Welcome to the Marathon Petroleum Fourth Quarter and Full Year 2013 Earnings Conference Call. My name is Christine, and I will be the operator for today's call. [Operator Instructions] Please note that this conference is being recorded. I will now turn the call over to Mr. Tim Griffith. You may begin.

Okay, thank you, Christine, and good morning. I'll remind everyone that the synchronized slides that accompany this call can be found on our website at marathonpetroleum.com under the Investor Center tab. On the call this morning are Gary Heminger, President and CEO; Don Templin, Senior Vice President and CFO; Mike Palmer, Senior Vice President, Supply, Distribution and Planning; and Pam Beall, Senior Vice President of Corporate Planning and Governance and Public Affairs and President of MPLX. We invite you to read the Safe Harbor statement on Slide 2. It's a reminder that we will be making forward-looking statements during the presentation and during the question-and-answer session. Actual results may differ materially from what we expect today. And factors that could cause actual results to differ are included here, as well as in our filings with the SEC. Now I'll turn the call over to Gary Heminger for opening remarks and highlights.

Thank you, Tim, and good morning. I want to thank you for joining our call and webcast. Before I give my comments, I want -- on our results, I wanted to mention a few changes we have made as a result of Garry Peiffer's retirement in December. Pam Beall, who many of you have come to know in her prior role as Vice President of Investor Relations, has taken executive responsibility for Corporate Planning, which encompasses business development, economics and global procurement, as well as she's become President of MPLX. Tim Griffith, who just introduced me and will be hosting our call has added Investor Relations to his current responsibilities as Vice President of Finance and Treasurer. Beth Hunter has been promoted to Director of Investor Relations supporting Tim and will serve as the day-to-day contact for investors and analysts with help from Jerry Ewing. This is a strong team that demonstrates the importance we place on continued succession planning, growing MPLX and maintaining a robust dialogue with our shareholders and the investment community. We'll be making the appropriate personal introductions as the opportunities present themselves over the next several months. Now moving on to our highlights. The fourth quarter of 2013 was a strong finish to an excellent year for MPC. Operating performance was outstanding and our financial performance in the fourth quarter reflected a nice rebound from some of the challenging market conditions we faced in the third quarter. Speedway also had an excellent year with record annual earnings and operational excellence throughout our nearly 1,500 locations. Don will provide a little deeper look at the drivers to our financial performance in the fourth quarter and full year shortly. Importantly, our focus continues to be on the future and balancing value accretive investments with a commitment to return…

Thanks, Gary. Slide 4 provides earnings both on an absolute and per-share basis. Our fourth quarter and full year 2013 financial performance was strong. MPC had adjusted earnings of $633 million or $2.10 per diluted share during the fourth quarter of 2013 compared to $760 million or $2.26 per diluted share in the fourth quarter of 2012. For the full year 2013, our adjusted earnings were nearly $2.2 billion compared to a very strong $3.4 billion in 2012. Adjusted earnings per share was $6.84 for the full year 2013 compared to $9.79 for 2012. The waterfall chart on Slide 5 shows by segment the change in adjusted earnings from the fourth quarter of 2012 to the fourth quarter of 2013. The primary driver for the change was the decrease in Refining & Marketing segment income, which I will describe in more detail on the next slide. As shown on Slide 6, Refining & Marketing segment income from operations was $971 million in the fourth quarter of 2013 compared with $1.1 billion in the fourth quarter of 2012. The change from 2012 was primarily due to narrowing crude oil differentials and higher direct operating costs, partially offset by wider crack spreads, higher product price realizations and increased refinery throughput volume. The unfavorable earnings impacts associated with the narrowing crude oil differentials are found in the price columns for the sweet/sour differential and LLS to WTI differential. The increase in direct operating costs quarter-over-quarter is primarily due to the acquisition of the Galveston Bay refinery and higher turnaround expenses and is consistent with the guidance we've previously provided. Our earnings were favorably impacted by wider crack spreads as shown in the LLS 6-3-2-1 crack price column. All of the gross margin indicators utilize spot market values and an estimated mix of crude…

Thank you, Don. [Operator Instructions] With that, Christine, we're prepared to open up the call for questions.

[Operator Instructions] Our first question comes from Arjun Murti from Goldman Sachs.

Thanks for the additional breakdown between the Gulf Coast and Midwest, which is helpful. My question, Gary, is there's obviously a lot of questions right now with the growing light sweet shale oil production, where you can stick all of it in, in terms of the U.S. refining system. And you all highlight, for example, in your disclosures, 65% of your Gulf Coast throughput is sour crude oil. Can you provide any color in terms of, if the price incentives were there, how much light sweet could you run? I know there are various limitations, but where you desire to run it, can you provide any color on how flexible your system is?

Sure, Arjun, I'm going to turn this over to Mike Palmer. Let me give you one statistic as -- before Mike talks though. In the fourth quarter and year-to-date, we ran approximately 53% sour for the entire year and almost the same amount in the fourth quarter. So while there's a significant amount of light sweet that's available, the economics versus alternative barrel still guide us to run the light sour and medium sours. While we can run about 25 -- or 65% of our entire slate, that's not just the Gulf Coast. The entire slate, we can run about 65% in light sweet. It illustrates that we ran around 53% sour that the economics still drive us towards that decision. But Mike, if you can add some additional color.

Yes, Arjun, I guess, probably what I'd have to say is that the amount of light sweet crude that we can actually run in the Gulf Coast or at any plant is really a function of the price. It's a function of the discount relative to our alternatives. And we really can't give you a specific number. What I can tell you is that we know that within our system, we know that we still have some logistical constraints, for example, that keep us from running as much light sweet as we would like to at certain times when the differential gets really wide. We're working to get rid of those constraints. We're also going to be taking on additional barging as we go forward because we think that'll help alleviate some of the constraints. At the refineries, it's really a function of the price. So the object that we always have is to maximize our profitability. As that light discount widens, we can run more light sweet crude at these refineries. And that's what we'll do. That's what we'll do. One of the real issues is how do you handle the naphtha. And I think you know that at our refineries, we're in pretty good shape from a reformer standpoint relative to the industry average. So that's about as good as I can do for you, Arjun. We will take advantage of light sweet crude depending upon what that differential is.

Arjun, let me add one more thing. I read the piece that was published this morning by you on volatility of the crude and the light sweet and the saturation. And I thought you were spot on that we're going to continue to have a tremendous amount of volatility. But one thing I want to really put out in more detail was that if you look at the end of the fourth quarter with the extreme weather conditions that we've had across the U.S. and a number of issues in the Gulf Coast, there's been more volatility and a pull on inventory. I'm sure you know that there was a major pipeline in the Gulf offshore, Gulf Coast, that was down due to some operating issues, which took some light sour off the market then it was going to be blended with some of the light sweet. And that really upsets some of the inventory, and there's been a big draw of inventory in the Gulf Coast and up into the Cushing area. So I think this is a temporary aberration in the crude market. But again, I think your presentation that you published this morning was spot on with volatility. Once we get through these reports or get through this inventory cycle, I would expect things to settle down and for that spread to widen back out.

Gary, that's very helpful. Just a very quick follow-up here. You gave the $1 billion of potential EBITDA on the resid hydrocracker. Did you give a volume throughput and order of magnitude CapEx that goes with that as well?

Yes, the CapEx that we gave was $2.2 billion was our estimate, and that's what the feed is going to confirm and verify. That number that we expect the feed to be done by the end of the year. Timing wise, we would expect, if we were to go forward with this project to be complete at the end of 2017, mechanically complete there and start up the first part of '18. And it increases ultra-low sulfur diesel by 28,000 barrels per day. And as I said earlier, about 70% of the resid comes from within our own system today. So we're confident already with the feedstock supply that's verifying and confirming the capital that it'll take to build this.

Our next question comes from Ed Westlake from Crédit Suisse. Edward Westlake - Crédit Suisse AG, Research Division: So I was just trying to get a sense of in the fourth quarter versus the first quarter. Obviously, there's a lot of changes in terms of the profitability. Now when we think about it, there's crude discounts, there's butane blending in fourth quarter. There's losses on secondary products. Maybe give us some color as to which one of those factors you felt was the biggest quarter-over-quarter.

Yes, I guess, Ed, if you noticed on sort of our Slide 6, where we showed that other gross margin, and there's a big $540 million of gross margin. Broadly, I would say about 45% of that impact was favorable crude acquisition costs. And about 75% of that amount was favorable crude acquisition costs and refined product realization and sale -- purchase for resale. So 75% of that $540 million was explained by sort of those 3 factors. Edward Westlake - Crédit Suisse AG, Research Division: Yes, and some other companies have been saying that in the winter period, they were able to beat the cracks in the Gulf by doing more exports. Is that explaining the sort of 30%?

Well, we had a very -- we had a very strong export quarter. We averaged, I think, 298,000 barrels a day for the quarter, the fourth quarter. So that was spread between Galveston Bay and the Garyville refinery. Edward Westlake - Crédit Suisse AG, Research Division: Right, and the final question, just more strategically just on light crude runs. Maybe just remind us, if you can or willing to, about the changes that you're making perhaps at the plant level to process more light crude. Any additional thoughts in terms of adding things like pre-flash towers and splitters over and above the plans that you've already announced?

Ed, let me take you back. When we first built the Garyville expansion that opened at the end of '09, our intent was to run that at about 180,000 barrels per day. And as you'll recall, we're running this about 110,000 barrels a day above what the design capacity. And the reason is we filled up all the downstream process units from heavy and light sour to medium sour crudes that we're running, and we still have this run to room or amount to run space in the crude unit. So we have 110,000 barrel a day basically free crude system to run. Beyond that, as we said, we're becoming the anchor shipper on the Sandpiper and SAX line. We're doing crude unit work at Robinson this year. We're building the condensate splitters at Canton and Catlettsburg, and then we're working on logistical constraints in the U.S. Gulf Coast, as well as expanding our margin flexibility. So we have a number of things. And this is top of our mind on how to be able to take advantage of this light sweet crude.

Our next question comes from Chi Chow from Macquarie Capital.

I want to follow up on your answer to Arjun's question earlier. You seem to suggest that you didn't really change the percentage of sour crude runs in the fourth quarter. I'm just wondering if you could comment on the pricing dynamic you saw on the sour and medium crudes in the quarter. Did they -- I'm assuming that they were just discounted along with what we saw in the LLS spread, but any comments on how the pricing dynamic work on those crudes?

Chi, this is Mike Palmer. When we look at the fourth quarter, the pricing dynamics for domestic crude were very favorable. Of course, that was a period when the Brent-WTI spread was widening out. The domestic crudes, LLS and Mars, were both priced very attractively relative to the ARB. And that's one of the keys to the profitability in the fourth quarter. Domestic crudes were at discount, made a lot of sense. Actually, when you look at LLS versus Mars over the fourth quarter, it didn't vary all that much. I mean, it was between $4.50 and $5.50 generally. And then when you look to the really heavy barrels in Canada, they were very attractively priced as well, getting probably between $25 and $35 a barrel discount. So I think what I would say for the fourth quarter again is just domestic crudes were very well priced for our system.

Hey, Mike, how about the foreign crudes? I know you still bring in the foreign mediums, in particular, into the Gulf. Were those pricing right along with Mars?

Yes, the foreign crudes that we bring in were attractive relative to the sour alternative in the Gulf.

Okay, I guess that suggests that both Mars and the foreign barrels, that they're moving with LLS then. And is that dynamic going to continue long term in your view that these crudes seem like they're going to be priced off where LLS moves?

Yes, I think going back to the basic dynamic, we're going to have this continued production growth in the light sweet crude that's going to end up on the Gulf Coast. But I think as we've said before that other barrels, the other sour barrels, if they want to find a place in the refineries, they're going to have to compete. So we would expect -- there's going to be changes in differentials, don't get me wrong. But these other sour barrels are going to have to compete as well, and we believe they will.

And one final question, your guidance for the first quarter, thanks for breaking out the expense per barrel and by region. I'm just wondering about the turnaround expense, looks pretty high in both regions. Are the turnarounds going to be concentrated here in the first quarter? Or can you say what might be ahead for the rest of the year?

Sure, Chi, this is Don. Yes, we'll have a very heavy turnaround activity in the first quarter compared to probably all of the other quarters. But we will -- when we have big turnarounds coming up, we will continue to incorporate that in our outlook guidance with enough time period for you all to be able to model that.

And Chi, you'll recall at our Analyst Day meeting, we spoke about Galveston Bay. And I think I -- the quote that I used was we need 1 more year of -- to be able to really get the -- with the turnarounds to be able to get this plant like we want it, and so you'll see that turnaround expense. A part of it is around that plant. But our strategy and the plant is performing very, very well. Our strategy is to go in and get this plant tuned up like we want it to be. And we expect by the end of this year to have the majority of the heavy turnaround complete at that plant. And as I said, this becomes the second powerhouse refinery we have in the Gulf.

Our next question comes from Robert Kessler from Tudor, Pickering, Holt. Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: My question is somewhat related to Chi's in the North America pricing dynamics for the mediums and heavies. You had some comments about the fourth quarter. I'm interested in the first quarter, what you're seeing today. A couple of things piqued my interest. One is more pipeline capacity, I'd say heavy pipeline capacity now coming down the Gulf Coast with market lengths switching to heavy barrels. Seems to have helped narrow the Canadian differential and presumably put more heavy barrels in the Gulf Coast region on the market. What are you seeing in the first quarter as it relates to availability and pricing structure for those heavy barrels? And then somewhat related to that, the imported heavy, say, Saudis and others coming in with mediums or heavies, the Saudis appear to have narrowed their price discount versus ASCI, albeit very slightly to say $0.80 for February versus $1.90 in December. Are they effectively pulling out of the market very slightly? And is that kind of price change in the posted prices matched with any noticeable change in your kind of commercial discussions with them?

Robert, this is Mike Palmer. If you come back to your first question relating to the heavy crude, as you know, the TransCanada MarketLink line did come onstream here in January. And right now, it's primarily the light sweet line fill I think that's moving to Nederland, but we do understand that, that will be followed by heavy crude more than likely. We had already seen the Canadian heavy, and if you look at the benchmark, Western Canadian Select. We'd already seen that differential that had been as high as $35, $36 earlier, come into around minus 20 to minus 18. And it looks -- if you look at the forward curve, I mean, it appears to be fairly stable at that kind of a level. I think that part of what was happening there, even though there continues to be growth in the Canadian heavy, as you know, the BP Whiting facility did get its coker project complete and there was an additional demand in the market for the Canadian heavy. But I think as we look forward, we would expect that Canadian heavy to be still an important crude. It'll still be attractive, although we may not see the very wide differentials that we've seen in the past once you have that ability to clear it into the Gulf Coast. So I guess that's the situation that we see for the heavy crude. In terms of Middle Eastern crudes, I would -- certainly from our standpoint, that continues to be a very important part of our crude slate. And we don't have any reason to believe that it's not going to be competitive going out in the future. We would expect to see the barrels in the same basic kind of pricing relationship that we've seen in the recent past. Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay, can I ask for some clarification? You mentioned alleviating some logistical bottlenecks in the Gulf Coast region relating to crude access. Can you specify what those are? You also mentioned some more barge capacity, it sounded like. Are those related to that Gulf Coast region barge purchases or something like that?

Yes, let me -- I can't give you a lot of detail, but let me just give you my thoughts. We know -- when these pipelines get built, and Seaway was a good example, the TransCanada MarketLink is another good example. You get a trunk line that completes. And you've got trunk line capacity, but you don't have necessarily all the connectivity that you need for all the different plants that have a potential requirement for those crudes. And that sort of thing continues in the marketplace where you get basic pipeline capacity, but you don't have all the connectivity you need to bring all those barrels in. And every refiner has to look at their own specific logistics to see where the constraints are, if any, and then to correct those. So while I'm not going to get into detail, I can tell you that within our own system, we know that we continue to have these various constraints around the system. And we're constantly working on those to try and remove those constraints to bring in more crude. And we believe that most of the refiners have the same sorts of issues. That's why you see when you look at exports that continue to rise, you look at the very -- and we talk about the fact that we're not saturated with light sweet, that's what our engineers do every day, is to find ways to alleviate these bottlenecks to continue to increase when the price signals are there. So does that answer your question? Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: That's helpful. And just a quick one for me on the new regional disclosure. Did I miss it, and do you intend to break out the gross margin as well in addition to cost by region?

No, we don't intend to break out the gross margin. We intended to provide operating data that allowed people to model the -- model that.

Our next question comes from Jeff Dietert from Simmons & Company. Jeffrey A. Dietert - Simmons & Company International, Research Division: Marathon's been a leader in kind of condensate splitters and activity in the Utica, but condensate's a big issue in the Eagle Ford. And we're hearing condensate volume's rising in the Permian as well. Could you talk about the condensate supply opportunities on the Gulf Coast? Is condensate an even bigger challenge than light crudes within the Gulf Coast market? Is it tougher to blend? Talk a little bit about the condensate market on the Gulf Coast and how you see that evolving.

Jeff, this is Gary. In fact, we look at condensate as an opportunity, not necessarily a challenge. And we agree that there's going to be a tremendous amount of condensate. There are already a number of projects in position. I'm not going to get out ahead of ourselves here and give away some of our competitive thoughts. But we certainly are looking at some opportunities in and around the Gulf Coast as well. Today, we can blend some of that condensate into our system. Of course, some of the condensate is looked at as diluent to move up into Canada to bring the heavy barrel down. But we are looking more at the opportunities we have to be able to bring that condensate into our system, along with the Utica condensate that we've already announced. Mike, any more color on that?

No, Gary. I think you've answered the question. Obviously, we watch very closely the production growth that's coming from all the shale plays. And we understand and recognize that there's significant condensate. And we're looking at various ways to handle that condensate, including projects. Jeffrey A. Dietert - Simmons & Company International, Research Division: Time line kind of 2016 type in service date, so that was quickly as you could react?

Here in -- 2 splitters in Utica are one at the end of '14, one mid-'15. And then if you want to look at something ground up in the Gulf Coast, I would say your timing is pretty close, '16 and '15 time frame. Jeffrey A. Dietert - Simmons & Company International, Research Division: Great. And secondly, your 290,000 barrels a day of product exports are ahead of your expected capacity that you presented at the Analyst Day. Can you talk about some of your success in growing that export capacity more rapidly than anticipated?

Yes, Jeff. I mean, the market continues to be very robust without a doubt. And it's very interesting. It kind of comes back to what I was talking about with -- when we think about how much light sweet can we actually refine. We're well above the -- what we thought the limits were going to be in terms of our dock facilities to export finished products. But when the opportunity presents itself and the economics work, that's one of the things that we're really good at is we're really good at getting around constraints and debottlenecking. And that's exactly what we've done. And it's not only hardware, but it's the way that we schedule. It's being able to move certain products away from docks to other means of moving that product out so that we can make room for exports. It's all kinds of things that we do to maximize our profitability. And as I say, I mean that's really what we do.

Our next question comes from Doug Leggate from Bank of America.

This is actually Jason Smith on for Doug. I'm just curious. We spent a lot of time on crude, but just on the product side, as a country, we're now exporting as much gasoline as we're importing. And you guys are obviously a part of that. So what do you guys see as the impact on the U.S. being balanced on the gasoline price? Do you think we continue to price off Brent, or do you think we eventually will price off of domestic crudes?

I would think for the near future that we'll continue to price off of Brent because if you look at -- it's not necessarily gasoline. You need to look at the entire pool. We're exporting more diesel, but in order to be able to get that diesel, gasoline is going to follow along, and diesel is being priced off of the Brent market. So we would expect for quite some time that we'll continue to be priced off of the Brent market.

Okay, thanks. And just a quick follow-up, Gary, just on the quarter. I think Garyville was down for a bit in the quarter. Could you just quantify maybe the lost opportunity cost there?

We do not give that information out, Jason. But it just went down for some turnaround work, which is typical. At the end in the fourth quarter, early first quarter, it's a good time to be doing turnaround work at Garyville.

Jason, this is Don. I mean our guidance around throughput would have contemplated the Garyville refinery and any activity that was...

Oh yes, sorry. I meant more just on the margin side on any lost opportunity cost.

Yes, we do not give that information out. We think that's too competitive.

And if I could just sneak one more quick one in. I mean in terms of the export debate within the country, it's -- obviously, chatter has picked up a little bit. I mean, what are you guys hearing now in terms of the potential to export crude at this point?

Well, in fact, I've spoken at a couple of conferences, and that was a theme at both conferences earlier in January. We do not oppose export. We support free markets. And we are not in the camp of any government mandates. However, I think as this thing continues to evolve, this discussion continues to evolve, you're going to see it's going to turn into a very comprehensive discussion. It needs to consider -- when you consider accrued exports, it needs to consider the Jones Act. Jones Act is a restriction on moving both crude oil and refined product in the U.S. today. You need to consider Renewable Fuel Standard, which is a restriction on moving refined products in the market today. You need to consider the restrictions on pipeline permits, not only the one that has been in the news for a long time around Keystone, but other pipelines that are being considered in and around the U.S. So -- and then just lately, you have the -- some of the very serious rail incidents that have happened. So I think all that is going to need to be taken into context into a comprehensive discussion, Jason. And I think this will take a long time to have this debate in D.C.

Our next question comes from Blake Fernandez from Howard Weil.

Gary, you've already answered one of my questions on the resid hydrocracker as far as reaching FIB [ph] potentially by year end. I wanted to confirm that the CapEx budget of $2.47 billion does not include any spending for that project.

The current year's budget includes the capital for the engineering work that's being done this year, but it does not include any construction costs or anything like that.

Okay, so Don, just to be clear, if it were approved, let's say before year end, is there a chance that, that budget could nudge up just a tad?

I don't believe so. If we decided to go forward, we wouldn't be in the field for construction until '15 and the early part of construction will be all land piling and so on, so forth. So you wouldn't really ramp up until mid-'15 into '16.

Okay, got it. The second question, if we could move away from refining a bit. On Speedway, if I look at your supplemental, trying to get a sense of free cash flow, it looks like you're free cash flow negative in '12, and then you move to a positive position in '13. And then looking at your CapEx budget for '14, at least, by our numbers, it looks like you're slightly free cash flow positive. I guess I'm wondering at this point, it seems like you're scalable enough, sizable enough to maybe be a stand-alone. And I just wondered if you've given any consideration to a spinout like we've seen others in the industry do.

Yes, like I've said many times and will continue to say, Speedway is an integral part of our business. We measure something that's called controlled volume, where we know every day because it improves our efficiency and the way we move products through pipelines, through terminals, through trucks, finally, to the consumer. We think that's the most efficient way to move your product. And it gives us the opportunity to capture margin across that entire supply chain. And that's what Speedway does for us. We think Speedway is one of the best operators in the business, and that's seen in their new record this year in income and cash flow. When you step back then and look at a spin versus continuing to have this, as I said, a key part of our business, having -- and I've looked at others who have spun off their retail, it has varying degrees of how many years you may have a supply agreement. And 10 years, 15 years is a very short time. And then you don't have that supply, you don't have that synergy that we have today. So I'm not going to say we would never do that. We continue to look at this and study this. But I think Speedway has a long way to run as far as growing and continuing to be efficient. And I think they have one of the best backroom platforms in the business. And -- which should help it continue to grow and become more efficient. So not now, but we'll continue to watch it.

Our next question comes from Faisel Khan from Citigroup.

Just on Slide 21 of your quarterly presentation, and I think you've answered a little bit of this, but I want to clarify it. So on the other gross margin that was above and beyond what you guys realized in the indicator margins, the $658 million. I believe when you were talking about the year-over-year numbers, you said -- I assume it's the same for this number, too, is that, of the $658 million, roughly 50% is related to crude acquisition cost and the rest is related to other stuff. Is that the right way to read Slide 21 and that $658 million?

Faisel, this is Don. That $658 million is much more weighted towards refined product price realization than the $540 million that I talked about that was quarter-over-quarter. So a much higher percentage of that $658 million is product realization.

Okay, can you just go into a little more granularity? Because obviously, we're using the indicator margins, and then I'm not going to be able -- we're not going to be able to pick up a $658 million swing in some sort of other product categories. Can you go into a little more granularity in terms of what's in that number that allowed you to exceed the indicator margins?

Well, the biggest -- as I said, the biggest piece of that is the price realization. We also -- and it's always been consistently one of the items that shows up in that column is our purchase for resell activity. So that has a meaningful impact as well. But we're not going to provide any more color on that. As a much -- I would just say it's a much higher percentage. As I said, the $540 million was probably 45% crude and 30-or-so percent related to refined product realization. This is a majority of the $658 million as refined product realization.

Okay, okay, that helps. And then last question from me. With the Ho-Ho pipeline potentially for sale, do you guys have capacity on that line? And is than an asset you'd be interested in?

Well, it's certainly a pipeline, Faisel, that we're interested in. And it can be a good pipeline for us to take barrels coming from the Houston area into the Garyville refinery. That's probably about the only thing that I can say to you today.

Our next question comes from Evan Calio from Morgan Stanley.

I know there's been a lot of questions on light imports and Saudi imports, of which you take some Arab light. Clearly, it's a more important topic today. Can you discuss generally how that contract works? I guess I'm asking, if economics permitted, how you could replace those barrels. How does the timing on the contract work given the shipment? And how easy is it to run, given I know APIs are close? But clearly, crudes have different yields, et cetera, how easy is that to replace those barrels with local crudes, which also vary on the Gulf Coast?

Yes, Evan, as we've stated before, we cannot get into any details about our foreign contracts. And they are term contracts. But I'll just leave it that these barrels have to be priced competitively for us to continue to be interested in that supply. And I think that tells you that obviously, they are competitive or we wouldn't be running them. But that's as far as we can go with talking about those contracts.

Okay, then maybe away from the contract, just I mean, could -- from a refinery level, could you run other local crudes versus that crude or any other kind of run issues that relate to that?

Sure, I mean as I've said earlier, we can run up to 65%, we believe, of our total crude slate in a light sweet crude. Some of the Middle East crudes have different properties than some of the domestic crudes and vice versa. And some have different yield characteristics, but all those went into the equation and the calculus when we make our decision. And we have been -- if you look in total, there's still, I don't know, 1.5 million barrels or so of light sour coming into the marketplace, 1.5 million to 2 million of light sour coming into the marketplace. It's just not light sweet. It's light sour that you look at, too. So every day we're looking across the range of crudes that are imported into the U.S. to determine what is the maximum profit -- profitable crudes to run.

Well, inventories inflected this morning here, so some tailwind for those assets today. And maybe a second question, just to get your outlook on Tier 3. I know that, that was proposed last year. And I think EPA's to come out with that at some point in the first quarter. But I mean have you -- are you prepared to discuss potential impact and potential spending relative to Marathon spending that might be in the '15, '16, '17 time frame? Any thoughts at this juncture?

Right. We did state at our analyst meeting, we had some comment that we are prepared on Tier 3. We are not prepared yet, Evan, to get into the details because the details have not been completed yet by the EPA. We expect that probably in the first half of the year. It might even slip a little bit beyond the first half. It looks as though things are going to be spread out and give us more time to be able to get the investments made in the different plants. But it's certainly, from what we know in the early discussions, it's not onerous.

Our final question comes from Allen Good from Morningstar.

Just a couple quick questions on the exports. You mentioned the efforts you made in debottlenecking that increased your exports above, I guess, what you previously state your capacity to be. Could we assume that, that 400,000 barrels per day that you previously targeted for 2008, it's either may be conservative or could be realized earlier in light of some of this debottlenecking? Or is it a case where you actually need some new facilities now?

Allen, that's a great question. I had that same question of the team when I saw the results for the fourth quarter. But obviously, the position that we took in the fourth quarter and being able to increase the throughput was very strong, and I applaud the team that's working on this. So yes, we think we're going to get there sooner, but we do have to do some capital work by -- for the next big jump, we're going to have to do some capital work in order to be able to get to that 400,000.

Okay. And then just secondly, a lot of talk on the light crude and processing more and your ability to do so. Can you talk a little bit about the impact on yields and maybe your gasoline distillates? But specifically, how would that may change if you do increase light crude runs to the potential you have?

I'll let Mike answer that.

Allen, I guess, the main thing that you can say is that when you -- obviously, when you look at these light crudes, they do have a different yield fractions than other crude it would be replacing. And I think I mentioned to you that one of the issues you get into is most of these have a pretty good-sized naphtha cut. So you've got to be able to upgrade that naphtha. You've got to be able to reform it and make higher octane material. And that's where we've said before that we're in pretty good shape relative to the industry. But again, as those volumes grow, all refiners, including ourselves, will look at ways to handle the fractions that first provide bottlenecks. And it'll just be an ongoing iterative process to continue to run more and more of the light sweet crude.

Okay. With that, we'll wrap up the call. We want to thank everyone for joining us this morning and for your interest in Marathon Petroleum Corporation. If there are other questions or anything that requires clarification, please, Beth Hunter and Jerry Ewing will be available the rest of the day. Thank you very much for joining.

Thank you. And thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect.