Okay, everyone. I think we'll get started. We have a couple refiners back to back here. First one is Valero Energy. I would like to welcome Gary Simmons from Valero, as well as Joe Gorder, the Incoming CEO.
Joe, I'll turn it over to you, and we'll finish with some Q&A. Thank you.
Thanks, Craig. Good morning, everybody. We appreciate you joining us for this discussion of Valero Energy. Before we get started here, we need to share the safe harbor statements, which basically says that the actual results could differ materially from our forward-looking statements. With that, let's go ahead and talk about Valero. I think as many of you know, we are the world's largest independent refiner. We have 16 refineries with 2.9 million bbl a day of refining 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. About 1,900 of these belong to CST Brands, which is our former retail business, which I think many of you know we spun off in May of 2013.
We have a very significant renewable fuels business with 11 efficient corn ethanol plants with 85,000 bbl per day of production capacity. We have a 50% JV interest in the Diamond Green Diesel plant, which has 9,300 bbl per day of renewable diesel production capacity. Finally, we have 10,000 employees. This map really 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 the yellow refinery icons. If you look on the West Coast, you can see that we have two plants in California. As you come across the map to the east, you can see that we have three refineries in the mid-continent. We have a significant refining concentration in the U.S. Gulf Coast.
If you go over to the east up into Canada, you can see the refinery in Quebec City, the Jean Gaulin Refinery. If you go all the way over to Wales, you can see we have the Pembroke Refinery. Our headquarters is located in San Antonio, Texas, and the Diamond Green Diesel plant is located on the side of the St. Charles Refinery there in the New Orleans area. Finally, the table on the lower right here provides some additional detail by region and by refinery. It includes our throughput capacities, our crude capacities, and the complexity index of the system. You can see we are very geographically dispersed in our operations. Our goal is to enhance shareholder returns and to increase their long-term value. We're going to do this by investing to take advantage of the North American resource boom.
We're also going to unlock potential value in our existing assets. We're going to continue to pursue excellence in our operations. We're going to continue to return cash to our shareholders. All of these strategies I'll cover here in some detail over the next several slides. Before we do that, though, I'd like to cover some key market trends that we're seeing, which are really supporting these strategies. These include the growth in the U.S. and Canadian oil, natural gas, and NGL productions. This is really providing North American refiners with significant cost advantages, particularly those with operations in the mid-continent and in the U.S. Gulf Coast. We're also seeing a market that's providing higher distillate margins due to the global demand growth. Then finally, we continue to have very strong export markets, which are supporting utilization rates and margins in the U.S. Gulf Coast.
The first key market trend that I mentioned, you can see on this chart, which illustrates the growth in U.S. and Canadian crude production. You can see the significant growth in North American production starting in 2010, going out through the forecast period here of 2020. The largest growth comes from U.S. shale and heavy Canadian crudes, which are the top two segments on these bar graphs. Crossing the bars, you can see the line that shows the imports of non-Canadian crude. You can see that since 2010, there's been significant reductions in imported crude, primarily light sweet crude. We still have plenty of heavy sour and medium sour grades coming in, but the light sweet crude has been effectively backed out of the U.S. Gulf Coast.
The takeaway here is that the crude production growth is providing an advantage for North American refiners, and it's going to continue to do so for some time. As you would expect, we're working on projects to supply more cost-advantaged crude to our refineries by pipe, rail, barge, and ship. For example, at the St. Charles refinery, we have a 20,000 bbl a day rail unloading facility that's going to be online in the first quarter. I'm sorry, in the first quarter. It's online in the first quarter. We'll be bringing bitumen in by the second quarter using our purchased rail cars, and we're also barging barrels into St. Charles from our Hartford terminal with 35,000 bbl a day of capacity.
At Port Arthur, we're working on a rail unloading facility, which is going to enable us to bring up to 70,000 bbl a day in, and this project will be operational in the fourth quarter of this year. At Corpus Christi, we're working on a crude export dock, which is going to be online in the third quarter of this year with 25,000 bbl a day of capacity initially. Then we're adding tankage that's going to allow us to increase this capacity to 50,000 bbl a day by the first quarter of 2015. On the West Coast at our Benicia refinery, we're working on a rail unloading facility that we'll be able to use to deliver up to 50,000 bbl a day of crude. This facility will be in place by the first quarter of 2015, subject to the permitting process, which we continue to work through today.
In the Mid-Continent, we expect to provide McKee with pipeline access to an incremental 30,000-40,000 bbl of Midland crude in the third quarter of this year. In the Atlantic region, our Quebec City refinery is one of the great examples that we have of how our business is benefiting from the North American crude oil boom. This chart shows the refinery's balance of imported and domestic crude over the past 12 months. As recently as March of last year, the refinery ran 100% West African and Mediterranean crudes, which delivered in at Brent plus prices. As you move to the right, you can see how we are displacing the imported volumes with North American supply. Currently, we are supplying about 50,000 bbl a day by rail, and we will increase that to 60,000 bbl a day by year-end.
We are also moving barrels by ship from the U.S. Gulf Coast using foreign flag vessels. In June, the Quebec crude slate is going to be over 80% North American crude. By the end of the year, we will be running 100% North American crude, which is generating meaningful margin improvements for us at this refinery. Another advantage we enjoy is low-cost natural gas, which is resulting from the significant production increases that we are seeing. For us, natural gas is a fuel, so it is an operating expense, but it is also a feedstock rolling into cost of goods sold because we convert it into hydrogen as a feed. Our refining system consumes over 800,000 MMBtus per day of natural gas, and if you throw into this our ethanol business, you are somewhere just under another 100,000 MMBtus a day. We have significant natural gas consumption in our system.
The chart below shows the financial benefit that we enjoy due to the lower cost that we are experiencing. As you can see, the right bar shows that at $4 an MMBtu, we enjoy a $1.8 billion annual advantage over the guy in Europe who is paying $10 an MMBtu, and a $3.5 billion advantage over the Asian refiner that might be using LNGs. Clearly, low-cost natural gas is a huge advantage for us. Distillate demand continues to grow, and as a result, we are experiencing much higher margins, the primary reasons that we invested in hydrocracking so aggressively. If you look at the chart on the lower left, we show U.S. Gulf Coast gasoline and diesel product margins as compared to Brent. Very clearly, the diesel margins are much stronger than the gasoline margins over the past five years, in 2013, and currently.
The chart on the right helps explain why. Clearly, diesel demand globally is growing much more rapidly than gasoline demand is, at about 1.5x the rate. You can see gasoline demand is growing, but diesel is growing at a much higher rate, and this is supporting these higher margins. As the title of this chart states, 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 cost-advantaged crude and natural gas, but also because they have access to water, which gives them very efficient access to these growing markets.
Now, if you take a 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. The East Coast and the West Coast refineries are running at lower rates, and Western European refinings are struggling. Another point, really, that we can draw from this chart is that the higher utilization rates in the Gulf Coast are supported going forward by our access to the export markets. The question we often get, are these export markets going to continue? Are they sustainable? I would tell you that from our point of view, they very clearly are. You have the shortage of refining capacity in Mexico, which is encouraging their continued import of products.
If you look at South America, they simply don't have the refining capacity today to sustain their growth in demand. If you look at other South American refiners, they're struggling to operate the assets that we have. We believe that the export markets are very sustainable. Now for global demand growth, it is very clearly important to refining margins. As 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, transportable, and fungible. As demand grows, we're able to take advantage of that by supplying products into these markets.
Now, we do expect significant new global refinery capacity additions to come on stream over the next several years, particularly in Asia and in the Middle East, where the demand growth is very strong. However, we also believe that many of the announced projects are going to be smaller than originally announced. They're going to be later than announced. We really believe that some of these projects are going to be shelved because the economics don't support them. We also expect that you're going to continue to see rationalization in the refining industry and that some of the refineries that just aren't competitive are going to shut down. Now, the chart below shows that the net refinery additions are more or less in line with potential demand growth, which is illustrated on this red bar.
The bottom line from our perspective is that we're not going to see significant deterioration of global refining margins going forward. But we do expect that regions without cost-advantaged crude and natural gas are going to continue to suffer and that they're going to be vulnerable to closure. Now let's focus a little more on Valero and our capital spending plan. As you can see, in 2013, we spent $2.7 billion, which is approximately $1 million less than the guidance that we had provided. This included $63 million that we spent on our retail business that we subsequently spun off. Now in 2014, we plan to spend $3 billion, with about $1.5 billion allocated to maintaining our refining logistics and ethanol assets, and the remaining $1.5 billion to be invested in projects to facilitate the processing of our cost-advantaged natural resources.
Now this page focuses specifically on that growth capital, and you can see that it's 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're going to spend additional dollars on hydrocracking and on projects that are going to allow us to upgrade natural gas and NGLs. More specifically, we're investing in logistics assets that are going to increase our access to cost-advantaged crudes for our refineries and to increase our capability to export products. We purchased 5,320 rail cars. To date, we received 2,500 of those, and we'll receive the final cars by the end of 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'll make on this is that they're all compliant. They're 1232 cars, so they're compliant with the DOT regulations. As previously mentioned, we commissioned a new crude rail unloading terminal at Quebec, and that took place in 2013. We've started up an unloading facility in the first quarter of this year at St. Charles. We're also working on terminals at Port Arthur and at our West Coast refineries. At Quebec, we will be delivering crude via Enbridge's Line 9B, and we're making investments here that include those in terminalling, tankage, and ships to satisfy our ability to move these barrels. At Corpus Christi, we're working on a dock project that's going to be on stream in the third quarter of this year, so we'll begin moving additional crude to Quebec at this point in time.
One point on this slide that we need to remember is that all of these logistics projects that we're investing in are candidates to drop to our MLP, which I'll speak about now. In 2013, we completed two major transactions. The first was the spin-off of CST Brands. The second was the successful IPO of Valero Energy Partners in December of last year. VLP is a sponsored traditional logistics MLP with 100% fee-based revenues. We don't plan to take any commodity risk in VLP. Valero retains significant ownership of VLP with almost 69% of the common and subordinated units, and we retain control by owning 100% of the general partnership and all the IDRs. We intend to use VLP as the primary vehicle for us to grow our logistics assets.
We're planning to grow distributions in VLP by at least 20% a year for the next several years, and we expect to complete our first drop-down sale in the early part of the third quarter of this year. VLP's future growth is supported by this extensive portfolio of logistics assets that are retained at Valero Energy, which can be dropped to VLP. The initial assets we put into 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 key refineries, their long history of reliable and ratable operations, and lastly, because they're very high quality and well-maintained assets. VLP has done very well since the public offering was completed in December.
I think we came out at $23 a unit, today we are trading somewhere up in the mid-40s, $44 and change. It has done very well. I mentioned earlier that distillates have stronger margins and higher growth rates than gasoline and that North American natural gas is relatively inexpensive. Our hydrocracking investments really benefit in this environment. We have increased the Port Arthur hydrocracker permitted capacity to 60,000 bbl a day, which makes it just like the one in St. Charles. Both of these hydrocracker projects are performing very well. Then we have our Diamond Green Diesel JV, 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 from animal fats.
Finally, we have 50,000 bbl a day in lower cost hydrocracker expansion projects, which cost a lot less per barrel than grassroots units do. Included in this is the 25,000 bbl a day Meraux hydrocracker project, which we will have on stream in early 2015. We are also looking at the Port Arthur and St. Charles hydrocrackers for possible expansion projects. We could take them up by 15 a day, and we would plan to do that in 2018. The hydrocracker investments have been very good for us. We are also investing to take advantage of processing more North American cost-advantaged crude. These investments enable us to displace purchased feedstocks to fill underutilized conversion capacity in our refineries. We are working on a 25,000 bbl a day expansion in the McKee crude unit, which is expected to be done in the first half of 2015.
We are also constructing two new crude topping units, one at the Houston refinery, that will be a 90,000 bbl a day unit, and then one at the Corpus Christi refinery, which will be a 70,000 bbl a day unit. These are going to be done for $400 million and $350 million respectively. We expect to have both of these projects complete in early 2016. The economics on these two projects are really good, with IRRs in excess of 25% using Brent and LLS at parity, so no discount. One of the questions we get asked periodically is, how will crude exports affect the economics on these projects? I am just telling you, we ran the economics with these two crudes at parity, so it really should not have a material effect.
The chart on this page shows how much light crude we can run, how much we ran in the first quarter of 2014 as compared to our current estimated capacity. You can see we ran 772 versus an estimated capacity of 1,205. You can also see that with these projects, we are going to increase that capacity by over 15% to 1,390 bbl per day. Of course, the amount of light sweet crude we run ultimately depends on the economics. Let us take a look at how our refining operations performed relative to the industry on some key performance benchmarks. The chart on the right here shows the results of a biannual industry survey over the last six years, with data points for 2008, 2010, and 2012, using the red, yellow, and green color dots to show the year.
Now, each key benchmark has a bar with four segments showing the performance quartile within that benchmark, and the dots are where Valero's refining system rated within that benchmark. As you can see, our performance has improved in each category during the survey period. This is really important to us because reliable, efficient operations are closely linked to improvements that we're making in achieving our health, safety, and environmental performance standards and to our profitability. Our team has done an absolutely fantastic job of continuing to improve our operations. We're pursuing our goal to be a first quartile refiner by maintaining a relentless focus on safety, environmental, and regulatory compliance. Our organization is committed to excellence, so you'll continue to see us invest capital to revamp unreliable equipment and process designs, and we'll continue to develop and implement reliability programs system-wide.
Now, our ethanol business has done very well. We now own and operate 11 ethanol plants with 1.3 billion gallons per year of capacity. We paid $794 million for the assets, which is approximately 35% of replacement cost. Our ethanol business had a record year in 2013 by earning $491 million, and since acquiring the 10 plants in 2009 and 2010, we've generated $1.7 billion in cumulative EBITDA. We continue to look for opportunities to grow this business, and in March of this year, we purchased an idled 110 million gallon per year ethanol plant in Mount Vernon, Indiana, for $34 million. Restart efforts on this plant are underway, and we plan to resume production in the third quarter of this year. The assets that we own are very high quality, and they're in great locations to provide a competitive advantage in any margin environment.
Given the favorable ethanol margin environment we have today, we're expecting these plants to do very well this year also. I don't know if you remember from the map that I showed you earlier, but these ethanol plants are really all in the upper Midwest, so they're kind of right in the middle of the corn belt , which really gives them a feedstock cost advantage. Now in addition to allocating capital to maintain our assets and to invest in growth projects, we've increased the cash that we return to shareholders, and we've built and maintained a very strong balance sheet. As you can see from the chart on the right, in 2013, we returned almost $1.4 billion in cash to shareholders through dividends and stock buybacks, and that's a year-over-year increase of 117%.
So far in 2014, we've returned almost $542 million of cash to shareholders, purchasing 7.5 million shares of Valero stock for $410 million. We've increased the quarterly dividend from $0.05 a share in the second quarter of 2011 to $0.25 a share in the first quarter of 2014. Our goal is to maintain one of the highest cash returns among our peers via dividends and share repurchases. Now in addition to the cash returns, which we show here, that we delivered last year, we had the spinoff of CST Brands, which provided Valero shareholders with a $3.60 distribution or $1.9 billion in total. Now we also remain focused on our investment grade rating. S&P recently reaffirmed our BBB investment grade rating, but they changed our outlook from negative to stable.
At the end of March, we had $3.6 billion in cash, which is inclusive of the $384 million that we kept at VLP. We had a net debt to cap ratio of 12%, which excludes that VLP cash. In April, we paid off $200 million worth of debt, and that is really our only debt obligation this year. Financially, we remain very strong. With these key market trends that I mentioned, cost advantage crude and natural gas, the ability to process them, our ability to move our products to markets where we can get significant returns and margins, and with our strategies that we have underway to invest in our assets, to unlock the potential of our existing assets, and to continue to pursue excellence in our operations, we are going to return cash to shareholders, and as a result, we really believe that Valero is an excellent buy today.
With that, Craig, we can go ahead and open it up and take questions.
[audio distortion] Right. If there are any questions from the audience, happy to take those at this time. Otherwise, I am happy to kick off with a question. Natalie, go ahead.
[audio distortion] Obviously, as you mentioned, exports have played a very important role in Valero's margins. Is there a cap to the amount of exports that as an industry we can have? Are we there? About how close are we to kind [audio distortion] of hitting a peak or that?
Yeah. Okay. You want to come on over.
Okay.
I'll let Gary. He's responsible for now the products side of our business, and his team is the ones that are executing the export strategy.
I would say on exports, especially in distillate, some of the issues that we've had were really being able to make the quality of diesel that the European market demands. The hydrocracker projects for us gave us a lot more flexibility to produce a lot of that EN 590 quality distillate that Europe demands. The second limit is just dock limitations, but those are very easily overcome and fairly small capital investments, mainly pumping capacity to be able to get the load rates up on the dock. We're a long ways from what I would say is reaching a limit on our export capabilities.
The one thing that we might add to that is that you look at the market and you say, how much is the market going to absorb? Clearly, South America, Mexico, demand continues to increase. Their operations of refining assets and their ability to invest in refinery assets is probably somewhat limited. The U.S. Gulf Coast tends to be very competitive from a product production perspective. I think that if you look at the market itself, our ability to sustain exports because of demand growth is there. If you look at the barrels that Gary's team is exporting to Western Europe, for example, it's mostly distillate. It's all distillate, in fact.
That is because we do have cost advantages in the U.S. Gulf Coast that allow us to move barrels into those markets more efficiently than they can produce them locally. It goes back to the fact that we have cost advantage crude, we have low-cost natural gas, you have a great labor pool, then we can ship export barrels on foreign flag vessels, which makes it very economic to do so. It looks very sustainable to us.
Joe, I have a question for you on Gulf Coast light crude balances. DOE numbers came out today, showed a little bit of a tick down in overall crude inventory levels, but we're still very close to record levels. Where do you think we max out in terms of storage capacity in the Gulf? Especially in light of the fact that we've got BridgeTex going to turn on sometime around mid-year 3Q, Seaway Twin, same timeframe. If you have any type of roadmap as to where you see crude differentials shaping up, would be curious to hear that.
[audio distortion]Gary, go ahead.
Yeah. Before today's stats, we would say you had consumed about 75% of the working inventory available in the Gulf. Not a lot left there. I think the thing that you'll start to see is a dynamic. We've seen big draws in Cushing and builds in the Gulf. Still a lot of shell capacity available in Cushing. You'll probably start to see some of that balance back where Cushing inventories begin to come back a little bit as the Gulf fills up light sweet crude. Overall, we think that it's very supportive of these differentials. Certainly, we saw the LLS to Brent differential come in in the last couple of days. I think that's mainly due to the expiration of the contract.
We see that all this is very supportive of these discounts with the light sweet trading at a substantial discount to Brent, then the medium sours following suit to be competitive with the light sweet and heavy sours also following the medium sours, again, trading at a discount there to keep their barrels flowing into the market.
Okay. Maybe I'll shift gears to the West Coast. You're probably tired of answering questions about your strategic view on your West Coast refining assets, but I wanted to ask the obligatory question. I know you've mentioned you see some option value there. If you can get Canadian crude in there, if you can rail more shale crudes there. Where do you see those assets five years from now? Secondly, are those assets generating any type of meaningful EBITDA from the logistics side of inside the refining fence, so to speak?
Yeah. No. Okay. The West Coast, it continues to be a challenged market. I think you've heard it said many times that we're probably one refinery long on the West Coast. The option value that everybody speaks about really is driven by the fact that if there is an operating issue, you get very good margins on the West Coast. When everybody's running well, the margins tend to be pretty close to break even or slightly better. It is a challenged market. In five years, if we look out at it, I think what you see is that we have a good portfolio of assets there. The Wilmington plant is very good. Benicia has very good hardware. The issue of Benicia is that it produces too much gasoline. I shouldn't say too much gasoline.
It produces a significant yield of gasoline, which of course, we've seen the margins compressed on and demand not be the greatest on. But the assets are very good. They cash flow. We're not in a bad situation when it comes to the West Coast at all. Gary and his team are working very hard at getting alternative crude supplies in, which would increase the economics out there for us substantially, and we're going to continue to try to do that. We expect that that's going to happen. But Craig, I don't think that you'll see any major changes from our perspective on the West Coast.
Okay, how about midstream EBITDA? Are there any MLP-able assets that you could contribute to VLP in the West Coast refining system?
Yeah, sure. I think you certainly could do that. We haven't identified specifically the assets going out beyond the right of first offer assets that we included in the VLP offering yet, and none of those are tied to the West Coast.
Got it. Okay, maybe one final question on RINs. We've seen RIN prices ticking up lately in the last month or so. Do you think that this is a reflection that the EPA may backtrack on their November proposed RFS mandate? Or what do you think it does reflect right now? Curious to know.
Gary talks to these guys all the time. Do you want to go ahead and?
Yeah. I think definitely the uncertainty. I think we need to have clarification in exactly what the obligation is going to be. Until we have that certainty, the market's going to have a lot of volatility, and we've seen that. It kind of fell off, and now it's strengthened back. We're hearing that we should receive final volumes for 2014, and I think that will settle the market back down.
Yeah, it's a twitchy market, Craig, as you know. Gina McCarthy comes out and makes a comment, and the next thing you know, it's moved a nickel, right? It's a tough one to operate in, but I agree, Gary gave you the right answer on the timing of all this. We also understand that longer term solutions are still getting knocked around on the RFS. Congressman Upton is looking at the possibility of including in an appropriations bill, a provision that says that if we don't have the final EPA numbers for 2015 by November, it'll revert back to the proposed 2014 volumes, and so on. There's a keen awareness in Washington, D.C., that we have an issue here that's disrupting these markets a bit. I think they're going to make efforts to deal with it.