Thanks for coming. We really appreciate you being here. Doug mentioned Lane. Lane Riggs has recently been promoted also. He is, as of May 1st, going to be the Executive Vice President for Refining and Engineering for the company. Just by way of background, Lane, when I first started working with him, he was a young engineer. He worked at the McKee Refinery. He's had a progression of jobs, including product supply, crude and feedstock supply, and trading. He ran our supply chain optimization group. Then we went down, he had refining operations, and now his span has continued to grow. He's got our refining operations, our engineering, our procurement functions, and he's one of those individuals that's very bright and knows a ton about the business, and he certainly makes me feel very good about where we're going with the organization.
As we get into the Q&A, feel free to pose questions that you might want, and Lane and I will try to take them, and if you want the right answer, I'm going to let him do it. All right. Now, this is the infamous safe harbor statement, and I will let you read it if you like, but basically what it says is that the actual results could differ materially from the forward-looking statements. With that, we'll go ahead and begin talking about Valero. I think, as you know, Valero is the world's largest independent refiner. We have 16 refineries with 2.9 MMbpd of refining 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. We have nearly, and I think a lot of you know, 1,900 of these were the CST sites. Those were our former retail sites that we spun off to shareholders in May of 2013. CST is our largest branded customer. Then we have one of the largest renewable fuels businesses with 10 efficient corn ethanol plants with 78,000 bbl per day of production capacity. We also have a Diamond Green Diesel JV plant that has 9,300 bbl per day of renewable diesel production capacity. Then finally, we have our 10,000 employees. Now, this map shows the geographic diversity of our operation. The teal colored states are those that we have a wholesale presence in, wholesale marketing presence. Those with the V logo are where we have a branded wholesale presence.
Then you can see the refinery icons here over on the lower left. That shows where our plants are located, all the way from the West Coast through the U.S. Gulf Coast, the mid-continent. Then in the Atlantic Basin, if you go over to the upper right, you can see that we have the refinery in Quebec City, and then we have a refinery in Wales, which is the Pembroke refinery, and between those two, we're able to optimize the Atlantic Basin. 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 at the St. Charles refinery in Louisiana. Then the table on the lower right provides some additional detail by region and by refinery, and it includes the throughput capacity, the crude capacity, and the complexity index.
You can see we have quite an extensive network, and we are geographically diverse. Our strategy is to enhance returns and to increase long-term shareholder value, and we are going to do this by investing to take advantage of this North American resource boom. In addition to that, we are going to continue to unlock potential, the potential value of our existing assets, and we are going to continue to pursue excellence in our operations, and we are going to continue to return cash to shareholders. I will cover these strategies in detail as we go through the presentation.
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 a significant cost advantage. We are also seeing a market that is providing higher distillate margins due to global demand growth.
Finally, we continue to have very strong export markets, which are really supporting utilization rates and margins in the U.S. Gulf Coast. 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 crudes, which are really the top two segments on these bar graphs. You can also see the significant growth in North American production since 2010 out through the forecast period of 2020. Also on this chart, we have a line, and the line shows the imports of non-Canadian crude, and you can see that since 2010, there have been significant reductions in imported crude. This is primarily light sweet crude.
We still have plenty of heavy sour and medium sour crudes coming into the U.S., but light sweet crude has effectively been backed out of the U.S. Gulf Coast because of economics. We expect as continued supply comes on stream, we are going to find that this continues to be the case. Really what this tells you is that North American refiners are going to be continued to be advantaged for some time based on crude supply. All right. Now I want you to eyeball this chart. There is a lot going on here, but this chart 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 the logistics solutions are implemented to move that oil. Let me walk you through it. Okay? Let us start over here. First of all, the ovals.
Okay, 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 is delivered into the U.S. East Coast, as you can see with this arrow, and that is the marginal price of crude. It is delivered in at a Brent plus 2 number, which is Brent plus the transportation cost. Everything else calibrates off of that based on the transportation cost. You can see the arrow comes in from the right, Brent plus 2. Then if you look at the rectangle immediately to the left, you see that rail from Bakken to the U.S. East Coast is anywhere from $14-$17 a barrel.
You go to where Bakken is produced into Dakotas, and you can tell that Bakken needs the price in the field there anywhere from $12-$15 off to compete with Brent. If you follow the line down, then at about 5:00, you can see that going into Louisiana at St. James, they are going to have to deliver Bakken there somewhere around Brent even to $3 off. It is all based on the marginal barrel coming in and then the respective transportation costs to get it to the refining centers. There are two major takeaways that I want to leave you with on this chart. Number one, and you can see this, is that the Midcontinent and the U.S. Gulf Coast refiners are clearly advantaged from a crude cost perspective.
The second, and it is less obvious here, but we are seeing it, is that having incremental crude supply in the market, even though it might be light sweet crude, is pressuring the discounts on the medium and the heavy grades as they compete for space in the refineries. This is something that, again, we expect is going to continue and be with us for some time, and it truly provides an advantage for U.S. Gulf Coast refiners. As you would expect with all of this going on from a natural resource perspective, Valero has many projects underway to enable us to supply more cost-advantaged crude to the refineries. For example, in the Gulf Coast region, we continue to benefit as additional pipelines come on stream and move crudes in.
In addition to that, at the St. Charles refinery, we have got a 20,000-barrel-a-day rail unloading facility that is going to come on stream in the first quarter of 2014. We are bringing Canadian bitumen in in the second quarter of 2014 using the rail cars that we purchased. We are also bringing bbl into St. Charles from our Hartford terminal, and we are doing this by barge, and we are bringing about 35,000 bbl a day that way. At Port Arthur, we are working on a rail unloading facility that could enable us to bring up to about 70,000 bbl per day of crude in, and we expect that to be commissioned in the fourth quarter of 2014.
At Corpus Christi, we are working on a crude export dock that is going to be online in the third quarter of this year with 25,000 bbl a day of capacity, and that is going to increase to 50,000 bbl per day by the end of the first quarter, when we get some additional, first quarter of 2015, when we get some additional tankage online. On the West Coast to Benicia, we are working on a rail unloading facility that we are going to use to deliver anywhere from 30,000 bbl a day -50,000 bbl a day of crude via rail. This facility will be in place by the first quarter, assuming that we get the permit in a reasonable period, and we continue to work on that permitting process.
In the North Atlantic region of Quebec, we expect to be running 100% North American crude by the end of the year. That is going to back out the foreign imports, which are delivered in today at much higher cost. Currently, we are railing 30,000 bbl a day of crude in. We started that in August of 2013, and we are going to increase that to 60,000 bbl a day by the end of the year. Thus far into Quebec, we have delivered WTI, Bakken, and Eagle Ford, and the refinery likes these crudes. Finally, we are going to be a shipper on Enbridge's Line 9B. The bbl are going to move on pipe into Montreal, where we will put them on a ship and then shuttle them to Quebec. Based on Enbridge's estimates, we expect this project to be going forward in the fourth quarter of this year.
Clearly, as a company, we are working on projects that are going to ensure that we are able to run this cost-advantaged crude. Another advantage that we are enjoying is the lower cost of natural gas resulting from the significant production increases that we have all seen. For us, natural gas is a fuel, so it is an operating expense, but it is also a feedstock, and so it rolls through cost of goods sold. This is the case because we convert it to hydrogen as a feed. Our refinery system consumes about 800,000 MMBtus per day of natural gas, and as the chart below shows, the financial benefit that we enjoy due to these lower costs.
As you can see, the bar on the right 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 then a $3.5 billion advantage over the Asian refiner that might be using LNG. Very clearly, low-cost natural gas is a huge advantage for us. Global distillate demand continues to grow, and as a result, we are 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, we show here that U.S. Gulf Coast gasoline and diesel product margins as compared to Brent. Very clearly, the diesel margins are much stronger than gasoline margins over the past five years than they were also in 2013.
You say, "Well, why is this the case?" It is answered by this chart on the right, where you can see where demand is globally. Clearly, diesel demand globally is growing much more rapidly than gasoline demand at about 1.5x the rate. Although we are seeing global demand growth for gasoline, diesel is growing at a much higher rate, and it is supporting these margins. As the title 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 the cost advantage crude and natural gas, which we have talked about. They also have access to the water, which really gives them very efficient access to growing markets.
It's contributed a lot to the 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, PADDs 3, and PADDs 4, which are supported by the cost-advantaged crude and natural gas. The East Coast and the West Coast guys are running at lower rates, and recently the EIA reported that Western European refineries were having dismal results. Their utilization rates were much lower. Italy's rates were around 63%, and France's were about 68%. Northwest Europe is really struggling here because they don't have the same type advantages that we have in the U.S. Another point I'll make on this chart is that the higher utilization rates in the Gulf Coast really are supported going forward by our access to export markets. Now for global demand growth.
It is important to refining margins. As you can see from the bar chart, 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, as you know, our products are storable, they're transportable, they're fungible. As demand grows, we're able to take advantage of that by supplying products into these markets. 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're going to come later than announced, and we also believe that many of these projects are going to be shelved because of cost.
We also believe that the less competitive refineries are going to continue to shut down. We mentioned the difficulties that we're seeing in Western Europe and the Med. We expect that's where a lot of this will be. The chart below shows the net refinery additions, and you can see here that they're really more or less in line with the potential demand growth that we've talked about. That's illustrated here by this red bar. The bottom line from our perspective is that we don't expect to see a significant deterioration of global refining margins. But we do expect that the regions without cost-advantaged crude and natural gas are going to continue to be vulnerable to closure going forward. Now let's take a look at Valero's capital spend. This is a topic that we talk about often.
As you can see, in 2013, we spent $2.7 billion, which is approximately $100 million less than the guidance that we provided. In this $2.7 billion, we had $63 million that went into our retail business, which we spun off. In 2014, we plan to spend $3 billion with about $1.5 billion of that 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. This page really focuses more specifically on our growth capital investments. You can see that they're really allocated in 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 on hydrocracking and in projects that are going to allow us to upgrade natural gas and NGLs. More specifically, we are investing in logistics assets to increase our access to cost-advantaged crudes for our refineries and to increase our capability to export products and to export crude. We purchased 5,320 rail cars that we began receiving in the fourth quarter of 2012, and we will receive the final cars in the second quarter of 2015.
About 55% of these cars are general purpose, and the other 45% are coiled cars that allow us to move heavy crudes. One point I will make here is that these are all 111A cars, and you have all heard about the regulations that the Department of Transportation is looking at implementing here. The cars that we have on order actually exceed Department of Transportation requirements.
We are in good position there. To date, we have received 2,000 of these cars. We are also working on crude rail unloading terminals in Quebec and at St. Charles, at Port Arthur, and at our West Coast refineries. I mentioned earlier that we are going to be delivering crude via Enbridge's Line 9. We have been investing in Montreal and Quebec City to provide the terminaling tankage and the ships that we need to be able to move the Line 9 bbl into the refinery. We are also working on projects to export products and to export crude.
One example is at Corpus Christi, we are working on a dock project that we will have online in the third quarter that is going to enable us to begin moving additional volumes to Quebec. Finally, we have other investments that include pipes, barges, ships, tanks, and docks at our various facilities.
We do have a lot going on on the logistics side of the business. One point that I will share here is that these assets that we are investing in really are very good candidates for us to drop to the MLP, which I will talk about now. As many of you know, in December, we completed the IPO of Valero Energy Partners. We are going to manage it as a traditional logistics MLP with 100% fee-based revenues. Valero did retain a significant ownership in VLP, and we own 69% of the common and subordinated units, and we own 100% of the GP and the associated IDRs, and we plan to retain control of this entity. It is going to be the primary vehicle that we use to grow our logistics assets going forward.
We are planning to grow distributions at 20%-25% a year for the next several years, and we expect to complete our first drop in the third quarter of 2014. In addition to the assets that we put in there, we have a significant portfolio of assets that are going to facilitate the subsequent drops. We should be able to grow at the rates we have talked about for some period of time. The initial assets we put in VLP are the Port Arthur Logistics System, the McKee Products System, and the Memphis Logistics System. These assets were selected due to their high integration into three key refineries, their long history of reliable and ratable operations, and the fact that they are very high quality and well-maintained assets.
I do not know if all of you track VLP and its performance, but in the middle of December, we put the units into the market at $23 a unit, and I think yesterday they were somewhere over $38 a unit. I do not know the exact price. Anyway, it has performed very well in the 2.5 months that we have been on the market. Friday of this week, we have our first VLP earnings call. It is going to be an interesting earnings call for me because we only had 16 days of operations. Anyway, we have got the first earnings call. That is it on VLP. I mentioned earlier that distillates have stronger margins and higher growth rates than gasoline, and that North America 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 that we have down in St. Charles. Both of these hydrocrackers are performing very well. We have our Diamond Green Diesel JV plant, which we started up in the third quarter of 2013. This is a plant that uses hydroprocessing technology to make high-quality, renewable diesel from corn oil, waste cooking oil, and animal fats. Finally, we have 50,000 bbl a day in lower-cost hydrocracker expansion projects, which cost less per barrel than grass roots units do. We are currently expanding the Meraux hydrocracker by 20,000 bbl a day, and we will have that on stream early in 2015. We are also looking at the new Port Arthur and St. Charles hydrocrackers, and we could expand these by 15,000 bbl a day.
If we did so, that would be sometime in 2018. We are also investing to increase our processing capability of North American cost-advantaged crude. These investments are going to enable us to displace purchased feedstocks to fill the underutilized conversion capacity in these refineries. That is a key point. A couple of years ago, if you would have thought about adding crude capacity, you probably would not have done it. The economics did not support it. In this case, what we are doing is really filling out the downstream process units at these two refineries and backing out expensive purchased feeds by putting these units in place. We are working on a 25,000-barrel-a-day crude unit expansion at our McKee refinery, and this is expected to be done in the first half of 2015, and that is a $60 million investment.
The two new crude units that I mentioned, one is going to be at the Houston refinery. That is going to be a 90,000-barrel-a-day unit. The other one is going to be at the Corpus Christi refinery. That is a 70,000-bbl-a-day unit, and they are $400 million and $350 million of capital, respectively. Both of these projects are going to be online in early 2016. Finally, we are looking at the system for opportunities to unlock light crude capacity at both the Port Arthur and the Meraux refineries. The chart on the right shows how much light crude we ran in the fourth quarter of 2013 as compared to our current estimated capacity. We believe that the projects that we have in place are going to allow us to process light crude, to increase that amount by 15%.
And of course, how much light crude we process is, as we pointed out earlier in one of our meetings, is really dependent on the economics. We ran 770 in the fourth quarter of 2013. We could have run more, but we didn't because the economics didn't justify running more. Now let's talk a little bit about our refining operations. Lane Riggs and his team are very focused on continuing to improve our operations. This chart represents the results of the industry survey, and it shows data points over the last six years. You can see the dots for 2008, 2010, and 2012. As you can see, we've had significant improvement in our performance in the areas of mechanical availability, which we call reliability, in our personnel index, our maintenance index, our non-energy CapEx, and our energy intensity index.
These are all very significant to us because you've got to operate reliably and efficiently to maximize income. Our team has done an absolutely fantastic job of working these issues very aggressively, and they're pursuing the goal to be first quartile in every category, and they're going to maintain a relentless focus on safety, environmental, and regulatory compliance. We also continue to invest capital to revamp unreliable equipment and process designs. We're going to develop and implement our reliability program system-wide, and we're going to continue to push our focus on excellence among our team. I expect that we're going to continue to see these results improve as they have over the last six years. Now our ethanol business has done very well since we acquired it beginning in 2009. We paid $760 million, or approximately 35% of replacement cost for these assets.
As the graph on the right illustrates, the business has generated significant cash. The fact that we bought very low-cost assets that are very high quality and in great locations, they're located right in the middle of the corn belt in the Midwest, really provides a competitive advantage for us in any margin environment. As you can see, the bullet on the bottom states that since the acquisition in 2013, we estimate that we've had about a 40% cash internal rate of return on this investment. So the ethanol business has been an absolutely fine acquisition, and it continues to produce significant income for us. Now, in addition to allocating capital to maintain our assets and to invest in growth projects, we've increased the cash that we've returned to shareholders, and we've built a very strong balance sheet.
We've increased quarterly dividends from $0.05 a share in the second quarter of 2011 to $0.25 a 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, and 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. Now, in addition to the cash returns we delivered last year, we spun off our company-operated retail assets to CST Brands, as I mentioned earlier, and this effectively gave a $3.60 a share distribution to Valero shareholders. In addition to returning cash, we've really focused on continuing to maintain our investment-grade rating, and we're doing that via a very 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 left in VLP. We had a net debt to capital ratio of 12%, which excludes VLP's cash. This year, we are going to pay off $200 million worth of debt in April, and that is really our only debt obligation this year. From a cash and a balance sheet perspective, we are in a good position, and I think you can see that we are very strong financially.
With the market trends that I mentioned, cost advantage crude and natural gas, the ability to process them, the ability to move 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 our existing assets and to pursue excellence in our operations and return cash to shareholders, we really believe that Valero is an excellent buy today. Doug, that is all I had for prepared remarks, and I guess if you would like, we will open it up for questions.
Please. Thanks, Joe. Folks, we should have some roving microphones. Gentlemen over in the corner, I think, are taking care of that. Maybe I could kick off the questions, and then we will go to the floor. Joe, the most obvious one, I know we talked a little bit about it last night, but as the new CEO, pending on May 1st, how does Valero's strategy change, if at all, particularly as it relates to spending and returning cash to shareholders?
That was not a surprise question. I know that we have gone through the capital that we have here, and I think very clearly there has been concerns over the years that we have spent too much capital, and I know Bill addresses that every day. This year, we are going to spend $3 billion. $1.5 billion of it, as I mentioned, is on maintenance, and the other $1.5 billion is on very high return projects. As we pointed out, we got the two crude units that we are doing, and that is about half of it. Another big chunk of it is on logistics assets. A lot of the logistics assets investments, frankly, is in rail cars to allow us to move the crude. More specifically to the question, though, Lane and I have talked about this in our one-on-one meetings, and we talked about it last night.
We have a very disciplined, gated process for assessing capital projects. We start with a concept, then we go out and we do some internal work on the project, and we make a determination, does this project make sense or not make sense? If it makes sense, we meet as a group, and we look at it, and we decide if we want to allocate some capital to it, for example, for engineering or just to scope the job a little more completely. It goes through this process, each time advancing the quality of the capital estimate. So ultimately, we get to the last gate, we call it, and we have a review of the project among our leadership team, and we make an assessment as to the project. Are the returns there? Is the risk properly measured?
Do we want to spend the money on it? So we do have a very disciplined process in place, and we will continue to maintain this disciplined process going forward. We haven't given guidance for 2015 for capital yet, and quite honestly, if you asked me today to tell you what that number was, I probably couldn't do it. We have a good idea of the projects we have underway today, those we mentioned. I think many of you have heard that we're looking at a methanol project, and the early capital estimates on this methanol project were somewhere around $700 million. But that's not an approved project at this point in time. It's a project that is working its way through the gated process. The economics of that project could change if after we do some engineering, we find that it's a $1.2 billion project.
That would totally change our perspective on it. One thing I will mention about this methanol project, and it goes to risk management, is that we announced it, and all of a sudden it's like we were the pretty girl at the dance. We had people approaching us that wanted to make an investment and form a JV on the capital side of it. We had people that came in and wanted to do an offtake on all the methanol that was going to be produced. So there's this continuum of opportunities available to us to look at as we proceed down the path with this project. What we're going to do is take a good hard look at it and make a decision on how much risk do we want to take here and how do the returns look.
But that project in itself is not something that's approved at this point in time. So I think what we're going to do is just try to not get out in front of ourselves on discussing projects that are early that may not be of value. But Doug, bottom line is, I think we do have a very good process in place to provide the discipline on capital spending going forward, and we will continue to do that.
Questions from the floor. Back here first.
Given the supply-demand issues you outlined in Western Europe, could you talk about how your Pembroke, your Welsh refinery, fits into Valero's current strategy? Longer term, is this an asset that will continue to be in the Valero portfolio?
No, that's a good question. Pembroke had a good year last year. You got to remember that what we have in Europe isn't just a refinery, but we bought an integrated system. We got the refinery, we got pipeline and logistics assets, and we got a marketing business goes along with it. Even though right now we're seeing compressed margins at Pembroke from a refining perspective, we're making money on the other side of the business. We are making money over there today. As far as part of a broader strategy, the reason that we got into the Pembroke refinery was, we went through this process of assessing the assets that we had that served the Atlantic Basin, and we had Delaware City, and we had Paulsboro. We obviously divested those.
From our perspective, you can assume that we thought that we were better off having Pembroke and the Quebec refinery to allow us to arb the Atlantic Basin than those plants. We feel very good about that decision today. If you look at Pembroke's position in our supply chain, it's supplying now based on what we were able to do with the marketing business in the U.K., supplying all of its diesel locally. It either stays in the U.K. or it moves to Ireland where we have a retail business. The gasoline continues to be exported, although at much lower volumes, and we typically take that gasoline into the highest net back market. Canada is short, so a lot of the volume out of Pembroke has moved into Canada. Longer-term strategy there, I think we'll continue to look at it opportunistically.
We do have an office there where we have a supply and marketing operation, and so we would have some synergies if opportunities presented themselves. I am going to tell you, there is just nothing that we are looking at today that would encourage us to do anything.
Last one.
Go ahead.
I got it. Okay. Joe, could you just rank for me, whether by concern, threat, priority, the regulatory issues that you are facing, imports, RFS, Tier 3, I do not know, whatever other things you think you need to deal with and how they get resolved?
No, that's a good question. Lane, you feel free to share your view here too, okay? Tier 3, from our perspective, is something that I think we're ahead of the game on, okay? So that's a lower risk to Valero. Obviously, the crude export issue is something that we look at. The dilemma here is that the compelling arguments for crude exports really are, we need to have free and open markets, right? Well, I don't know if there's one of us that would look at the crude oil markets and say, "These are free and open markets." Quite honestly, you've got OPEC involved in pricing crude globally. You've got presidential permits that aren't issued, which would increase supply of North American crude into the U.S. We have the Jones Act in place.
Then you've got the RFS, CAFE standards, Tier 3, all these things that you mentioned. So the energy, particularly hydrocarbon energy, operates in anything but a free and open market. So I think our perspective is we're not opposed to free and open markets, and we're frankly not opposed to crude exports if they're taken in the context of a broader energy policy that would address all of these issues and truly allow us then to slug it out in a free and open market environment. The dilemma is how do you get there, okay? I'm not sure that we get there. So that's where I am on that. The RFS is clearly poor legislation. It's put the industry in a bad spot. It's raised everybody's cost structure. The RINs, we had them at $1.40 and change last year. They dropped off to $0.18.
Gina McCarthy speaks to the public and mentions that she's met with the biofuels guys, and she hears them, and it runs back up to $0.50. Some of that, too, had to do with people, I think that were covering their short position, going into We have until June of this year to comply with the regulation. There were a lot of people that were short, and I think you've seen buying taking place to try to cover that. But bottom line is we think that the proposed regulations, they might be tweaked a little bit, but they're going to be well below the statutory obligation that we have that was in place before. So I think you'll see the RINs markets come back off again, and reduce the cost to the industry for that. But that's bad legislation, and it needs to be amended.
The one thing that we're seeing today, which is getting a lot more attention, of course, is crude by rail. There's been a lot of talk about this, but I think we've seen that the requirements for testing and labeling what is being transported have increased, including the need to run lab tests on it to find out what the components are in the particular crude. I think you're going to see slower transportation speeds going through urban areas. It's kind of interesting. I had a conversation with the CEO of Burlington Northern, and I believe that the requirement is that we have to slow down to 40 mi an hour through urban areas. He said the previous week he took the train through Houston, and that they weren't able to get above 20 mi an hour.
In his mind, there's not going to be a whole significant economic impact associated with slower transportation speeds. There's also talk about increasing the puncture resistance and the integrity of the rail cars, which could cause some capital investment. As long as that gets phased in over a reasonable time period to allow the industry to adjust, not only the energy industry, but anybody who's shipping by rail, I think we're all going to be okay. Those are-
What's the most important one so far?
I think probably the most important one to the industry in total really is the crude export situation. Lane, do you have a different view?
It's pretty much the same. The RFS needs to be resolved. The uncertainty around it is a problem for the industry. I would have it up there also with crude exports. Certainly RFS and all the regulatory, I would say, overreach, and that's enough space.
We'll take two more questions, one at the back, and I think the gentleman here was first, so we'll go to the back first.
Okay.
I'm sorry. Do you hedge your natural gas exposure? If you do, to what degree, and do you find the market deep and liquid enough to have an effective hedging strategy at these prices?
Right. I will tell you, we have not hedged our natural gas exposure going out the curve. We look at it all the time, and last year, the market was severely contango. To put on a paper position, we were going to be doing it at $4.50 or higher, rather than the $3.50 or whatever it was that the market was giving us on a prompt basis. The way we handle our natural gas is we look at it a month in advance every month, and we make a decision, do we want to float it or do we want to fix it? That's an approach that we've used that's worked for us so far, and I think it's the approach that we'll continue to use going forward.
However, that being said, we do continue to look out the curve, and if we get to the point where there's a number we like, I think we do something. Yeah, I do believe there's enough liquidity in the market to take a position.
[inaudible] , looks like it has been pushed out a couple of years. I could be wrong.
No
If that is the case, I am just curious why that was and how are the hydrocrackers performing right now?
Lane, you want to
Yeah, Paul. They are performing great. We can run 68 all the time, and the reliability has been great, and they make a lot of diesel. What we have decided to look at is we, in fact, either this week or early next week, we will go ahead and take St. Charles up to 65. We are really sort of taking a pause to see how far can we press these units to understand the real limits and not sort of jump ahead of ourselves and engineer on top of engineering without operating experience on them. We thought we would make some room to just learn how to run the units a little bit better rather than aggressively try to increase them. If we end up where we can run 65, 68 a day without a whole lot of capital, that might be a better place to land.
That's sort of where we are on them.
Yeah, no. That's connected.
I realize there's a couple of other questions from the floor. Look, Joe, in the interest of keeping on schedule, maybe we could take those offline, if that's okay.
Sure.
Everybody, if you could join me in thanking Joe for his presence.