follow-up, just call the IR department. Thank you very much.
Thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect.