Well, next up we have Valero. I am sure everyone in the room is very well aware of some of the dynamics going on in the North American crude market and some very strong results in the fourth quarter. Very happy to have Joe Gorder and Gary Simmons, who is also the head of crude trading, so I am sure there will be some questions that come up on the crude market. Thank you very much.
No, thanks very much, Ed, and thanks to all of you for sticking around here and joining us this morning for this discussion. Let me go ahead and begin with our safe harbor statement, which says that actual results could differ materially from our forward-looking statements. With that, let me begin talking about Valero. Valero is the world's largest independent refiner. We have 16 refineries with 2.9 million barrels per day of throughput capacity, and that excludes the Aruba refinery, which is shut down. In 2013, we IPO'd Valero Energy Partners, which is a traditional logistics MLP with 100% fee-based revenues. We have approximately 7,400 branded marketing sites. Nearly 1,900 of these belong to CST Brands, which is our former retail business, which I think many of you probably know we spun off in May of 2013.
We have one of the largest renewable fuels companies with 10 efficient corn ethanol plants with 78,000 barrels per day of production capacity. We also have a Diamond Green Diesel JV plant that has 9,300 barrels per day of renewable diesel production capacity. Finally, we have 10,000 employees. This map shows the geographic diversity of our operations. The teal-colored states are those that we have a wholesale presence in. Those with the V logo are where we have a branded wholesale presence.
You can see based on the legend on the lower left here, the refinery icons show that our plants are located all the way from the West Coast, down through the U.S. Gulf Coast, in the Mid-Continent, and then we have, of course, the plant in Quebec City, the Jean Gaulin Refinery, and then in Wales, we have the Pembroke Refinery. You can also see here the location of our headquarters in San Antonio, and then finally, the location of the Diamond Green Diesel plant, which is on the site of the St. Charles Refinery. The table on the lower right provides some additional detail by refinery of our system, and it provides the throughput capacity, crude capacity, and then the complexity index.
Now, our strategy is to enhance our returns and to increase long-term shareholder value, and we're going to do this by investing to take advantage of the North American resource boom. In addition, we're going to continue to unlock potential value of our existing assets. We're going to continue to pursue excellence in our operations, and we're going to continue to return cash to stockholders. I will cover these strategies in more detail with the subsequent slides. Now, some of the key market trends that are supporting these strategies include growth in the U.S. and Canadian oil, natural gas, and NGL production, which is really providing North American refiners with significant cost advantages. We also are seeing a market that's providing higher distillate margins due to the global demand growth.
Finally, we have very strong export markets, which are really supporting utilization rates and margins in the U.S. Gulf Coast. So this chart illustrates the growth in U.S. and Canadian crude production. As you can see, the largest growth comes from U.S. shale and heavy Canadian crude, which are the top two segments on these bar graphs. You can see the significant growth in North American production starting in 2010, going out to the forecast in 2020. Also on this chart, we have the line, and the line shows the imports of non-Canadian crude. You can see that since 2010, we've seen significant reductions in imported crude, primarily in the area of light sweet crude. Still plenty of heavy sour and medium sours coming in, but the light sweet crude has effectively been backed out on the Gulf Coast.
I think that shows in this chart. So what we take away here is clearly this growth provides an advantage for North American refiners and will continue to for some time. This is a chart that Gary talks from quite often when we talk about crude. It has a lot going on, but it does a very good job of illustrating our estimate of light crude discounts over the next 24 months as incremental production comes on stream and logistic solutions are implemented. Let me walk you through this. The ovals on the chart represent the range of crude price discounts relative to Brent, and the rectangles are the transportation costs from point to point. The base assumption here is that Brent's delivered into the U.S. East Coast, setting the marginal price for crude.
The prices in the other markets are adjusted to this basis based on transportation costs. So you can see we've got the arrow coming in from the right here into the U.S. East Coast. Crude delivered in at [Brent plus $2]. If you look at the rectangle just to the left, you see that U.S. East Coast rail is $14-$17 a barrel. You go over to where Bakken is produced in the Dakotas, and that would tell you that Bakken needs to price in the field there anywhere from $12-$15 off. If you follow the line down at about 5:00, you can see that going into Louisiana at St. James, you're going to deliver Brent in there for somewhere around zero to $3 off. Anyway, we use this to calibrate our thinking.
Now, the two major takeaways that we should get from this chart. Number one, you can see that the Mid-Continent and the U.S. Gulf Coast refiners are clearly advantaged from a crude cost perspective. The second thing, and it is not obvious here, but that as we see more light sweet crude supply being delivered into the U.S. Gulf Coast, it is pressuring the discounts on the medium and the heavy grades as they compete for space in the refineries. We expect that this is going to continue going forward. As you would expect, Valero has many projects underway to enable us to supply more cost-advantaged crude to our refineries. For example, in the Gulf Coast region, we are going to benefit as the pipelines continue to move the crudes in.
In addition to that, at the St. Charles refinery, we have a 20,000 barrel a day rail unloading facility that is going to come on stream in the first quarter of 2014. We will be bringing Canadian bitumen in by the second quarter of 2014 using our rail cars that we have purchased. Then we also bring barrels into St. Charles from our Hartford terminal. We have the ability to move 35,000 barrels a day by barge from that facility into St. Charles. At Port Arthur, we are working on a rail unloading facility, which will enable us to bring 70,000 barrels a day, and we expect to have that on stream fourth quarter of 2014.
Finally, at Corpus Christi, we are working on a crude export dock, which is going to be online third quarter of this year with 25,000 barrels a day of capacity initially, and that will go up to 50,000 barrels a day by the first quarter of 2015, when we get some additional tankage online. On the West Coast, at Benicia, we expect to deliver anywhere from 30,000- 50,000 barrels a day of crude via rail based on using an unloading facility that we are working on. That will be in place by first quarter of 2015, and that is somewhat dependent on the permitting process. Then in the North Atlantic region, at Quebec, we expect to be running 100% North American crude by the end of this year. It is really backing out foreign imports, which are delivered in at a much higher cost.
Currently, we are railing 30,000 barrels a day of crude in. We started that in August of 2013, and we will increase that to 60,000 barrels a day by year-end. We are also moving barrels by ship from the U.S. Gulf Coast up there using foreign flag vessels. Thus far, Gary and his team have delivered WTI, Bakken, and Eagle Ford into Quebec, and the refinery likes those crudes. Then finally, we are going to be a shipper on Enbridge's Line 9B. Those barrels will move on that pipeline into Montreal, where we will put them on a ship, shuttle it to Quebec. Based on Enbridge's timing for Line 9, we expect that to be ready to go by the fourth quarter of this year. Clearly, all of these projects are providing a cost advantage for us from a crude supply perspective.
Now, another advantage we enjoy is the lower cost of natural gas resulting from the significant production increases we've seen. For us, natural gas is a fuel, so it's an operating expense, but it's also a feedstock, and some of it rolls into cost of goods sold because we convert it to hydrogen as a feed. Now, Valero's refinery operations consume about 800,000 MMBtus per day of natural gas, and the chart below shows the financial benefit that we enjoy due to the lower costs we are experiencing. As you can see on the right here, the right bar shows that at $4 an MMBtu, we enjoy a $1.8 billion annual advantage over the guy in Europe who's paying $10 an MMBtu, and a $3.5 billion advantage over the Asian refiner that might be using LNG. Clearly, low-cost natural gas is a huge advantage for us.
Now, global distillate demand continues to grow, and as a result, we're experiencing much higher margins, which is one of the primary reasons that we invested so aggressively in hydrocracking. If you take a look at the chart on the lower left here, this shows U.S. Gulf Coast product margins as compared to Brent. You can see we show the gasoline margin and the diesel margin. Very clearly, the diesel margins were much stronger over the past five years and in 2013 than gasoline margins. You say, well, why is that the case? You look at the chart on the right, and you can see where demand is globally. Clearly, diesel demand globally is growing much more rapidly than gasoline demand is, at about 1.5 x rate. Although gasoline is growing, diesel's growing at a higher rate, and that's supporting these higher margins.
Now, U.S. refining is globally competitive, and it continues to take market share. The chart on the lower left shows that the U.S. has flipped from a net importer to a net exporter of products. This really provides a significant advantage to the U.S. Gulf Coast refineries who have the cost-advantaged crude and natural gas, but also because they have access to waters, and they're able to move products into growing markets. So that's contributed a lot to this shift in the trade. If you look at the chart on the lower right, it shows the higher utilization rates that are enjoyed by refineries in PADDs 2, 3, and 4, which are supported by the cost-advantaged crude and natural gas. This is refinery utilization. You can see very clearly the Rockies, Gulf Coast, and Midcontinent are advantaged. The East Coast and the West Coast are running at lower rates.
I saw that the EIA reported this morning that Western Europe has had dismal results, and their utilization rates are much lower with Italy around 63% and France at 68%. So Northwest Europe is really struggling here. Another point I'll make on this chart is that we see the utilization rates in Gulf Coast refining and having ready access to export markets really would support the fact that you're going to continue to run at higher utilization rates in the Gulf going forward. Now, global demand growth is important to refining margins. You can see from the bar chart below, the emerging markets, particularly Latin America, the Middle East, Africa, and Asia, are the driver of global petroleum demand growth. This is really good for us because our products are storable, they're transportable, and they're fungible.
As demand grows, we are able to take advantage of that by supplying products into these markets. Clearly refining is a global business and will continue to be so. We expect significant new global refining additions to come on stream over the next several years, particularly in Asia and the Middle East, where demand growth is very strong. However, we also believe that many of the announced projects are going to be smaller than announced. They are going to come later. We also believe that many of these projects are going to be shelved. We also believe that the less competitive refineries are going to continue to shut down. The chart below shows that the net refinery additions are more or less in line with the potential demand growth, which is illustrated with this red bar.
The bottom line from our perspective is that we do not expect significant deterioration of global refining margins, but we do really expect that the regions without cost-advantaged crude and natural gas are going to suffer and will be vulnerable to closure. Let us take a look at Valero's capital spending plan. As you can see, in 2013, we spent $2.7 billion, which was approximately $100 million less than the guidance that we provided, this did include $63 million for the retail business that we spun off. In 2014, we plan to spend about $3 billion, which about $1.5 billion is allocated to maintaining our refining, logistics, and ethanol assets. The remaining $1.5 billion is going to be invested in projects to facilitate the processing of cost-advantaged natural resources, I will speak more about that on this page.
This focuses specifically on our growth capital investments, you can see that they are really allocated into four key areas. The largest is logistics. The next largest is light sweet crude processing. These two areas comprise 72% of 2014's estimated growth spending. In addition to these investments, we are going to spend additional dollars on hydrocracking and then in projects that are going to allow us to upgrade natural gas and NGLs. To look at this a little more specifically, on the logistics side, we are investing to increase access to cost-advantaged crudes for our refineries and to increase our capability to export products and crude. We have purchased 5,320 rail cars that began delivery in the fourth quarter of 2012, we will receive the final cars in the second quarter of 2015.
About 55% of these cars are general purpose and 45% are coil-wrapped to allow us to move heavy crudes. One point I will make on this is that they are all 111A cars, which satisfy the most recent structural requirements. Just to point out that we have 1,800 of those in hand today that we are utilizing with the rest to come. We are also working on crude rail unloading terminals at Quebec, at St. Charles, at Port Arthur, and at our West Coast refineries. We are also focused on Quebec logistics. I mentioned earlier that we are going to be delivering crude oil via Enbridge's Line 9, investments here include those in terminaling, tankage, and ships to satisfy our ability to move those barrels. We are also working on projects to export products and to export crude. I mentioned volumes moving out of Corpus Christi previously.
We're working on a dock project there that we'll have on stream in the third quarter, so we'll begin moving additional volumes to Quebec at that point in time. Finally, we have other investments that include pipes, barges, ships, tanks, and docks at various facilities. One point I'll share on this is that most of these logistics projects that we're investing in are candidates to drop to the MLP, which I'll speak about now. As many of you know, in December, we completed the IPO of Valero Energy Partners. We're planning to manage it as a traditional logistics MLP with 100% fee-based revenues. Valero did retain significant ownership and control of VLP. We own almost 69% of the common and subordinated units. We own 100% of the general partnership and all the associated IDRs, and we plan to retain control of this entity.
It's going to be the primary vehicle for us to grow our logistics assets. We did state on the roadshow that we're planning to grow distributions at around 20% a year for the next several years, and then we'll probably taper off a bit after that. We expect to complete our first drop in the third quarter of 2014, so probably the early part of that quarter. One of the key points relative to VLP is that Valero did retain a significant portfolio of logistics assets, which are going to facilitate subsequent drops and should allow us to continue to grow at the rates we've stated for some period of time. The initial assets we put in VLP are the Port Arthur Logistics System, the McKee Product System, and the Memphis Logistics System.
These assets were selected due to their high integration into these three key refineries, their long history of reliable and ratable operations, and then finally, the fact that they were very high quality and well-maintained assets. VLP has performed very well so far as a public entity. I mentioned earlier that we have distillates with stronger margins and higher growth rates and that North American natural gas is relatively inexpensive. Our hydrocracking investments really benefit in this environment. So we've increased the Port Arthur hydrocracker permitted capacity to 60,000 barrels a day, which makes it just like that one in St. Charles. I'll share that both of the hydrocrackers are performing very well.
We have our Diamond Green Diesel JV plant, which we started in the third quarter of 2013, which uses hydroprocessing technology to make high-quality renewable diesel from corn oil, waste cooking oil, and animal fats. Finally, we have 50,000 barrels a day in lower-cost hydrocracker expansion projects in progress, which cost less per barrel than grassroots units do. We're currently expanding the Meraux hydrocracker by 20,000 barrels a day, and we'll have that on stream in early 2015. We're also looking at the new Port Arthur and St. Charles hydrocrackers. We could expand those by 15 a day, and we would plan to do that in 2018. We're also investing to increase our processing capability of North American cost-advantaged crude. Really what we're doing, though, is displacing purchased feedstocks to fill the underutilized conversion capacity in the refineries.
We're constructing two new crude topping units. One at the Houston refinery, that'll be a 90,000 barrel per day unit, and one at the Corpus Christi refinery, and that'll be a 70,000 barrel per day unit, for $400 million and $300 million respectively. We expect to have both of these projects online in early 2016. The economics on the projects look really good. We ran the economics using Brent and LLS at parity, so no discount. The project showed an IRR of greater than 25% with that assumption. We're also working on a 25,000 barrel a day expansion of the McKee crude unit, which is expected to be done in the first half of 2015, and that's a $60 million investment. Then finally, we're looking to unlock light crude capacity at both the Port Arthur and the Meraux refineries.
Now let me talk just a little bit about our operations. Internally, we are very focused on continuing to improve our refining operations. What I show here in this chart on the right is the results of the industry survey over the last six years. We show 2008's data point, 2010's, and 2012's, and 2012's are the green dots. You can see that we have had significant improvement in our performance in the areas of mechanical availability, which we call reliability, in our personnel index, our maintenance index, in our non-energy CapEx, and in our energy intensity index. These are all very significant to us because you've got to operate reliably to produce income.
Our team has done an absolutely fantastic job of working these issues aggressively, and they are pursuing the goal to be the first quartile refiner, and they're going to maintain this relentless focus on safety, environmental, and regulatory compliance. We will also continue to invest capital to revamp unreliable equipment and process designs. We'll continue to develop and implement reliability programs system-wide, and we'll continue to push this focus on excellence among our team. I expect that we'll continue to see these results improve. Now, our ethanol business has done very well since we acquired all these plants in 2009. We got it for $760 million, or approximately 35% of replacement cost. As the graph on the right illustrates, this business has generated significant cash.
The fact that we bought very low-cost assets that are very high quality implies that we're going to have a competitive advantage in any margin environment. You can see the bullet at the bottom says that since our acquisition in 2013, we estimate that we've had a 40% cash internal rate of return on this investment. The ethanol business has been a fine acquisition, and it continues to produce significant income for us. Now, in addition to allocating capital to maintain our assets and invest in growth projects, we've increased the cash we return to shareholders, and we've built a very strong balance sheet. We've increased quarterly dividends from a $0.05 per share in the second quarter of 2011 to a $0.25 per share in the first quarter of 2014.
In 2013, we doubled the amount of cash returned to shareholders in the form of stock buybacks and dividends versus 2012, you can see this from the chart on the right. Our goal is to have one of the highest cash returns among our peers via dividends and buybacks. In addition to the cash returns we delivered, last year we spun off our company-operated retail as CST Brands, which was effectively a $3.60 distribution to Valero shareholders. In addition to returning cash, we are focused on maintaining our investment-grade rating via strong balance sheet. In 2013, we paid off $480 million of debt. At the end of the year, we had $4.3 billion in cash, which is inclusive of the $375 million that we kept in VLP. We had a net debt to cap ratio of 12%, which excludes VLP's cash.
This year, we are going to pay off $200 million worth of debt in April, that is our only debt obligation through this year. With the market trends that I mentioned, cost-advantaged crude and natural gas, the ability to process these, the ability to move these products to markets where we can get significant returns, with the strategies that we have underway to invest in our assets, to unlock the potential of the existing assets, to continue to pursue excellence in our operations and then to return cash to shareholders, we really believe that Valero is an excellent buy today. With that, I believe that we have got some time left, Ed, we will go ahead and take questions for Ash, Gary, or myself.
Thanks very much.
Could you give a little bit more color on where you are exporting to today, where you might hope to export to over the next two or three years? Indeed, what U.S. total exports of refined product might get to in a three-year time horizon with the same sort of price tags as we have got today?
Okay. No, that's a good question. The bulk of our gasoline is going to South America and into Mexico. I think we reported in the fourth quarter that we had 130,000 barrels a day of gasoline exports. This excludes the gasoline that we're exporting out of Pembroke, it's probably 80,000 a day that we take into Canada or the New York Harbor. So 130,000 a day gasoline in the fourth quarter, and diesel was much higher. Diesel was in that 230,000-240,000 barrel a day range. That split probably, and it depends, it changes from time to time, but that's probably split 45% to South America and then 55% to Europe. We're seeing the same type of export volumes, perhaps a little more gasoline going out in January and February than we had in the fourth quarter.
But demand in those markets continues to be strong. Quite frankly, the Mexicans don't have adequate refining capacity to supply their needs, and a lot of the South American refineries and the Caribbean refineries have had trouble operating. So I think we'll see this export trend continue. As far as the industry's ability to export, I think we're at what, 1.4 million barrels a day of distillates, and I think gasoline tends to be 500,000 barrels a day, give or take a little bit. I expect that those volumes will continue to increase. As I mentioned, a lot of refining capacity is being planned in the markets that really get served naturally by U.S. Gulf Coast refining, which would be the Caribbean and South America and Central America.
I think that a lot of that refining capacity is going to struggle to earn an economic return. So I think we'll see this continue. Is there anything you guys would add to that? Okay.
Maybe just talk a little bit, given obviously we have all the supply growth of the light crude, where is your ability to process light crude today? I mean, you've obviously outlined some growth projects, but how much headroom do you have for the E&P companies?
No, that's good. We'll let Gary Simmons speak to that.
In the fourth quarter, we took about 850,000 barrels of light sweet crude into our system. We believe that without capital, we have room for about another 300,000 barrels a day, and that's mainly just getting logistics in place to get those barrels to the refineries that can process it. In addition to that, with the capital projects that Joe's outlined that we're moving forward with, we believe would give us another about 250,000 barrels a day. So overall, in our system, we can take 550,000 - 600,000 barrels with what we currently have in place.
While we're on that topic, obviously we have a large excursion in LLS prices in the fourth quarter, and all other grades moved pretty similarly. So really just Gulf crudes were oversupplied. How do you think or how would you help investors understand what the key things are that you look at to sort of predict whether that volatility is going to continue and how wide that volatility could be?
Well, certainly in our refining system, we see that a medium sour has to price at about a 5% discount to a light sweet to make it economic for us to run that medium sour barrel compared to a light sweet barrel. Then you see a similar differential on the heavy sour side, that a heavy sour barrel again has to price about a 5% discount to a medium sour to make that economic. So we still believe that you have the volatility that's going to occur with the light sweet in the Gulf, and that the medium sours and the heavy sours will have to follow the light sweet.
Are you seeing any change in behavior from the E&P companies in terms of wanting to term up some of their volumes at a certain price that would be attractive to Valero?
Yes, we've seen numerous interest from producers. Some of that has been people are taking line space on some of the new pipelines coming online, so they want to have a home for those barrels that they have committed shipper status on the lines. Some of the producers you can tell are starting to get concerned that there may not be a home for their barrel, which makes them a lot more open to discussions on doing some sort of term arrangements.
What about the response of maybe some of your key suppliers on the heavy side? They've obviously seen the price of their heavy also fall. What do you see in terms of, say, the Mexicans or the Venezuelans or maybe even the Gulf suppliers in terms of trying to do different things with the barrels that they currently sell to you?
Well, most of our heavy supply comes from Latin America, and we haven't really seen a change in behavior from the Venezuelans or the Mexicans in terms of what they're willing to supply us. In fact, we got above our contract volumes from the Mexicans in the fourth quarter and some into the first quarter as well. The volumes have been fairly consistent from Venezuela as well, as well as Colombia. So we haven't seen really any change in behavior from our heavy sour suppliers.
I have a question to maybe bring Joe back into the conversation. $1.5 billion of growth investments, maybe $700 million is going into logistics from the maths. As you look at your pipeline or visibility on additional logistics projects, how long do you think you could sustain that level of investment in logistics or even grow it? This is at the parent level, and obviously VLP is a good vehicle to then drop those assets down into down the road.
Yeah, that's a good question. We shared this number on the roadshow, and it's an extrapolated number because a lot of the assets that we would look to drop, we don't have formal negotiated contracts between Valero Energy and VLP. Obviously, we'll work on those as time goes on, but we don't have them today. But if you just look at a replacement cost of these assets and you put an MLP-type multiple on them, okay, or the EBITDAs, take the EBITDAs and put an MLP-type multiple on them, it would imply that you might have some $600 million- $800 million of incremental EBITDA that you could then drop to an LP. I think we started with Ash, we had maybe $50 million of EBITDA in VLP today.
You can see very clearly that with that deep of a bench, that we could drive significant growth for an extended period of time. That really excludes several of the projects that we talked about. This is really, I'm referring to assets that are on stream today. Our guys do, as we mentioned, we've got some of the deals that we talked about today, but we also have other projects obviously that we're working on to try to continue to improve the efficiency of our operations.
At the parent level, over and above the numbers that you've just quoted, do you feel that there's a decent pipeline even beyond, say, 2014, 2015 of projects that you could fund?
Yes. I'm not at all concerned that we're going to be able to do what we've said. I think we've talked about 20%-22% growth for at least three years, and then averaging, I think, 16%+ over a five-year period. But depending on how things go, I think we'll continue to drive assets that way. Makes sense for both parties.
Well, thank you very much, Joe. Thank you, Gary, thank you, Ashley, and thank you to Valero, and good luck this year.
It's our pleasure, and thank you all for sticking around for this.