With this roundtable session. We have Valero for this session. Up here we have the Valero management team, and leading the Q&A or the discussion here, we have Bill Klesse, who is the Chairman and CEO of Valero. Bill began his 40-year career in the refining industry as an Engineer Trainee with Diamond Shamrock. Bill held roles of increasing responsibility over the years to eventually become Director of Corporate Development at Diamond Shamrock, and then Executive Vice President of Ultramar Diamond Shamrock Refining Operations.
After Valero acquired UDS in 2001, Bill became Executive Vice President of Refining and Commercial Operations. In 2003, he was named Valero's Chief Operating Officer, and then became CEO of Valero in 2006, and then eventually Chairman. We will just hear a few quick comments from Bill, and then we are going to go into our roundtable session Q&A, and I think we have a pretty active and interactive discussion, and keep it going from there. Bill, if you have a couple prepared remarks. Other than that, then we can go into Q&A. Thank you.
Okay. Well, thank you, Faisal. With me is Gene Edwards, our Executive Vice President, Chief Development Officer, Ashley Smith, who runs IR, and Matt Jackson, who is in IR. Just a couple of comments. There are some macro trends in this business. Clearly, there have been some refining closures in the Atlantic Basin. The place that is both U.S., Japan, Western Europe, are long refining, and that is part of how we view the business versus demand. Then you look at where are the weakest links.
The weakest links are Japan and Western Europe. Then if you just focus on the Atlantic Basin, you can say there have been some closures. You just saw Petit-Couronne in France finally did close after about two years. The U.S. then is very competitive primarily because of crude oil pricing and how we see the future, NGL pricing and how that plays into fuel supply. Natural gas makes the U.S. a very competitive place. Because of demand and our outlook for demand in the United States, which should improve a little with an improving economy, but primarily because of CAFE and other actions of the consumers, we really do not have increasing demand as part of our expectation for the future.
More cars, more people, but improving CAFE kind of makes it look something like this, pretty flat. You have to be able to export. That, with the U.S. being so competitive, we are able to take market share in the Atlantic Basin. In Valero's particular case, we have growth projects that are coming in that are truly adding earnings power to our company, and those projects are focused on distillates, and they are focused on converting natural gas, which goes to hydrogen, then to liquids.
In the two hydrocrackers, one that finished at the end of last year at Port Arthur, the second one that'll finish at the end of the second quarter here and start up in the third. They have a very strong component of profitability from gas to liquids. You look then at what's happening, and Valero has some growth projects that separates us, but then we have the macro trends that allow this business, for all of us in the refining segment, to be able to compete because exports are a key part of the future of the business. We've returned cash. In the last two years and four months, we've bought 37 million shares of our stock, paid a little over $1 billion. We've raised our dividends several times. Our capital spending has fallen from last year, and so our cash position is very strong.
Thanks, Bill. More recently, in the last few months, we've seen some extreme volatility in crude spreads and differentials. The heavy-light spreads have been moving around quite a bit. The Brent-WTI spreads are moving around quite a bit, and the LLS premiums of Brent has gone from discount to premium. Is what we're seeing today any different than what you guys are used to dealing with in the past? Are there things that are more difficult today with the current crude environment that make it more difficult to operate as a large-scale refinery?
Well, I don't think we have that many things that are different in crude costing into the refinery. Differentials, discounts, they always move around. The thing that is different in the history, at least that I've been associated with, is historically, you made your money in refining on your conversion units. You boil oil or fractionate oil, but you made your money conversion-wise. Good operations, safe, reliable operations, those type of things made you money. Today, because of where the oil is being found, location has taken on We're talking about the U.S. and North America.
Location has taken on a whole new significance in financial performance. So if God built your refinery in Kansas, you're loving it. If you're somewhere on the coast, it's not quite as good. So it's all about location, location, and what companies are having to do, like Valero and others, we have great location for a couple of our refineries, but the other ones we're having to build logistics, and that is to overcome the location handicap. The challenge for you, as investors is the location advantage already priced into the other stocks and is it coming more toward Valero? On specific differentials, Gene, have any comments?
Yeah, just a couple of comments, I guess on. Okay, sorry. A couple of comments just on Brent-WTI. We've always expected that spread would narrow, that $18, $20 was not sustainable, and we've always thought it would come into pipeline tariff. If you think about pipeline tariffs today, with the discount being $8 by the time you pay to Houston, and then also from Houston to St. James, with some kind of St. James discount, I think $8 is a sustainable type number is where I would call it. What's really swinging that too is LLS, though. I think what happened there, we had a squeeze going on about a month, six weeks ago, as everybody anticipated Seaway expansion bringing more light sweet crude to the Gulf Coast. I think people counted on that.
They didn't buy the imported sweets that they had been buying. What happened when the Seaway did not deliver as many barrels as they thought it would, it caused sweet crude to become tight, very tight there for a period, where the Louisiana refineries that were dependent on sweet crude didn't have the foreign, so they had to bid up LLS. It went from basically even to Brent to $5, $6 over Brent for a period of time. That's now self-correcting as we've gotten more sweet crude to the Gulf Coast, and the people who got squeezed on that probably didn't enjoy it very much.
So, now we've seen LLS come in to less than a dollar premium to Brent. Ultimately, I think that goes to a discount as more of this sweet crude continues to hit Houston and ultimately clear to St. James, either by Ho-Ho Pipeline or by water. That will continue to put pressure on the LLS market. Next year, I understand LLS is trading on the forward markets about $3 under Brent. Historically, it's been $2.50, probably over Brent plus freight.
So I think you're going to see a fundamental shift on the Gulf Coast by about $5 a barrel versus what we historically think about on LLS. So that's a huge advantage to a U.S. refiner versus a other Atlantic Basin refiner that's basically still buying Brent or North Sea or West African that basically lays in at Brent + $2.50 or something like that. Anyway, I think we have not really seen the benefit that historically, so I think it's still in front of us. I think it's coming because all the crude that is showing up.
Just to add, very important to what Gene says is where these price points are actually located because freight is the thing that is in between them. Brent is over in Europe. You really have to take the freight back to the U.S. If ultimately it is going to clear the New York Harbor, you could see how these numbers start to move around when you take LLS at St. James, Houston, you have WTI now, Cushing. The actual price point is key to the conversation.
Thanks, Bill and Gene. On this enormous or this new source of crude supply in North America, I guess if I look back historically, at the different crude prices for different grades of crude around the world, there used to be a quality differential that there is still the quality differential that we see with the global crudes. But in North America, there seems to be less of a quality differential. It seems to be more of a volumetric issue. There is all this volume coming to market, and it is just getting discounted based on logistics. When do you think, or do you think we will actually see some of these crudes get priced based on their quality, like we do all the international crudes? Is that anywhere near in the future or is that still pretty far off?
Well, I do believe that the basic premise of what you said is true. There is a volume component to all this oil moving. But it is still quality gets involved. For instance, at least yesterday, WTI at Midland was selling for more than WTI quoted Cushing. And that is because out of Midland, you are getting a neat barrel, one that you know your quality. For a refiner, we would much rather have a WTI out of Midland, even though it is higher priced than a WTI out of Cushing. Forget the tariffs for a moment. Just think about the quality.
If you think about getting Eagle Ford, things like that, where we actually get a neat barrel, it is very important to us. Many of the markets, whether it is Cushing, St. James, there is a lot of blending going on, and that does impact us, and we do try to adjust our feedstocks for the quality. In the oil field, the condensates, a lot of this are problems for the producer to dispose of, so there is a lot of blending into the oil. We don't really want those products either. So there is an increasing debate as to the stuff that we're getting at the refinery, but we prefer a neat barrel.
You want to add?
Yeah, I think our crude traders work with our optimization group all the time. They try to get experience with certain suppliers, certain fields, and recognizing there are quality differences, and they take that into account in the negotiation to try to get the highest margin barrel.
Rail, for instance, offers you the ability to get a neat barrel. So if you're buying a Bakken or something by rail or bitumen or certain crudes, you get what you paid for.
To touch on this a little bit more, it's interesting. I guess when some of this crude is getting to the Gulf, it gets blended, and there's a lot of companies that do crude blending on the midstream side, Enterprise and Oiltanking Partners and some of these other logistics companies. What you're saying is that you prefer that neat barrel versus one of these blended barrels. That's almost like a blended wine versus a pure grape. Is that what you're saying? Your operations prefer the neat barrel?
Well, what I'm saying is we want to get what we paid for.
Yeah.
If we bought a WTI barrel, we want a WTI barrel. We don't want some cocktail because it doesn't exactly always look like that. If you think about how crudes are purchased in the business, there's gravity adjustments, sulfur adjustments, BS&W adjustments, but there's not a lot of other adjustments. We buy crude from everybody. We have great relationships with everybody. Dumbbell crudes that look like WTI don't necessarily fit that well in a refinery. So we want to get what we pay for. We have processes, as Gene just mentioned, to try to make sure we do get what we pay for.
Can you also talk a little bit about your imported crude, your heavies and sours, your relationships with your Middle East suppliers and your Latin American suppliers. As more of this domestic crude is hitting the Gulf, are you backing out those imports? How do those relationships work over the foreseeable future given the crude production hitting the Gulf?
System-wide, Valero buys about 2 MMbpd of crude, and we buy another 500,000 barrels a day of other feedstocks. As a general statement, I would like to say our relationships with our suppliers are excellent. One reason they are excellent is we pay our bills. We have great relationships. Now, the second part of the question, of course, as the light crudes more and more are coming to the Gulf Coast, in Valero's case, the Gulf Coast, we are backing out imported sweets. Our Houston refinery now primarily is running domestic barrels. It runs Algerian resid. It runs all different types of foreign sweet crudes, and we still buy Algerian resid. If you go to our Three Rivers refinery, that used to be primarily a West African supplied refinery, and it runs Eagle Ford now and some other local crudes.
You can see this happening for us, and it will be happening for other companies on light sweet. If you just go back two years or so, 1.5 MMbpd of light sweet crude was coming into the U.S. Gulf Coast, and I think our numbers indicate that there is 117,000 bpd of light sweet coming into the Gulf Coast in the first couple of months of this year. That stuff has been backed out. As a general relationship with suppliers, I think it is good, but the light sweet crude is pushing stuff out.
Do you think that these suppliers are going to want to compete for market share in the U.S.? As you back out maybe some of your mediums and heavies as this Canadian crude hits the Gulf, do you think that that crude is going to compete to keep market share?
I do not know if they will compete for market share. There may be some political overtones with some countries that sell oil to the United States, but it gets down to economics. We are going to deal with the heavies. Valero is very supportive of wanting more heavy oil on the U.S. Gulf Coast. We are a consumer of heavy oil. We have a lot of coking operations. We are very supportive of Keystone Pipeline. We think the Canadian heavy should come to the United States where there is jobs, pay taxes, help communities. We think that is what should happen.
We have cokers already here that want that oil. Whether other countries that sell heavy oil into this market continue, that is their decision. Their alternatives would involve what? Freight. How this all works, who demands the oil, where it goes, I think remains to be seen. But we believe the heavy Canadians should come to the Gulf Coast. Then the other people, whether it is the Mexicans, the Colombians, the Brazilians, the Venezuelans, that still sell into this market, continue to put heavy in remains to be seen as how they decide. Other countries, we still run Middle East oils because you get into the medium sours. Those kind of things still come. What their strategy will be, I really do not know. For us, it is an economic decision.
Yeah.
The only thing on the sweet crude, I think they are clearly not trying to keep competing because they cannot. You can only push so much sweet crude to the U.S., and it is all domestic. So I think they are focused on Asia, if you look at West Africa and even North Sea to sell their crude there. But I agree with Bill, the medium sours and heavy sours will continue to come to the U.S. for the foreseeable future.
Okay. I just want to make sure I open it up to the audience here for Q&A. Go ahead. Sorry, go ahead. Right here. Yeah.
So on the topic of the excess of sweet crudes, how much sweet crude you are currently using a mix of sweet and light and heavy crudes. To what extent can you switch to using more light crude if there is more of it available, let us say, relative to heavy crudes from the U.S.?
Okay. First of all, we shifted really from a lot of foreign sweets to domestic. We hardly ran any domestic sweet just a few years ago. Even Three Rivers, like Bill said, was on foreign. We've already gone up to, I want to say, on the Gulf Coast, about 600,000 bpd . Then you add McKee and Ardmore, that's another 250,000 bpd . We've got a lot of capability already. Furthermore, you're looking at Quebec. We run 230,000 bpd of basically foreign sweet there. We're shifting all that to domestic as well with substantial discounts versus a foreign alternative.
I think just moving what we've got has been a big deal. Then we've got projects to build some toppers at Corpus in Houston. That'll be another 160,000 bpd combined. Then we got debottlenecks that we're looking at a couple of other refineries that could add some more. We are continuing to push that. I think you'll look and see we'll have capability of in excess of 1 million bpd by probably the end of next year to run domestic sweet crudes. We have been focusing on that end.
When we're talking domestic here, obviously we know Canada's Canada, but we're dealing in North America here. That's why for some that listened to our earnings call, where I said our Quebec refinery, which is a foreign-supplied refinery, would eventually be a North American-supplied refinery because we're involved in some of the pipeline reversals. We have a rail facility going in there. We just shipped some crude oil from the Gulf Coast to the Eagle Ford to the Quebec refinery. As we're going through time, that refinery will add, and you'll see the Canadian refineries in the eastern Canada here, I think will all eventually be North American-supplied refineries. Then you have the Gulf Coast situation. What I add to that, the world has changed dramatically with all this light sweet oil.
Valero was convinced four, five, six years ago that the future was processing of heavy oil, heavy sour oil. That's why we have the cokers. That's why we have all this. If you were going to build a grassroots refinery today, you would not build a coking refinery. You would build a light sweet refinery. Then what happens, we start trying to get into our heavy sour refineries, more light sweet crude. Our people use their ingenuity, like other companies' people use their ingenuity to get more into the mix. We change an exchanger. We get a permit and do the pre-flash. We work it. We take our vapors somewhere else in the refinery, and we keep figuring out ways to run more light sweet crudes in our heavy plants. But it does take some investment, as Gene mentioned, where we have announced two crude toppers.
I want you to understand why we do something like that. Historically, we made money on conversion. Now you're in a long crude market. That says you probably need to be generating your own feedstocks with oil in the U.S. Remember, once you make the feedstocks, they trade at world prices. You can't export crude, but world prices are for feedstocks. Now you have very good economics in the sense to boil oil. We have projects that'll start to get done over the next couple of years that will allow us to take more light sweet oil and generate feedstocks for some of the conversion units that used to purchase feedstocks.
Just having those big downstream units kind of enables you to do that. Is that a fair statement?
Well, you made your money on conversion units. If you look at Valero, and many of our competitors will be the same, we have large cat crackers. We have other units, yet crude is a small unit. In Houston, we have a 90,000 bpd or so crude unit. The plant is 150,000-bpd refinery. If you think of our Corpus Christi refinery, we run a lot of feedstocks. Our Wilmington refinery has about 80,000 of crude, but it's a 140,000-bpd refinery when you consider all the throughputs. That was done on purpose because you could buy feedstocks. But when you are long crude that's discounted versus feedstocks that are world price, you need to make your own feedstocks. That's why we have those projects.
Just so I understand, with some of these investments that Gene was talking about, what's the incremental amount of light sweet from here on out that you guys can take in the next, call it 12 - 24 months?
I think it would be a little longer than 12 or 24 months. Ashley, when are these projects? Press your button.
The two toppers are about 160,000 bpd of incremental light sweet crude. We have other projects beyond that, but they are further out and not fully disclosed yet.
Got it.
We do not have a total for the toppers.
The detail is in our handout in the appendix. I think we have details.
Okay. Seth, did you have a question? No. Okay, gotcha. Go ahead, please.
Can you talk a little bit about your thoughts about product demand going forward over the next three to five years? How do you guys see how you're currently configured versus where you see product demand going in the U.S.?
Sure. I am going to broaden it to the world because I think part of the future of U.S. refining is exporting. If I deal just with the first part of your question, I would say to you, gasoline demand, which has not recovered at all and has actually continued to be down from the Great Recession, and peaked in 2007, I actually think will continue to rally with a better economy. People drive as long as pricing stays where we are today. Over time, CAFE will impact this so that our demand projections for gasoline in the U.S. are relatively flat. Seasonals may be up a little in the near couple of years, but then trends off to 2020. So more cars, more people, but CAFE offsets. On diesel, it has not recovered from the Great Recession, dropped about 500,000 bpd .
You look at diesel demand in the U.S., I'll just round here and say 3.6 MMbpd . We see diesel over time increasing, but increasing slowly. I think we've seen that consumers, whether it's industrial consumers or retail-type consumers, they change some of their habits. They're much more efficient. We see low growth. That's why I said I need to broaden it, because we do not say to you domestic North American growth is a big part of our future. Now if you take relatively flat, you already know there's too much refining capacity relative to domestic demand in North America even. Then you step out and you say we're going to be able to export.
Now if you start thinking about the numbers, 3.6 MMbpd of U.S. diesel demand, and we're exporting about, on average, about 1 MMbpd of exports. So 20%-25% of diesel production's being exported. We think the world will continue to grow in diesel. If you think about the numbers around, diesel's about a 27-million-barrel-a-day business. Gasoline's about a 23-million-barrel-a-day business in the world. Gasoline's growing in the world, whether it's Mexico, Colombia, Brazil, the gasoline demand continues to grow.
Middle East, the Far East, diesel demand is also growing. It's growing at probably on average at 2X. 2012 was an exception. Diesel demand will grow faster than gasoline demand. So 27 MMbpd , we see it growing. China, the Far East, South America, again, the Middle East, some growth in Africa. You have the growth components in the world. Thus, Valero, we have geared very much our output to make more diesel because this is how we see it. We don't see gasoline growing that rapidly. Gasoline exports out of the U.S., roughly 500,000 bpd , primarily from the Gulf Coast.
We're importing gasoline into the Northeast, so that's a little bit in balance, but over time, we see more exports. We are changing our portfolio to make more diesel. In another year, probably another two years, Valero will be a big exception for a North American refiner in that over our whole system, we'll be about 1:1 of gasoline to diesel ratio. Very, very different than others because all the investments we're really doing are really making more diesel fuel. We see exports as very important to the industry. The weak link in this conversation, in our opinion, is the Western European refiner. They are very long refining, and so we see that as the place where there'll still be rationalization.
What about resid? You didn't mention that. Do you think that it's weak, it's strong? How do you see resid markets in the next four or five years?
Do you have an opinion?
Well, resid, it has been fairly tight by historical standards because you used to think about resid being 30% discounts to crude, and these discounts are more like, well, today, I think resid discount to Brent's like $15 or 15%. I think it's going to stay in that range. I think you see more and more shifts away from resid is growing slower than light products. So I think directionally, that light products will outperform resid, which will keep some pressure on it. On the other hand, there's lots of coking capacity that's been added and everything, and most of the growth is in sweet crude. So I kind of see it stabilizing. The Maya-type crudes at around 10% or 12% of crude and the resid being somewhere around 15% of a discount to crude, which is pretty strong by historic standards.
Can I ask another question on demand? I'd love to hear perspectives on natural gas and the consumer government investment appetite for using that as a transport fuel in North America.
Natural gas. This is really a North American conversation because this is where we have these on a BTU basis, very inexpensive fuel in the form of natural gas. We do not, in autos, really have much. We are a petroleum refiner, so we do not really see much inroads in automobiles here, primarily due to the lack of infrastructure. But secondarily, at least today, the engines cost more and a car does not really individuals do not drive enough to get a payout. I know we sell electric cars, which are totally not efficient. I mean, not economic either. We do not really see inroads into the auto fleet because of basic economics, but you lack the infrastructure. On trucking, it might be a little different, but remember the numbers I threw out earlier. 18-wheel trucking is 60%-65% of the distillate demand.
There, you could have economics as long as you had enough infrastructure built. There are people talking about it because the engine costs more, but they drive more miles. We would say you could get a payout. However, when we look at our numbers and look at the inroads that they would make there, we really only see this 20,000, 100,000 bpd , some small piece of the business. It is a North American conversation, so we do not really see it as taking huge amount of North American market share. I will not forget the railroads.
You had one of the railroads say they are going to convert six of their engines to LNG, and we will see how their test comes out. The railroad industry is really only a 200,000, 300,000-bpd business in the U.S., and I do not think We just do not see it taking that much market share. When you go back to the numbers I just got through saying, where the industry is exporting 1 MMbpd of diesel. We export 1,000,001. I just do not see it as a big issue in the foreseeable future. What could change?
There is Boone Pickens wants to do this, but they want you to pay for it. You got to decide if there was some other to overcome infrastructure conversations, well then things might change. The fixed-based operator, like the Frito-Lay , some of these guys, I think you will see them do some conversions where they drive enough miles with their small trucks and they have room in the back of the truck to put the tanks. But we are not in the auto transportation business or in just the transportation fuels business. We do not see it taking a lot of market share in the foreseeable future.
Bill, in the last 10 years or so, you guys have, maybe less than 10 years, you guys have made significant investments in your assets, to improve conversion capacity, improve reliability. You did so when a lot of people kind of weren't making those investments. Then we've seen some of those refiners eventually get shut down. As you think about your investments in this part of the cycle, what sort of things are you thinking about to keep your system competitive for the next cycle? I think that's the way you guys think about things, and it'd be helpful to kind of get your perspective on that.
There were a couple of components to that question. Valero obviously bought a lot of refineries, and many of the refineries we bought were in a distressed nature. They were underinvested, and thus, what does that mean? Well, stuff is dated and reliability's poor. We have invested, and we have numerous programs, and in our handout, you can see some of our mechanical availability, energy efficiency. We have made significant investments over the years to become a more safe, stable and reliable operation. That part of it. We have a goal to become a first quartile refiner. A few years ago, we were a third quartile refiner in the benchmarking in the industry. Very significant effort. Now that's one set of the investments.
I consider those to continue here in the sense of working reliability because in our industry, reliability almost leads everything. If you just envision if it's always working okay, usually you're going to be safer. You're going to be not on your flare. You're not going to have these community incidences. That's why we will continue to work that, and frankly, our industry works that. Now, how do we position for the future? Well, we're finishing these investments that we did on the hydrocrackers here in the second quarter, but we have a couple other projects. We already talked about the crude units, but also we're expanding our two hydrocrackers.
We bought the Meraux Refinery a couple years ago, and clearly that was bought to convert it to make more distillates, which we are in the process of doing, and that project should be done by sometime near the end of next year. We are going more to this 1:1 ratio, I said, making more distillates. The other thing that's happening, we spent the last 20 years of our careers trying to remove butanes from gasoline because of vapor pressure. Obviously, the NGLs are coming. We talk about oil, we talk about natural gas, but the natural gas liquids. Today you have ethane being reinjected in the natural gas. You got propane being exported. You've got all these butanes, pentanes, hexanes, heptanes coming. Those are going to eventually wind up, many of those, into the fuel systems. How do you handle butane?
You handle butanes through alkylation, where getting isobutane and isobutylene. You will wind up seeing those type of projects coming around refineries over time. Petrochemical industries are growing in the world, and the U.S. has a huge competitive advantage. I get questions a lot, "Well, does that mean you are going to start getting into condensate splitters?" I do not see us doing that because there are competitors out there that are better strategically positioned.
But around our refineries with naphthas, with products like that, I see that we have competitive advantages, and those are the type of things. All that said, Valero is very focused on returning cash to its shareholders. We have demonstrated that by buying stock, raising our dividends. We actually were doing this before the Great Recession. We have gotten ourselves back on track. We have a very strong balance sheet, and I think you should anticipate from Valero that you continue to see us returning cash to the shareholder as well.
Thank you, Bill. We appreciate the time. Thank you, Gene. Thank you, Ashley. Thank you, Matt.
Well, thank you, everybody, for being here.