Welcome to the Valero Energy Corporation report 2013 Second Quarter Conference Call. My name is Larissa 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 this conference is being recorded.
Now, I would like to turn the call over to Mr. Ashley Smith, the Vice President of Investor Relations. Sir, you may begin.
Thank you, Larissa. Good morning and welcome to Valero Energy Corporation's second quarter 2013 earnings conference call. With me today are Bill Klesse, our Chairman and CEO; Mike Ciskowski, our CFO; Joe Gorder, President and COO; 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 described in our filings with the SEC. Okay, as noted in the release, we reported second quarter 2013 earnings of $466 million or $0.85 per share. The results include after-tax charges to general and administrative expenses of $20 million or $0.04 per share, and income tax expense of $9 million or $0.01 per share, both related to the May 1 spinoff of CST Brands to Valero stockholders. In addition, the results include after-tax charges to G&A expenses of $34 million related to various environmental and legal matters.
Second quarter 2013 operating income was $808 million versus operating income of $1.4 billion in the second quarter of 2012. The decrease was mainly due to lower refining margins in each of our operating regions. Our second quarter 2013 refining throughput margin of $9.26/bbl was over $1/bbl lower versus the second quarter 2012 margin of $10.63 /bbl . The decrease was partly due to significantly lower discounts for heavy sour crude oil. For example, the Maya crude oil discounts of Brent crude oil decreased by $4.40 /bbl from the second quarter of 2012 to the second quarter of 2013. Fortunately, the Maya discount has improved by more than $3 or over $3 /bbl , with July month-to-date discounts to Brent of nearly $8.20 /bbl .
Also contributing to the decrease in margins were the lower discounts for medium sour crude oil and light crude oil. For example, the Mars crude oil discounts of Brent crude oil decreased by $0.69/bbl in the second quarter of 2013 compared to the second quarter of 2012. For light crude oil on the Gulf Coast, the LLS crude oil was a slight discount to Brent crude oil in the second quarter of 2012 versus a premium in the second quarter of 2013 for an increase of about $1.80 /bbl . In addition, the refining throughput margin was negatively impacted by the higher cost of Renewable Identification Numbers, or RINs, needed to comply with the U.S. Federal Renewable Fuel Standard. For the second quarter of 2013, the reported cost to comply were $125 million versus $58 million for the second quarter of 2012.
Given the recent escalation in RINs prices, we now estimate our cost to comply with the Renewable Fuel Standard to be in the range of $600 million to $800 million for the full year 2013. Another factor that affected refining margins was the higher cost of natural gas. Natural gas prices increased from $2.24 / MMBtu in the second quarter of 2012 to $4/ MMBtu in the second quarter of 2013. In addition to affecting our operating expenses, this increase impacts our cost of sales due to our use of hydrogen, which is produced from natural gas. So far in the third quarter, natural gas prices have favorably decreased about $0.40/ MMBtu versus last quarter.
Our second quarter 2013 refining throughput volumes averaged 2.6 million bbl per day for a decrease of 52,000 bbl per day from the second quarter of 2012, caused mainly by turnarounds and planned maintenance at our Quebec City, McKee, Port Arthur, and Norco refineries. Refining cash operating expenses in the second quarter of 2013 were $3.82 /bbl , which was higher than second quarter of 2012 due mainly to higher energy costs. I would like to highlight several other items in our refining operations. First, the new hydrocracker at Port Arthur has continued to perform well and contribute to earnings. In the second quarter of 2013, we estimate the new Port Arthur hydrocracker contributed approximately $80 million in EBITDA, with the throughput rates nearly at capacity and achieving high conversion rates.
The contribution is slightly lower than last quarter due to changes in market prices for key drivers such as higher natural gas prices, lower naphtha values and lower butane values during summer RVP gasoline blending season. Using 2012 average prices, we estimate EBITDA would have been approximately $120 million. We look forward to the contribution from the recently completed St. Charles hydrocracker, which is essentially a clone of the Port Arthur unit. Earlier in July, the St. Charles hydrocracker experienced a smooth and successful startup and is now running at planned rates. As a reminder, both of these hydrocrackers were designed to take advantage of the current environment of relatively high crude oil prices, strong diesel margins, and inexpensive natural gas. This is also consistent with our strategy to increase production of high-quality diesel.
Also at the St. Charles refinery, the Diamond Green Diesel joint venture biofuels plant started up at the end of June. Throughout July, we have been ramping up rates. This plant is designed to produce approximately 9,300 bbl per day of renewable diesel from low-quality recycled cooking oils and fats using refinery hydroprocessing technology. The project is a 50/50 joint venture between Valero and Darling Ingredients, a leading gatherer of used cooking oils and animal fats. Valero's retail segment reported $39 million of operating income in the second quarter of 2013 prior to the May 1 spinoff of CST Brands. Subsequent to May 1, Valero reported its equity interest in the earnings of CST Brands as part of other income. As a result of entering into long-term fuel supply agreements, CST Brands became our largest wholesale customer.
Our ethanol segment reported operating income of $95 million in the second quarter of 2013, an increase of $90 million from the second quarter of 2012, mainly due to higher gross margins per gallon and higher production volumes. Production averaged 3.5 million gallons per day in the second quarter of 2013, for an increase of 156,000 gallons per day compared to the second quarter of 2012. The increase in production volumes was mainly due to the economic incentive of higher gross margins per gallon. In the second quarter of 2013, general and administrative expenses, excluding corporate depreciation, were $233 million. Included in this were pre-tax charges of $52 million, or $34 million after taxes, for increases to environmental reserves related to non-operating sites and legal reserves and pre-tax charges of $30 million, or $20 million after taxes, related to costs incurred to effect the spinoff of CST Brands.
In the second quarter of 2013, net interest expense was $78 million. Total depreciation and amortization expense was $405 million, and the effective tax rate was 37%. Regarding cash flows in the second quarter of 2013, capital expenditures were $796 million, including $162 million for turnarounds in catalysts. We returned $364 million in cash to our stockholders by paying $109 million in dividends and by purchasing 6.5 million shares of Valero common stock for $255 million. In addition, Valero paid off $300 million worth of 4.75% notes that matured in June, and we received approximately $550 million of net cash from the CST Brands transaction. At the end of the second quarter of 2013, we had approximately $3 billion remaining under our stock purchase authorizations.
With respect to our balance sheet at the end of the quarter, cash was $2.4 billion, total debt was $6.6 billion, our debt to capitalization ratio net of cash was 18.8%, and we had over $6 billion of available liquidity in addition to cash. We maintain our guidance for full year 2013 capital expenditures of approximately $2.85 billion, which includes turnarounds in catalysts. For 2014, we estimate capital spending, including catalysts and turnarounds, to be in the range of $2.5 billion-$3 billion. Returning cash to stockholders remains a high priority, and we are balancing this with opportunities to create value by strategically investing in logistics assets, hydrocracking, petrochemicals, and processing cost-advantaged lighter crude oil. Our premise is to capture the competitive advantages provided by the growing supply of cost-advantaged crude oil and natural gas in the U.S. and Canada.
Along these lines, we are also evaluating potential petrochemical investments that will leverage our existing assets to upgrade the value of abundant and growing supplies of natural gas and natural gas liquids. Lastly, we are evaluating the formation of a master limited partnership for our logistics assets. Okay, for modeling our third quarter operations, you should expect refinery throughput volumes to fall within the following ranges: U.S. Gulf Coast at 1.5 million to 1.55 million bbl per day, U.S. Midcontinent at 420,000 to 440,000 bbl per day, the U.S. West Coast at 270,000 to 280,000 bbl per day, and North Atlantic at 470,000 to 490,000 bbl per day. We expect refining cash operating expenses in the third quarter to be around $3.85 /bbl .
For our ethanol operations in the third quarter, we expect total production volumes of 3.45 million gallons per day, 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 third quarter, we expect G&A expense, excluding depreciation, to be around $160 million, and net interest expense should be about $100 million. Total depreciation and amortization expense in the third quarter should be around $420 million, and our effective tax rate in the third quarter should be approximately 35%.
Okay, Larissa, we have concluded our opening remarks. We will now open the call to questions. During this segment, we request that our callers limit each turn in the queue to two questions. After those two questions, callers may rejoin the queue with additional questions.
Thank you. We will now begin the question and answer session. If you have a question, please press star then one on your touchtone 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 touchtone phone. The first question is from Jeff Dietert from Simmons.
Good morning.
Morning, Jeff.
I'm sure there will probably be a long list of these, but I wanted to start with RINs, and one of the struggles I'm going through is, are blenders passing through the cost of RINs into the retail prices? Does it vary by region? What are the major considerations with regard to whether or not these RINs costs are getting passed through to the retail level?
Well, Jeff, this is Joe. It's a great question. We're trying to figure the same thing out ourselves. I would tell you that we look at it on a regular basis, and it's very difficult to quantify whether or not we're seeing the effect of the RINs in the cracks. We think we might be, but we're not 100% sure. I do know that if you look at our customers, there are some out there that are able to capture this, and there are some that aren't. Everybody's interested in somehow capturing this. The real question for us going forward is how much of this actually gets passed through into the marketplace and how much doesn't? Because it's a legitimate expense for us.
As we've mentioned, $600 million-$800 million is a big hit, and we'd like to be recapturing it. We're just not sure whether we are or not.
There's been press reports that have talked about blenders in the Gulf Coast reducing the price of blended gasoline in order to try to shift more gasoline sales through the blended stream rather than selling RBOB, perhaps into Colonial Pipeline and then it gets blended up in the Northeast. Have you seen evidence of this activity on the Gulf Coast? I guess the risk is if you discount your blended gasoline, you lose the value on your traditional gasoline blended sales. I don't know how much you might be able to shift over from RBOB sales to blended sales.
This is Klesse. Trying to get a handle on this issue is obviously very difficult. Joe gave you a couple of our perceptions as to the market and our estimate of cost. I guess I need to remind you that we're no longer in the retail business, so we're not focused on the street. That's CST Brands and our other operations. We're a wholesaler. Valero is obviously trying to pass it through where we can. We're obviously trying to recapture it where we can. Our opinion is we are getting some of it in the crack, but we're not getting all of it. Then we can have a debate whether we're getting 50%, 25%, but we think we're getting some in the crack, but not all of it.
Having said all that, Valero is going to maintain a competitive or be competitive to our wholesale branded customers where we capture the RIN. We will stay competitive. If in fact the street and these other people are taking it on the street, we're going to be competitive for our customers.
Thanks, Bill. Thanks, Joe.
Thanks, Jeff.
Thank you. The next question is from Evan Calio from Morgan Stanley.
Hey, good morning, guys.
Morning, Evan.
Yeah, maybe as a first question, just to follow up to kind of keep the RIN conversation moving. I know, Bill, you've been front and center in the RIN conversation, and I read portions of your testimony in Washington last week. I guess my question is, as you run your system, do you make operating decisions based upon a fully loaded kind of RIN economic analysis of each asset? The question is: Would Valero or the industry potentially see economically induced RIN cuts based upon RIN cost and margins, et cetera, particularly as you move into the seasonally weaker fourth quarter?
I t's a prospective question. Today, with the gasoline cracks where they are at the peak of the gasoline season, and we're primarily talking about gasoline, then I would say that you're not seeing it because we have good cracks. But part of that question was, do we include that in our economics? And the answer is yes. As we look down the road into the fourth quarter, I don't know what the world will look like, but it is turning into a cost to manufacture for a company, certainly for the independent refining segment of the industry.
Great. That's helpful. Thanks. For a second question on CapEx, I know this is the first time you're providing 2014 CapEx, which looks flat ex CST to 2013. Can you discuss how you think about overall CapEx levels, the new project returns versus potential share back, and I guess this would be outside of MLP-able assets?
Well, our goals continue to be, as I've stated over the years, we're going to maintain a safe operation. We're going to maintain our investment-grade rating. We're going to hold a little more cash. These are the things that I have continually said. We are investing in reliability. We think in this world you have to be reliable. So what the company can do to support our people in the refineries by investment, we're doing. This is a long-term capital investment business, and the marketplace has given us these opportunities because I know people are questioning methanol, and you see some comments on petrochemicals. The marketplace has given us this. They've given us low natural gas, giving us the potential for very inexpensive butylenes, which obviously can be converted to gasoline.
Valero has the wherewithal, the expertise, the talented people to be able to construct and operate these type of plants. We have sustainable competitive advantages by extensions and bolt-ons to our existing assets, and these are sustainable. I get to be an old guy, and I look at what management does, and I think part of management's job is to take our cash flow and to look at our alternatives. Do we have projects that will give our shareholders value, growth over the long term? If we do, and we look at our stock and how we think our stock is priced, if we do have these, then we should pursue them for our shareholder. If we don't, we return cash. I think this management team has done a very good job at this, frankly.
Over the years, we've bought a lot of our stock. There was a lot of stock issued in the acquisition period of Valero's history, and we've bought a lot of stock back over the years. We raised our dividend. We got caught by the Great Recession, just like a lot of people and had to regroup. Once we got past 2009 and 2010, we've gotten back on the same path we were on before of returning cash to the shareholder. We do continue to think our stock is inexpensive, and we know that many of our shareholders are looking for yield anywhere they can get it. We do think the marketplace has given us some opportunities. We match it all up. We've bought in the last 2.5 years 41 million shares. We spent about $1.2 billion on share repurchases.
I'll probably get criticized from a few guys because some of those shares were bought at higher prices. We've raised our dividend numerous times, and I've made comments to the investment community that when we have the hydrocrackers done, management will look at the dividend and make a recommendation to our board. We've done that. Methanol has Ashley's gotten some feedback from some of you that questioning that. Valero is very uniquely positioned at our St. Charles refinery. We have a lot of hydrogen production capability. We can pull this syngas off these plants. We can build a methanol plant for half of what a grassroots methanol plant can be built for. With all the hydrogen capability of our own plants and third parties, we think we have an opportunity here to add significant shareholder value.
I feel strongly that this is our job, and whether it is this or alkylation or adding some crude capacity to run light sweet crudes, which we do not have at some of our plants. We certainly do not want to be buying feedstocks when I am absolutely certain the light sweet crude is going to be very long on the Gulf Coast. These are the type of jobs I think that are clearly in our shareholders' interest, but it has to be a long-term thought process because basically, just about anything we are doing anymore with permitting and stuff takes us four-five years. That is kind of how we look at it.
That is very helpful. Just a quick follow-up, and I will leave it there. Within 2014, again, for CapEx, are the categories of spending similar to 2013 in terms of growth versus maintenance and your MLP-able EBITDA growth rate, if you will?
Yes, because some of those projects we are talking about, we will not spend that much anyway. We get the rail cars coming in, the logistics is still, all those projects are still, significant part of that spending is next year.
Great. Thanks, guys.
Thank you. The next question comes from Robert Kessler from Tudor, Pickering, Holt.
Hi. Good morning, guys. Two questions for me on transportation economics and logistics assets. One on barge traffic. Your recent presentation highlighted 20,000-30,000 bbl a day in barge deliveries in the Gulf Coast. I am curious if you have any more color on the pace of increase there and from where and to where you are moving. Presumably, you are moving west to east, but I am curious if the volumes have picked up and what you are seeing in the market for barges on the coast. Are you getting into a tight market situation there? Then I have got a question about rail cars as well.
Yeah, Rob, this is Joe. Our barge volumes have been pretty consistent. I would say if you look at everything, we are moving probably 90,000 bbl a day. We barge sweet crude into Houston. We barge sweet crude into Meraux. Memphis receives Bakken that will come up from St. James from barge periodically. St. Charles is receiving Cold Lake, so we are taking heavy sour from Hardisty down there, and then we have a little bit of barge volume around Corpus. So, no major change there as far as our volumes go. Okay? That is all I have there, so.
Okay. Thanks for that. If you wanted to pick up additional barges, say, in the spot market, your sense is they would be available for you?
Yeah, I think in the spot market, it is a snug market. Barges are being highly utilized, and Jones Act vessels, which you could move products or crude on, are very tight, and the prices have gone up on those. There is not an abundant supply, but what we are seeing is, and hearing from the barging companies, is they have got so many barges under construction that we are going to find ourselves with adequate supply going forward.
Okay, thanks for that. On rail cars, obviously, the changing dynamics of the spreads of late have, let us say, marginalized rail car transportation economics in the short term. Just putting that in context with your capital program, you have previously stated plans for significant expenditures on rail car purchases. I think, in fact, that $850 million is the single largest of the spending buckets you have outlined in your investor presentations. I know that is for optionality in feedstock and the like, but it sort of begs the question about the possibility of marginalized rail cars sitting idle in the portfolio down the road. How do you think about that potential scenario in your overall capital budgeting process?
Well, there are two things I would say. You are right, the volume has come off, and a lot of it has to do with what we have seen with Brent-WTI coming in so tight. That has affected it. That is going to vary, and we expect that that discount will open up again. The thing that we get with rail cars is you get tremendous optionality in where you move volumes. We are railing, we are actually railing now some bitumen down to Port Arthur, and that was not in our plan, but we have been able to get that, and we are taking it across a commercial dock or a commercial terminal down there. If we look out a little bit longer term, Valero has over 6,000 rail cars that we currently lease. We use them to move asphalt, we use them to move LPGs.
What we are adding to our fleet, in a worst-case scenario, we would go ahead and displace these leased rail cars and use the ones that we purchased. We still feel good about our decision to go ahead and get these cars. I guess the fact that we have leased cars provides us a hedge on the downside, but we fully expect that as these markets go back to a more normal pricing, which we expect a WTI discount to go back out to $7 relative to Gulf Coast. Bakken will open up again, and I think we are going to see more normal discounts, which will put the rail cars right back in the market.
Understood. Thanks, Joe.
Thank you. The next question is from Doug Terreson from ISI.
Good morning, everybody.
Morning, Doug.
Bill, returning to your comments a few minutes ago about your meetings with Congress last week, and specifically on the Renewable Fuel Standard, I wanted to see if you would comment on whether you feel that the industry is making progress in this area and having its position understood and the implications for consumers. Also any updated opinion that you may have on whether changes might be ahead in this area, and also what you think they might be. Just a progress update on where we're headed with this.
Well, I think everyone on the call understands the RINs issue, and the assumptions when the 2005 and then the 2007 law were passed are very different today than before. The issue boils down to just a few things. Cellulosic is not available. There's none on the EPA's website. Everyone says there's going to be a little cellulosic production this year, but it's totally uneconomic as well. It was clearly a let's pass a law and they will come, and it hasn't happened. The other part of the regulation that is clearly you pass part of this advanced biofuels in the sense of the ethanol piece. You got cellulosic. Then the other part of it is, it encourages you or you have to buy Brazilian sugarcane ethanol or somebody's sugarcane ethanol. We have a law that encourages you to import over producing domestically.
Then on top of all it is, gasoline demand has not continued to grow. It's actually down and now flat. The whole thing is screwed up. That's why I said the other day, it needs to be redone. I'm supporting the industry position. I accept that. It needs to be redone because Valero is a little bit unique in that we are a significant ethanol producer, and we also are a significant renewable diesel producer. We think E10 is part of the fuel mix. We think E85 is part of the fuel mix. We have no issues with renewable or biodiesel. We think that's all fine. Some of this technology is pretty darn good. But the EPA solution of going to E15 is not practical.
There are no facilities. Even the service station people are saying they do not know about their tanks and lines. There is hardly any certified pumps. You have the car warranties. I understand some of the 2013 car warranties say it is okay, but there is a whole lot of cars out there besides this. The whole thing needs to be redone. The whole thing is basically with RINs is now, as I got quoted everywhere, it is out of control.
RINs were in the preamble of the EPA's regulations that they were not going to be significant. They were there to give the industry flexibility and to give the EPA a way to monitor, and now it has become a huge issue. It just needs to be completely redone. Where do I think it is going? Well, the EPA does not seem to be able to do anything, it is a White House or Congress conversation. I think the only way the White House will move is they get enough political pressure, frankly, from consumers, because at the end of the day, the consumer is going to pay for this.
Right.
They get enough pressure from consumers or the option that you see happening, there will be some bills introduced here, is over in Congress, in the House and in the Senate, where people are at least understanding that the basis of the law are not appropriate anymore. Yet, there will be some compromise. I am optimistic that we're going to get something out of Congress, then the president will have to make a decision. Is it backtracking or is it just fixing a problem? The earlier question is the reality. This is very unfair on the street because you have winners and losers at retail. Clearly in the refining segment, this is hurting the independent refiner. It's not hurting the majors.
You actually are hurting the independent guys. Is that what you really want to happen? I think we'll get some congressional action, but I'm not sure you're going to see anything this year.
Okay. Then on methanol, the outlook for that business is pretty positive for the next several years. You talked about some of the rationale for the new plant. But I wanted to see if you'd elaborate on the competitive advantages and the synergies that you referred to with some of your existing operations. Also, what do you guys plan to do with the product once you manufacture it? I recognize it's a ways out, but if you could just cover those, that'd be great.
N ow you're jumping from the ethanol business to the petrochemicals?
I am. Ethanol to methanol?
Yeah. From ethanol to methanol, okay. We think on ethanol, we just think it's part of the mix, and we think we have a decent business there, and our people are doing a fine job. I remember the old saying of the Renewable Fuels Association, "Pigs get fat and hogs get slaughtered.
We've got a good business there and everybody, corn prices are up, farmland is up. It's part of the mix. It's accepted by the consumer. I think some balance needs to get worked into this. On methanol, because we have our own hydrogen plants at St. Charles, we're able to strip the syngas before we finish and make hydrogen. We can take this syngas, we really don't have to build the front end of a methanol plant.
Right.
Because there is a lot of supply capability and additional capability coming into the plants, when you look at the whole steam sink, everything that you have around this is why I'm saying we think that we'll be able to build this plant for about half of what a grassroots plant, 60% of a grassroots plant. The other thing is we used to be in this business. We were in a joint venture down in Houston. Then it all shut down when natural gas prices were going up. Obviously, it was part of the MTBE business as well to use methanol to do that. But methanol is a way to move methane.
In a liquid form, if you think about it. We just think it's a nice little bolt-on, and we'll develop it a little further, but we felt it important to get it out into the marketplace that Valero was looking at this.
Okay, great. Thanks a lot.
Thank you. The next question is from Paul Cheng from Barclays.
Hey, guys. Good morning.
Good morning.
Maybe this is for Joe or maybe it is for Bill. Bill, I was looking at. I am trying to understand between the difference in the ethanol business, how you invoice your customer in terms of, say, in the reforming gasoline, when you invoice it, you will have, say, what is you charge for the output and what you charge for ethanol as a pass-through. Is that really that much different that we cannot move into the same system related to RINs? I mean, you could have two invoices, right? If your customer want to buy the full-blown reforming gasoline including ethanol, so you will have the invoice that with the output and then also that a separate item as ethanol. If they just want to buy the net gasoline with output without ethanol, so you have that, and then you have a charge of the RIN.
Given that every single refiner who sell to someone without ethanol have to pay for that RIN, it seems like it is just part of the cost of your pass-through, yet by doing it this way, you have the benefit to crystallize and make it very transparent what the consumer ultimately is paying for that. As you say, Congress not going to do anything until they get the public outcry from consumer, and that will help the process. Secondly, that it also make it, I think that, rather easy so that we do not get confused, at least in the investment community, that how much is being pass-through or not pass-through. Is there any hurdle or obstacle why the industry, and including you guys as the leader, why not moving into that?
Well, I will let Joe and Gene add to this, but remember when you blend it, that is when you can separate the RIN. Theoretically, the RIN has no value till you blend it. Now it is all of a sudden a value. Because you cannot get if you do not count the carryover from 2012, because you cannot get to the mandated volume, you are short RINs in the market. You are just short. Now, I understand you are asking about a whole pricing mechanism here. But RINs have taken on a life of their own. They are a market in and of themselves now. At the rack, you have to be competitive. We sell ethanol at the market price. We sell gasoline at the market price. If the whole industry moves to some different pricing relationship, I am sure you are correct.
Unless the industry moves to that, you cannot capture it.
Well, because, I mean, Bill, that seems like it is exactly what happened in 2005, 2006, when we start moving into the E10. There is a lot of confusion, and it never really separate out ethanol as a separate item in the invoice. But by 2009, I think the whole industry moved. I just curious that, is there anything stopping because everyone selling to their customer without the attachment of ethanol need to recuperate. It seems like that is also fair because then the guy that who buying the full reforming gasoline, then they do not pay for the RIN.
Yeah. I mean, Paul, Bill answered it, I think, correctly.
You guys have an answer to this?
No. I do not know.
I agree. It's a competitive process, and if you try to keep the RIN and another supplier that's in the terminal is going to give the RIN to the customer, you're uncompetitive. It's all got to balance out. It's a very fungible market out there, whether it be at the spot level or at the wholesale level.
I understand. But what I'm saying is that you make it crystalline, transparent for everyone to see and to know that what is that price that they are paying. We don't have the confusion.
Well, I think it's something we can kick around, Paul. Clearly, we're just not there yet. We'd have to think through what the competitive implications are.
On a second question then. Bill, just curious that the $2.5 billion-$3 billion for next year for the CapEx, is that the new norm for the company going forward on at least for the next several years? I mean, I think last year that we've been talking about in the $2 billion-$2.5 billion. So has that now changed into this $2.5 billion and $3 billion? If that's the case, how's that impacting in terms of your outlook on the raising your regular dividend payout?
Well, I've never given longer term guidance than about two years out. I have said that I thought 2014 would be in the $2.5 billion range previously, and all we've done here is say, "Hey, it's $2.5 billion to $3 billion." To me, we're still in the range. We're still in our budgeting for next year. Whether this is the new norm or not, I don't know. I think it depends on whether or not we believe we'll add value through some of these discretionary projects. I've said several times that our stay in business, what I'll call the whole maintenance end of the business, turnaround, regulatory, all of that seems to run somewhere in the $1.6 billion to $2 billion range.
On top of that, we have this discretionary area. But your main question is, it's about returning cash to the shareholder. I think that if we have projects that add greater value, we're going to pursue them. If we don't, we're going to return the cash to the shareholder. I don't see that as one bit changed from what this management team has been doing.
All right. Thank you.
Thank you. The next question is from Roger Read from Wells Fargo.
Yeah, good morning.
Morning, Roger.
I guess maybe just to change the subject a little bit. Light heavies obviously had an impact on Q2. Can you help us understand as we're looking at Q3 where if you measure by LLS, light heavy spread's pretty attractive. If you measure it by Brent or WTI, not so much. What are you seeing move out there, and what do you think really will drive the market here over the next, well, let's just say through year-end in terms of the most important marker on the light side of that argument?
You mean, which would be more important, like a Brent or an LLS or a WTI?
Yeah. How LLS fits in terms of driving the Gulf Coast market there.
All right. Roger, if we think about what has happened in this quarter, obviously we had Brent-WTI come in in a material way, and we saw LLS move out and get priced at a more significant premium to Brent. A lot of that has to do with the simple fact that we ended up being shorter in the Gulf Coast on light sweet crudes than perhaps the market anticipated. We have said all along that the pricing of sweet crudes in the Gulf is going to be dependent on the quantity of domestic crude that is there. We saw that we did have a bit of short supply, and there was a host of reasons for it. We had syn crude outages in Canada that reduced the volume. We got BP Whiting still running light sweet crude, which has supported Bakken prices at Clearbrook.
Bakken is pricing up in the field at an LLS plus transportation or adjusted for transportation, which is making it expensive, but it is expensive because it was in tight supply. I think as we look forward into the third and the fourth quarters of this year, we are going to have more takeaway capacity out of Cushing and out of the Permian that is going to bring those barrels to the Gulf. I think that you will see more volume coming on stream and moving into Cushing. The inventory draws that we saw will probably stabilize here a little bit. What is that do to the overall crude markets? I think you are going to see the light suites. Our view is that LLS will trade down, and we will trade at a discount to Brent longer term.
I think we will see the WTI spread back out to maybe a $6-$8 discount. I think what we will see, the medium sours will adjust to price themselves into the refinery. Then we are getting some relief on the heavy sour discounts now. The Mexicans have adjusted the K factor as aggressively as they can over the last several months, and they adjusted at $1.90, and that will take effect on August 1st, which will increase the discounts on the Maya, which affects, of course, all the other heavy sours. I think as we look at the we saw all the discounts on crude come in in the second quarter. I think we are going to see them start to move back out in the third and the fourth quarters.
Okay. That is helpful. The unrelated second question, probably more for you, Bill. Getting back to the CapEx versus dividend versus share repo evaluation. What are the rough returns you are looking for? Or what are the various ways you analyze what makes the most sense for Valero to do at a given moment in terms of investing in the methanol plant versus, say, a more aggressive share repo program or accelerated, maybe I should say, rather than aggressive?
Well, so many of these plants are bolt-ons or extensions of our business. Because you are capitalizing on the whole refinery that is already there, these returns are all north of 25%, on all of them. These are IRRs. We get into a huge conversation here of what is our cost of equity. I have even had it with a lot of you that are on the call. We look at it, and we try to balance. What you have really seen with this management team, I keep going back to this, is we bought our shares every single year that we have been as part of this management, except 2009 and 2010. The other component here is next year, we only have $200 million of debt that matures, and the year after that, we only have $500 million of debt that matures.
We also see that we have ample cash flow coming at us as well. I think some of these projects are very good returns. We look at that. We look at where our equity is priced. It is obviously down from where it was. Do not forget, we spun off to the shareholders at CST as well. I think we are very shareholder-focused here, and the only caveat I really stick on it is, it is long term. You have got to think what we are looking at long term shareholder value, not tomorrow afternoon. [crosstalk].
Okay.
We want a dividend that sustains, that we can sustain.
Okay. When you are looking at the share repo, it is not necessarily a It is more free cash flow driven than it is a return analysis? In other words, you are not going to worry so much about the share price at a given moment as you are that is part of what you are doing, or is there more to it than that?
No, that would be correct. Back a couple of years ago, we made a decision we were not going to buy any refineries because we thought they were too high priced, and we turned around and had a very significant share repurchase. Yes, if we have free cash flow, we have enough cash where we set our cash position solid, we are going to maintain this investment grade rating, then yes, we are going to return the cash to the shareholder.
Okay, thank you.
Thank you. The next question is from Doug Leggate from Bank of America.
Thanks, fellas. Good morning.
Good morning.
Morning. Maybe I could just change tack again a little bit to the MLP. I know you've kind of suggested now that you're probably moving forward here, but you stuck to this $50 million to $100 million of EBITDA. But as we look through your presentation, it looks like there's a fair amount of MLP-related expenditure. Can you help us a little bit with how you see the scale of that EBITDA ultimately and what the kind of timeline is to get there?
Well, we have said, and I think this was 2012 assets kind of, that we had $50 million to $100 million of EBITDA. That's probably the range of where we're looking to go out initially. As Mike Ciskowski is running this project for us here, he tells me that getting everything done, this is probably a first quarter of 2014 project, subject to, of course, our board. We're doing all of that. Obviously, we're adding a lot of projects, so pipelines, rail cars, all terminal enhancements, so rail facilities to unload, and all of these assets are MLP-able. What we have said is our focus would be in the sense of a terminalling and distribution MLP, because some people have asked us about other assets.
We said, "Well, our focus is more there." Obviously, we have many more potential drop-downs going forward.
Okay. It doesn't sound like you want to be drawn in a number, Bill, but just to keep it in context, it looks like you're spending about $1.7 billion over the next It says five years in the presentation, but is it really five years, or is that a little quicker than that?
It would be quicker than that.
Okay, great stuff. We can figure it out from there. Last one from me really is to go back to the RIN question, and it's really just on your guidance that you gave for the full year. If I'm not mistaken, you talked sort of $500 million to $750 million before, but RIN prices were like $0.75. Now they're up 60% from there, and you're barely above the top end of that range in your guidance. Can you help us understand why we're not getting a kind of proratable impact? It sounds like there's not really a lot of change in your cost, even though the RIN cost has doubled. I'll leave it there. Thanks.
Well, part of it has to do with where we bought these RINs and our position in the whole process. Plus, there's assumptions in our numbers as to export volumes, how much we're capturing, and all of that. That's based in there as well. But this is the range that we're operating in now, $600 million -$800 million . But clearly, if it's $1.50 a RIN, we're at the high end of the range. But we're only in July.
Right. But what I am trying to figure out is that your previous range with the high end was $750 million, and the RIN price was $0.75. Now the RIN price is $1.36, and your high end is only up $50 million. Why only such a modest increase?
Well, that was at the high end. I had a range of four, and I was probably at the low end. I think you just have to accept that we are not misleading you. This is how we are viewing it. You guys are asking us for guidance, and I am saying to you at, okay, $1.36, I was using $1.48 or something. But at these higher numbers, we will be at the high side of our range.
Got it.
But it has to do with our position as to when we bought a lot of these. There is a serious timing component involved here.
This is for 2013. Does it change dramatically in 2014? Does it change significantly?
Absolutely, it would change. Remember when we first started this, they were 75, and in January or February, they were still $0.05. Then they started moving up. They went to $1. They pulled back to the $0.60, $0.70, then they go back up. But next year, it would be a much larger number at $1.50 a RIN.
Got it.
Then we will get into the conversation, well, how much a RIN is going to be in 2014 because you are totally unfeasible.
Right.
I mean, hopefully.
Okay, I will leave it there, Bill.
No, seriously, because you have the carryover from 2012, so that is the big debate this year. But you are going to have to carry from 2013 into 2014. You can carry in 20%, but there are not going to be enough RINs around. It is totally not feasible next year.
All right, Bill. Thanks a lot. Appreciate it.
Thank you. The next question comes from Paul Sankey from Deutsche Bank.
Hi, good morning, everyone.
Hello, good morning, Paul.
Morning, Paul.
Howdy. Thanks a lot for the early CapEx guidance. We appreciate that. Bill, you mentioned really part of my question, which was the $1.62 billion that you have of ongoing stay in business CapEx. I guess[crosstalk].
Well, our DD&A is running about $1.6 billion to $1.7 billion. $1.7 billion? And I think it's very unrealistic to assume we don't have to spend DD&A to maintain our assets.
Got you. Effectively one way of looking at this is you've effectively doubled your growth CapEx at the margin. We're coming off two huge projects in the past year or so that have come online. I'm just wondering what the components are of the new relatively high number for growth CapEx. Could you list the biggest, I don't know, several projects that you're going to be investing in? Thanks.
Paul, the best guidance we can provide right now about those details would be on slide 19 of our latest IR presentation, which we presented earlier this month. That is focused on 2013, but the 2014 details are largely in line with that. As we get later in 2013, and we complete our strategic planning process, we will be able to hone that and give you the specific chunks. It is very similar. It is basically a continuation of spending on existing processes or existing projects.
Keep in mind, as Bill said earlier, they are long-term projects. I know it takes you guys a second to update your model, but it actually takes years to get permits and construction and do all these things and to spend the money. In order to achieve the returns Bill talked about earlier, it does take some time. That is why there is generally going to be continuation of existing projects.
On slide 32, in that same handout, we give a little EBITDAs with some of the projects as well. Okay? So you can piece together how we are looking at it.
We will update that later this year as we go through our planning process and complete that.
I do not think you are referring to Deutsche Bank models, by the way there, Ashley , but what are you looking for from a planning, thinking about how you decide on these investments? I am looking at your cash flows at a low in 2009 of a little bit under $2 billion, maybe last year, $5 billion. Is that how we think about it? We have been asking this question in various ways on this call, obviously, but I am just wondering. Another way of looking at this is that you have effectively doubled your growth CapEx at the margin against expectations. You could have effectively doubled your free cash flow, especially in a high-risk RINs environment. I am just trying to drill down into why we are spending so much money, basically.
Well, if you look at the logistics capital, that is kind of been intact. I will just try to add clarity here. The place where I am sure some of you guys are wrestling with is in this whole petrochemical methanol area. Our view is that the marketplace is giving companies like us a huge opportunity to add a lot of value for our shareholder. We expect low-cost natural gas. That is why the hydrocrackers look so darn good. That is why,
Is that sub $4 that you are assuming there, Bill? Sub $4?
No, but sub $5. We think the number needs to be a little higher long term so that the drilling industry can make a reasonable return. There seems to be a debate sub $4 how much return they are getting. If you get into the $5 range, we believe they can make a return. You guys would know more about that, I suppose, than us. Then you look at the butanes coming. We have alkylation units within our refineries right now. These things just look like something where Valero and its shareholders can really benefit.
I get you.
We are studying it, and we are getting it out there, so at least you guys know these are the things that we are looking at.
I get you. Can you give us a sense for how much more light sweet crude you think you will be able to run, let's say, by the end of 2014?
Yeah. Ashley can because our projects won't quite be done.
Yeah. By 2014, not a whole lot more. It's not till the toppers are done in early 2015 that we'd be able to increase those. And those, I think[crosstalk].
It's not Quebec in 2014.
Yeah.
It's going to be 2016.
Yeah. You are really talking. It is not until 2015 conversation.
But if you take the Houston plan, it is 70.
Yeah.
The Corpus is 90. We are looking at Port Arthur, where we have an idle crude tower or excess crude tower, excess space in the tower, probably 50,000 to 75,000. Quebec is already a sweet crude refinery, but we will be subbing in North American crude more and more as we go through time. At Meraux, we will be running more lighter crude there as well. Those are projects that are significant. Then we have these little change this exchanger and add this deal here and re-pipe these projects going on too. But Ashley, I think he will give you a number here.
It is 160,000 bbl a day.
For those two?
For those two.
Not counting the other ones I just said. We'll pick up another 50 to 100 between Port Arthur and Meraux.
Okay. In closing for me, N15, how much more slight suite will be, if you like, a substitution, and how much more will be incremental throughput in what total? I'll leave it there. Thanks.
It is almost all incremental throughput. It is incremental throughput, but what it is backing out is our feedstock purchases. Remember, we buy Algerian resids, a lot of those that we bring directly into our units. We bring some other of these feedstocks in that basically go to the cats, and instead, we will be making a lot of our own gasoline.
Sorry, it is all incremental replacement. I am confused. Does it mean your overall capacity is higher at Valero?
The overall crude capacity will be higher. For sure.
By how much?
Not our throughput capacity.
Got you. Okay, that's great.
Remember, we run today, I guess officially, we'd say we're 2.3 million to 2.4 million bbl a day of crude, but we're 2.8 million to 2.9 million of throughput because we're buying these other items.
Yeah. I'm with you. I don't want to take up the whole call, but that's very helpful, and we'll come back potentially with more. Thanks a lot.
Okay.
Thank you. The next question comes from Arjun Murti from Goldman Sachs.
Thank you, and sorry for another follow-up on RINs, but if we look out to 2014, and agree with your comments on how unworkable the RFS looks, can you talk about to what degree you guys can crank up your exports to help offset some of your RIN obligation next year relative to what you might be doing this year?
Well, it depends on the cost of the RIN. You have to have a basic crack. Assuming we have a basic crack that says, "Hey, it's profitable to make those barrels," then you have, if RINs are $1.50, you technically have $0.15 a gallon here that you're playing around with. You can be very competitive going export versus the U.S. market.
Yeah.
But as far as ramping up.
Ramping up the exports?
If the industry is basically out of RINs next year, and you guys are on the coast who do have export capability, Congress is going to have to take action at some point here. But in the absence of that, it seems like you could have a very, very high RIN price well above where you are today. No one wants to shut in their units, which I guess is the other way to not have a RIN obligation. It would seem like exports is one of the outlets, and you guys would seem to have a better position to do that. But just trying to see if we can frame how much you could reduce your volumetric RIN obligation next year if it's a, whatever the right phrase is, very, very high RIN price, much higher than where we are right now.
All right. Arjun, let's assume that the market's out there for the barrels to be exported. And that ARB supports the exporting. Just as an example, we exported 70,000 bbl a day of gasoline in the second quarter, and we exported 170,000 bbl a day of diesel. Now, those numbers are what they are because we optimized the supply into the marketplace. We had a very strong market in PADD 2 because you had Joliet turnaround and Whiting turnaround, they were down. We were able to move barrels to that higher net back market. Barring that and saying that the market was demanding the barrels abroad, we could go to 225,000 bbl a day of gasoline and 280,000 bbl a day of diesel.
The projects that we've got underway to improve docks and tankage and segregations at the refineries would allow us to take it up beyond that going forward, particularly with the St. Charles hydrocracker coming on and the quality of the diesel fuels that we're getting out of St. Charles and Port Arthur. There is capacity.
I think Joe's giving you a capacity conversation. I don't think it's realistic because the industry is in the same boat. Yes, we're on the Gulf Coast, and we would have that capability, but so would other people. You get down to the basic, you got to have the basic cracks.
Yeah.
Yes, to the way you phrased your question, Joe answered you, yeah, we would have capability. Yes, we're on the Gulf Coast, so we could do that. But I would not want to lead you down a path that this would be a significant solution for us. I don't think so.
I appreciate. Yeah, go ahead.
Arjun, [audio distortion] this is Gene. I would just add that both of these solutions there, exporting more or reducing refinery runs, reduce supply. If demand really doesn't go down, which we don't think it is next year, you got to meet demand, which tells me it's ultimately got to be priced in on the cracks on a U.S. basis and maybe a lower basis for your exported barrels, but on a[crosstalk].
That to me would be the mechanism, right, by which you then get the true pass-through. Especially if the U.S. economy is recovering and the demand is there. Do you guys either supply less, which I don't think you do, but potentially export more? It's clearly a mechanism to get the pass-through. But I appreciate your candor in the answer. Thank you so much.
The next question is from Edward Westlake from Credit Suisse.
Hey, good morning. Yeah, obviously a lot going on in refining, lots of questions. I guess, the 2Q Gulf Coast was probably the weakest absolute number that we have seen for a long time. I guess, despite the first hydrocracker, that is also despite there is some cheap Eagle Ford coming into Corpus. Clearly light heavy is weak, but is there anything else material going on that we should focus on? I guess, if not, then as light heavy expands again over time, you should go back to a more normal capture?
Yeah, that is it. When you are referring to light heavy, are you talking about really the sour crudes versus the sweeter crudes in general?
Yes.
Because you are right. The discounts on all of those crudes relative to the sweet crudes were off, and we shipped this late. We ran about the same amount of heavy sour crude 2Q 2012 versus 2Q 2013. We ran quite a lot less medium sour, though, because it tended to be just out of the market. Now, on the heavy sour side, we do not price all of our heavy sour crudes off of Maya. We had some advantages there. But I do not know of anything else, Bill or Lane. I do not know of anything else going on in the Gulf other than that.
Well, we make a lot of other products and they are all moving around. But if you take our Port Arthur refinery, which runs Maya crude oils, it did very poorly in the second quarter.
Okay.
Even with its new hydrocracker.
Yeah. And that was due to the pricing of Maya just getting[crosstalk].
You can see it had a huge impact.
Then a second question, more broader around the Texas market, I guess. You have the Eagle Ford growing, some decent Permian well results recently. You have two major pipelines, probably more, coming down into Texas. Do you think there is a limit on the effective capacity of the industry to move those barrels over to Louisiana? Earlier you spoke about there being enough barges, but it feels like it is a lot of volume, and it could cause some stress. Any color on that would be helpful.
Well, I think as the volume comes into Houston eventually here, it has to move east. You are going to have Shell's pipeline running, which has a very high tariff, which is a lot higher than barges. I think you are going to see the barges, you are going to see assets come into play here because it has to move. It has to move along the coast. Then one of our competitors has signed a deal to ship it up to the East Coast by water as well. You are going to see it moving. To us, Houston is going to be the focal point of all of this.
In terms of obviously there is only a limit to how much light you can run, I guess, moves across. As you talk to your major suppliers, I am thinking the Mexicans, obviously there is mediums coming over from the Middle East. How do you think they are going to respond to the fact that not just yourselves, but the whole industry on the Gulf is going to be probably looking for less of their product?
Well, it remains to be seen, and there will be political considerations as well, because Valero, we buy from the Persian Gulf suppliers, and they have a stake in this market. Their crude is more medium than this light that we are talking about. This is not today's issue, and it is probably not tomorrow's. This is probably a 2015, 2016 conversation. But over time, the U.S. is going to have a lot more oil on the Gulf Coast, and I think the refining industry is going to figure out how to run it.
Thank you. That's very clear.
Thank you. The next question comes from Faisel Khan from Citigroup.
Good morning. It's Faisel from Citi.
Hey, Faisel.
Hey, Ashley. Just another ethanol question, I guess. How difficult would it be for you guys to increase your blending capability? I know you sell a certain amount of merchant volumes, and you blend some of your own volumes, but how difficult would it be to increase your blending capability, given your natural supply of ethanol and your production of gasoline?
Well, Faisel, we're looking at increasing it everywhere we can, as you would expect. For example, with the Diamond Green project, we're going to have a lot more renewable diesel that we can blend into the pool. But we're looking at every asset we have, and if it requires some modest investment to increase the blending capabilities there, we're going to do it. But generally said, we just don't have access to the terminaling assets to control blending of all the product that we produce. We are a merchant refiner, and we sell a lot at the flange of the refinery, and we just don't have the opportunity to blend that up.
Okay. Understood.
We're blending where we can, and diesel side is what Joe's talking about more because you have a customer base here.
Sure.
The customer base goes into a terminal. Everybody sees I guess, somebody said $1.36 RIN. I mean, i t's a matter of customers as well. So where we can, we've added facilities. Where we are, we're blending. But clearly, the marketplace is in disarray because at the wholesale racks, theoretically anyway, you've got all these different prices now.
Right. Fair enough.
We're trying to minimize. If the question is, are you trying to do things to minimize your exposure? The answer is absolutely.
Okay. Got it. And then just last question from me, I know the call's been going on for a while. On the potential investments in natural gas liquids, and also alkylate sort of investments, could you talk a little bit, in a little more granularity and what type of assets you're looking at building and where you're looking at doing that? Is it fractionation, and where would it be? Also on the alkylate side, where are you looking to increase your production of alkylate?
Well, so it's not fractionation per se with us. I answered this on the last call last April. I do not think we add value per se just to build a fractionator. But where Valero, we do not really have a competitive advantage over some of these guys, like Enterprise, for instance, who can come in and build a fractionator.
Sure.
What we do is we have alkylation units in all our refineries. Alkylates are great blend stock. When you look at how we make gasoline's a blend. If you remember that, it's made up of all these different components. As we look at our system, we believe we are going to have very inexpensive butanes. We have spent the last 10 years of our, maybe 15 years of our careers removing butanes from gasoline. But one way you can stick butane back into gasoline is by alkylating it or making a longer carbon chain.
As we see normals coming and converting them to butylenes and you see cheap or inexpensive isobutane, we just think this is a good option in a refinery to be able to increase the amount of that blend stock.
Makes sense. Where do you do that and what are the magnitude of investments you make to increase that capability?
Well, these alky units would be $200 million-$300 million. They would all be sulfuric acid. Valero would not build a new HF alky. As we look at our system, they would be on the Gulf Coast.
Okay. Understood. Thank you.
With one possible exception for a different reason.
Got it. Thanks, guys. I appreciate the time.
Sure. Thanks, Faisel.
Thank you. The next question is from Chi Chow from Macquarie Capital.
Hey, Chi Chow.
Hello. Hi, Bill. How you doing? I think you know who this is. Hey, just sorry to keep pounding this RIN issue, but Mike, can you tell us how the accounting works on your RIN purchase and how exactly does it flow through your P&L?
Sure. Our accounting is based on whatever our RINs deficit is, and we amortize in. We purchase forward. We have been purchasing forward a number of contracts, and we amortize that cost in as a deficit that's basically created.
Okay, great. Is that split by region as far as where that amortization goes in the cost of goods?
No, it's not. From a regional standpoint, we allocate all of that based on a throughput basis to the regions.
Okay, so it is split in each region by throughput.
Correct.
Okay. Got it. Thanks on that. Bill, I just want to clarify, I think you mentioned on one of the other questions, the $600 million- $800 million on the 2013 cost. Is that a net number? Net of some sort of pass-through assumption?
No, that is not a net number. That is just what the deficit would cost us.
Okay. Okay, good. Thanks for that. I guess a final question on rail movements. How do you think this Quebec rail car accident is going to impact crude by rail going forward? Is there going to be more regulation costs? Any thoughts on that?
This is Klesse. I do not think it will impact it in the sense of the extremes. I do think that you are not going to see one-person trains anymore. You are not going to see trains left sitting on the sidings here full of products. I think it is just one of those areas that people just had not focused on. This is a very tragic accident, and we all understand that. I think you are going to see more of the procedures. You are going to see a very strong review of procedures. I think you will see the cooperation increased in North America here between Canada and the U.S. on regulation, maybe on tank car design. You will see more on these bonnets, beeping them up.
I think also you will have a conversation that will pull the Mexicans into this as well. Railing crude oil, railing ethanol, railing distillers grain, railing corn, railing asphalt, propanes. They are all here. They are part of the distribution system. There will be procedural things that will change. This train was left alone. I do not think you are going to be leaving a train on the siding with nobody there anymore.
Yeah, sure. Not going forward.
Those kind of things will take a little time, but to me, that is where we will see more procedures, and maybe it is in the operating area.
You mentioned maybe changes in tank car design. Does that impact your deliveries at all going forward on your rail cars?
No, it would not, because there is no change now, right?
Right.
If it is, we strive all the time for safety and reliability, and if something happens, we will take a look at it.
Right. Okay. Thanks, Bill. Appreciate it.
Yep.
Thank you. The next question is from Allen Good from Morningstar.
Good morning. Just a question on the chemical investment follow-up. You mentioned some of the characteristics around St. Charles that made it attractive. When we look around your system, where are some of the other opportunities you think for additional chemical investments? If you do identify those, would you be willing to move forward with maybe several of these similar size investments at the same time?
Well, it is a very fair question, and we are looking at this because the marketplace is changing so quickly. I am of the belief that the United States can have a huge manufacturing and petrochemical resurgence here if our government would figure out how to get behind it. We look at the Gulf Coast plants. They are in the sense of our crown jewel assets. They give you access to the water because some products would be exported. Remember, Valero is already in the benzene, toluene, xylene business. We are already in the propylene business. We are in a lot of these businesses anyway. We are just talking about bolt them on, but they would be along the Gulf Coast.
Would we take on several projects at the same time? Sure. We have the capability, as other companies do, to manage projects in the capital spend level that we have guided you.
Okay, thanks. I guess the second question is, earlier you mentioned that you expect some of these crude differentials have narrowed in the first half of the year to widen back out later this year. Looking at your most recent presentation, you have a small list here of rail and barge projects that you anticipate to come online later this year, moving Gulf of Mexico crude to the Gulf Coast, the West Coast, and the North Atlantic region. If we are at the same situation here as far as differentials are concerned, I guess mainly being the WTI Brent, as we get into the third and fourth quarter where there is basically no differential, would you still expect some of those rail projects to come online and start delivering some of that crude via rail?
Or would you delay that into next year until we maybe get some more widening of the spread?
It would absolutely depend on some of our deals. But we are in business to make money, and if it is not economic to do something, we may have some fees we have to pay a few guys. But where we have to take it, we will have to do it and make the best of it. We try very hard to maintain optionality on these deals. Sure, if you do not have any spreads, you are going to optimize.
Is there a general WTI Brent spread or any other sort of spread we could use as maybe a rule of thumb to see whether some of these rail projects in general are economical for you?
Well, in the back of our handout, we have that big map where we made this price call 12- 18 months, and we said New York Harbor is where we see the equilibrium point between Brent and delivered sweet crudes into the harbor. You take Brent plus a couple of bucks for freight. We have been saying that is where a lot of this balance is on the East Coast. Then you back up from there. We think over time, you are going to have these differentials because the crude has got to move to the markets, and it has got to displace the foreign barrels. But sure, you can have a spot month or two or what is going on right now, but we do not believe they are going to last. We are in business for the long term.
Okay, great. Thank you.
In our appendix, we put all those numbers in there, and I think we say 12- 24 months is our price outlook. But the basis is the East Coast being equilibrium.
That's helpful. Thanks.
Gulf Coast, we think that LLS is several dollars below Brent.
Great. Thanks.
Thank you. The next question comes from Paul Cheng from Barclays.
Hey, guys. Just a real quick question. Bill, I know that you may not want to give us an absolute number, but what is the percent of your rail arrangement with the rail operator? Is it take or pay for the long term, or what percent is a 30-day rollover kind of deal?
I do not know if it is that I do not want to give it to you. I am not sure we know.
Well, we don't have a bunch of different phases.
Well, we have loading commitments for loans.
Well, yeah.
I think here we'll put something together. The railroad, we own the cars. Joe's point is, hey, you don't have that. But the reason I was hesitant on the previous question is we make some commitments to load cars at these third-party loading. At our own refinery, there are facilities, so there are no obligations. But we do have some fee commitments to load and a couple things like that, purchases of oil. We will put something together. It is relatively small, but once we get all our rail cars, we will have a $750 million investment in rail cars and a couple other hundred million in sidings. We want a return, too.
Sure. Secondly, on the Keystone XL Southern Leg, and also the Seaway 1 and 2, can you give us some rough idea what your take or pay commitment is on those?
Paul, we do not do that.
Okay. Final one. Bill, when we are looking at your dividend policy, when the board evaluates whether you are going to increase or not, is there a policy from management that this is an annual exercise, or is it a semi-annual, or is there really no policy at all?
Well, I would like to With the way you phrase your question, no policy at all.
No, means that, you may decide.
I think we are a little better than that. We raised our dividend in January, and I said that we would look at it, and management would have a recommendation. We have not had our board meeting yet this month, after we finish the hydrocrackers. We look at our balance, we look at our forecast, we look at our payout rate. I have said that Valero wants to be among the highest in dividends and returning cash to our shareholders of our peer group. We look at those guys as well.
I feel like there is more of a process, but we do not say the July board meeting is a dividend meeting. It is a dividend meeting with the board, but we do not say management is going to raise the dividend or something at the January meeting or the April meeting or the July. We go into it with us having looked at our forecast, where we think our cash is. Do we think we can sustain it? Then we make a recommendation to the board.
Thank you.
Thanks, Paul.
Thank you. We have no further questions.
Okay. Thank you, Larissa. I just want to thank everyone for listening to our call today. I believe we set a record for length. Thank you for that interest. Please visit our website or contact investor relations for additional information.
Thank you, ladies and gentlemen. This concludes this conference. Thank you for participating. You may now disconnect.