Pamela K. M. Beall - Vice President of Investor Relations & Government & Public Affairs Gary R. Heminger - Chief Executive Officer, President, Director and Member of Executive Committee Donald C. Templin - Chief Financial Officer and Senior Vice President C. Michael Palmer - Senior Vice President of Supply Distribution & Planning Garry L. Peiffer - Executive Vice President of Corporate Planning, Investor & Government Relations and President of Mplx Gp Llc Richard D. Bedell - Senior Vice President of Refining

Edward Westlake - Crédit Suisse AG, Research Division Evan Calio - Morgan Stanley, Research Division Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division Paul Sankey - Deutsche Bank AG, Research Division Chi Chow - Macquarie Research Blake Fernandez - Howard Weil Incorporated, Research Division Douglas Terreson - ISI Group Inc., Research Division Paul Y. Cheng - Barclays Capital, Research Division Jeffrey A. Dietert - Simmons & Company International, Research Division Faisel Khan - Citigroup Inc, Research Division Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division Roger D. Read - Wells Fargo Securities, LLC, Research Division

Welcome to the Marathon Petroleum Corporation First Quarter 2013 Earnings Conference Call. My name is Christine, and I will be your operator for today's call. [Operator Instructions] Please note that this conference is being recorded. I will now turn the call over to Pam Beall, Vice President of Investor Relations. You may begin.

Hey, Christine, I'd like to make sure that I'm coming through okay because your initial opening remarks were garbled. So can you hear me okay?

I can hear you. Would you like me to repeat again?

No, but when you speak, you are breaking up. So I just want to make sure if there's a way to make sure that the audience can hear okay, and that we'll be able to hear them okay as well.

You're coming in clear on my end.

Okay, all right, very good. Well, we're going to go ahead and proceed then. Good morning, and welcome, everybody, to Marathon Petroleum Corporation's First Quarter 2013 Earnings Webcast and Conference Call. The synchronized slides that accompany this call can be found on our website. And on the call today, we have Gary Heminger, President and CEO; Garry Peiffer, Executive Vice President of Corporate Planning and Investor and Government Relations; Don Templin, Senior Vice President and Chief Financial Officer; Mike Palmer, Senior Vice President of Supply, Distribution and Planning; and Rich Bedell, Senior Vice President of Refining. If you turn to Slide 2, please read the Safe Harbor statement. It is a reminder that we will be making forward-looking statements during the presentation and during the question-and-answer session. Our 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 Securities and Exchange Commission. And now, I'll turn the call over to Gary Heminger for some opening remarks.

Thanks, Pam, and good morning to everyone. Thank you for joining us. If you'll please turn to Slide 3. Our strong financial results this quarter reflect the strategic expansion and optimization of our refining system, favorable market conditions and increased income from Speedway. Since the completion of our Detroit Heavy Oil Upgrade Project in November of last year, this project has provided our system with greater flexibility to refine larger volumes of price-advantaged crudes, including Canadian heavy. The refinery quickly reached its design capacity and performed very well during its first quarter of operation. Also contributing to our financial performance this quarter was the acquisition of the Galveston Bay refinery on February 1. Results from the first 2 months of operation have been consistent with our expectations. Located on the Texas Gulf Coast, our Galveston Bay refinery is well positioned to process growing supplies in North American crude oil, with expanding access to price-advantaged feedstocks and an array of complex processing units, we're enthusiastic about the prospects of this facility to enhance margins and further leverage dynamic market trends through this strategic acquisition. We are working hard to integrate this large, very complex refinery and the related assets we acquired into our system, and we are pleased with the enthusiasm and professionalism of the employee team. Speedway also had a very strong quarter. It posted increased segment income, primarily due to higher fuel margins and additional revenue from the stores that were acquired last year. We announced today that we have agreed to sell MPLX an additional 5% interest in Pipeline Holdings for $100 million. This transaction, which is expected to close on May 1, will increase MPLX's interest to 56% from the 51% it held since initial public offering in October of 2012. We believe this drop-down, along with expected throughput increases, positions MPLX to support distribution growth in the near term and is consistent with our intent to provide an attractive growth profile over the long term. MPLX also announced today an increase of $0.01 per unit to its quarterly distribution, raising it to $0.2725 per unit. This is the first drop-down following the IPO. This transaction, along with the increase in its quarterly distribution, demonstrates our commitment to support the growth of MPLX. We continue to focus on our commitment to balance investments in the business with returning capital to shareholders. During the first quarter, we returned $547 million to the shareholders through share repurchases and the payment of $116 million in dividends. As of the end of the quarter, the total remaining share repurchase authorization was $2.2 billion. And now I will turn the call over to Don Templin to review our financial results for the first quarter.

Thanks, Gary. Slide 4 provides earnings both on an absolute and per share basis. Our first quarter 2013 earnings of $725 million reflects $129 million increase from the $596 million we earned in the first quarter of 2012. Earnings per diluted share were $2.17 for the first quarter 2013 compared to $1.70 during the same period last year. I should note that, as a result of our share repurchases, the weighted average number of diluted shares outstanding during the 2013 first quarter was 333 million compared to 350 million in the first quarter 2012. As of March 31, 2013, 327 million common shares were outstanding. The waterfall chart on Slide 5 shows, by segment, the change in earnings from the first quarter of 2012 to the first quarter of 2013. The primary driver for the change in our earnings was the increase in Refining & Marketing income, partially offset by additional income tax expense. The improvement in Refining & Marketing segment income was primarily the result of a higher refined product production and sales volumes attributable, in large part, to the acquisition of the Galveston Bay refinery on February 1, 2013. The increase in income tax expense is primarily a function of higher earnings during the first quarter of 2013. As shown on Slide 6, Refining & Marketing segment income from operations was just over $1.1 billion in the first quarter of 2013 compared with $943 million in the first quarter of 2012. The primary drivers of this increase were the contributions from 2 months of operating the Galveston Bay refinery and the first full quarter of upgraded operations at Detroit, partially offset by increased operating expenses or costs. Utilizing market indicators and actual refinery throughputs, we estimate that the Galveston Bay refinery contributed approximately $150 million of EBITDA for…

Thanks, Don. [Operator Instructions] And with that, we are now going to open the call, Christine, to questions.

[Operator Instructions] And our first question is from Ed Westlake of Credit Suisse. Edward Westlake - Crédit Suisse AG, Research Division: Just on Galveston, could you give us an idea of the crude cost in the quarter, perhaps relative to LLS? I understand, I think, you're still running the old slate and just wondering, in terms of progress of switching out imports for domestic crudes, and general comments there.

This is Mike Palmer. Ed, I'm not sure that we can give you the number, the difference between the crude slate and WTI or LLS. But I can tell you that, if you look at the first quarter, we closed on this transaction in February and, of course, the February supply was arranged by the previous owner during the month of January. So we've really been involved in formulating the crude slates just during March in that quarter. When you look at this plant, overall, and if you looked in the appendix, at the MPC Crude Slate, you can see that we -- at this plant, we don't run, at least in the first quarter, quite as much WTI-based crude as we did in the 6-plant system. And of course, that'll be dictated by the marketplace over time. The other thing is that's important in this plant is that we do continue to see value in some foreign sweet cargo crudes, which is related to the aromatics business at the plant. So again, we're working to optimize the crude slate everyday and the market will dictate the crudes that we purchase. Edward Westlake - Crédit Suisse AG, Research Division: But in terms of being able to capture a discount to crude, is there any sort of sense of how many thousand barrels a day you could process at Galveston to take advantage of domestic discounts?

Ed, what I would say is that, if you look at the -- where this plant is located and its access to domestically produced crudes, what we're starting to see is that pipelines are getting built into the Houston area. And I'm sure you're aware that the Longhorn pipeline has just recently begun. Permian Express will begin shortly. We're going to continue to have a buildout of pipelines that are going to feed this refinery. So as domestic crude continues to grow, we expect that we're going to see that crude being run by this plant. We think it's very well positioned for that going forward.

Our next question is from Evan Calio of Morgan Stanley.

My question, my first question -- yet, I'm just trying to understand the sizing and the overall drop-down strategy. What you sold, 5% in Pipeline Holdings for $100 million, but you're still in net cash position, MPLX debt-free, $500 million of credit. I know you got assets in the quarter with the Texas City acquisition. So, I mean, can you just kind of talk me through the strategy on the sizing of the first drop? And I have a different question, please.

Sure, this is Garry Peiffer. I think we've been consistent, both when we did the roadshow before the IPO and since the IPO, that we're looking at this MPLX as a long-term, very transparent, consistent growth type of vehicle here, and we plan to grow this business both through tariff increases, organic projects that add value and acquisitions. And when we look at the fact that our goal and it's our strategy to have annual distribution growth in the top quartile of a high-growth, drop-down peers, this is the amount of distribution, or, excuse me, drop, that we felt we needed to lease from a first-drop standpoint, put into the new entity, only 6 months after we went through an IPO as well. I think dependent upon everybody's outlook, well, I think a lot people might have expected us to do the drop a little bit later than 6 months, but we felt the timing was good to get the first drop done at this point, which gives us more earnings power from that drop earlier on in the life of MPLX. So it's really our goal to achieve this top quartile annual distribution growth that -- not dictated, drove us to this type of drop.

That could -- certainly have the assets at the parent level. Let me ask you a different question yet related. I believe you guys are investing in condensate splinters associated around your Ohio asset in Canton and Catlettsburg, to process and provide advantage condensate as it grows from Utica. Can you provide any details on kind of costs and potential volumes and when you potentially could see those units on stream and also whether you think those are suitable, potentially, for MLP? I'll leave it at that.

Well, the last part of your question, yes, they're suitable, they qualify for an MLP. So that's the easy part of the answer, but I think what our goal is here, is to -- today, we've said that, at our Canton and Catlettsburg refinery, we believe without any additional investment, we can run roughly 20,000 to 30,000 barrels a day in total of condensate at those 2 facilities. As the amount of condensate grows there, we want to be in a position to make sure that we can handle more than that amount of volume, which we expect to come online maybe in a year or 2. But we are not in the exploration business, we are just in the refining business. So we're positioning ourselves with these condensate splinters, which we announced, that when completed, we could go from about 20,000 to 30,000 barrels a day to about 60,000 barrels a day of total condensate throughput. We've kind of pegged end of 2015, 2016 type of timeframe for these new units to come online. That's going to really be driven by how quickly the condensate production ramps up there. So we're doing the engineering. But we haven't finalized exactly when we're going to come online with those new units. But again, we'll be in a position, that once we exceed that 30,000 barrels a day or so, that we will have -- be in a position to have the condensate splinters there, to be able to process the higher volumes.

Great. Any estimate on cost as well? And I'll leave it at that.

I think, we've said previously that when you look at all of the investments we're making in the Utica, we're investing in some barges, as you know, we announced that we're -- signed a letter of intent to convert our Wellsville terminal into a barge-loading facility for crude and condensate. So the whole complement of investments in that area is about $300 million over the next few years is what we're looking at. So we haven't split that out into particular assets, but roughly $300 million over the next 2 to 3 years.

Our next question is from Doug Leggate of Bank of America Merrill Lynch.

I'm not sure who wants to take this one, but it was being -- before it came onstream, I guess, you've given some indication as to how you expected the contribution to look. I think you mentioned the numbers on your prepared remarks. So I'm just wondering if you can kind of characterize how the project's actually behaving, relative to expectations and any differences in your view going forward. And I have a follow up please.

Doug, this is Gary. Yes, we had given some earlier indications of $200 million to $350 million, and we believe after our first quarter of operations that we are right in that sweet spot, and the plant performed very, very well, as we stated in our remarks in the first quarter. So I'd say we're right on target.

Okay. Great. Is there any debottlenecking potential down the road, Gary? Or is it pretty much running at capacity now?

Well, let me -- may I ask Rich Bedell to talk about the next step after -- we brought it up, as we said, and quickly got it up to its designed capacity, and now they are -- they will work on the next steps. Rich?

Yes, that's right, Gary, I mean, Doug, as you know, we've got it up and it's running very well at that design. And as we go forward, we're looking at debottlenecking opportunities, as we find -- as we gather more information, do more engineering. So I'm sure with -- as with any of the expansions, there's going to be some debottlenecking in the future.

Got it. Gary, my follow up is really -- you've been quite vocal about your views on differentials. And obviously, there's been a lot of moving parts this past quarter. So I'm just curious if you could bring us up-to-date with how you're seeing -- or your view of the world as in terms of the sustainability of the end line versus international -- the discounts, and then perhaps a comment on the heavy outlook as well? I'll leave it at that.

All right. Thanks, Doug, and you're right. We have talked about that a number of times, but let me ask Mike Palmer, who runs all of our daily supply operation to give you his view. Mike?

Okay, yes. Thanks, Gary. Obviously, you've watched the transatlantic arb, the difference between Brent and WTI, that's come in since early February from a level around 2,200 or 2,300, to around 10 today. A lot of that, I think, that we believe was caused by the weakness in Europe in a very, very heavy turnaround season. And if you look at the WTI side of the equation, the inventories at Cushing really have not come down. They're still around 51 million barrels. But again, I talked earlier, I mentioned a couple of pipelines from the Permian that will direct Permian crude into Houston. So we do think that we're going to see the Cushing inventory start to come down this year. So I guess what we would say is that, with this big move that's taken place down to just a little bit below $10 on the spread, I don't think we'd be at all surprised if that spread would start to move out a little bit again. I don't think, personally, that it's going to reach the kind of levels that we saw before in the $20 level. But to have that arb trade between $10 and $15 would certainly not be a surprise.

Our next question is from Paul Sankey of Deutsche Bank.

Just as a direct follow up, you did a nice job there on WTI-Brent. Can you talk a bit about heavy versus lighter crude spreads? And also, for you guys particularly, the sweet/sour ratios, that would be interesting, too.

Yes, this is Mike Palmer. I guess, probably the most important one to talk about would probably just be the Canadian crude. And if you watch the heavy Canadian closely, you would have seen kind of an unusual pattern that occurred this year. We did have the spreads that started to come in, basically in May, to around $15 on Western Canadian Select. And now -- and that really was related to a number of production problems that were occurring in Canada. Many of those have been resolved. Production is now increasing, and you watch the spread that it started to move apart again to more, what I guess I would call, seasonal levels. I guess when we look at what's happening in Canada, we're still very optimistic. Exxon is bringing on their Kearl project. We believe that, that crude will start to flow into the marketplace in July. I think that'll be a very important source of heavy crude oil for the market. And in addition to that, if you look at some of the other production for the rest of the year, we think it's very likely that we're going to see Canadian heavy production increase another 250,000 barrels a day by the end of 2013, in addition to the Kearl. So we continue to be very optimistic about the heavy Canadian supply.

Great. And then sours?

I'm sorry.

Sour crude. That's obviously a very important differential that we look out for you guys, the sweet/sour spread.

And you're thinking in terms of what? LLS March?

Just in the context of what Doug asked, which is where we've been, where we are today and where we're going to, from here.

I think, again, when you look at the very big picture, certainly, one of the things that is going to continue to happen is that, in the U.S. is we're going to continue to see this light sweet crude continue to grow. So I guess I would expect that as we move forward, you're going to continue to see probably the most attractive differentials being in terms of these light sweet crudes, the Bakken, the Eagle Ford, the Utica, that sort of crude going forward. But having said that, I think that, at the same time, we see very good production growth in the U.S. Gulf of Mexico. So we would expect to see the Gulf of Mexico being attractive as well.

Yes, I guess, the anomalous one would be the premium of LLS that we're seeing. I assume that you're not expecting that to continue as the pipes are developed on the Gulf.

No. We're not, and I think that, actually, if you look at it today, we can reconcile Brent -- LLS being $2 to $3 over Brent today. On the Gulf Coast, there's probably $1 difference in the quality, the value of the 2 crudes. And in addition to that, it cost a couple of dollars to bring a barrel of Brent into the U.S. Gulf Coast. So with LLS $2 to $3 over Brent, I think that a U.S. Gulf Coast refiner today would probably be indifferent, on average. Everybody's a little different. But as we move forward and we continue to see the growth in the U.S. domestic shale plays, we would very much expect that LLS will trade at a discount to Brent.

Great. If I could throw in one key question, which would be, Gary, can you just talk a little bit more about Galveston Bay? There's an earn out there, I think, but can you also talk about how you feel about the costs and how you can change performance there, given that you're now 2 months in? And I'll leave it there, I promise.

Well, thanks, Paul. I was hoping you're going to ask a question about Chicago dips instead of Galveston Bay, but I'll leave that for another time. Paul, we're very pleased with Galveston Bay, on the front end. We only have 2 months of operations that were just reported. The processing kit, we're very pleased with, we had a turnaround right after we took over the asset, which was planned. And we came out of that turnaround in very good shape, but we have a lot of work to do. And I will say that the employee base that -- in the acquisition, is very energized and very pleased to be working with Marathon. And I think that is -- since we have a very strong base, our employee base and interest in the plant, I think that is probably the most important thing. Now as we go forward, to go in and get some of the units turnaround over the next couple of years, our plans are such that, that'll happen. But you look at the financial performance, $150 million of EBITDA in the first 2 months. We're very pleased with that. And we have a very, very strong team that we put in place to operate this plant, and I think we will perform well there.

Our next question is from Chi Chow of Macquarie Capital.

Great. Just further on Galveston Bay. Mike, you talked a little bit about crude slate optimization activities going forward, but can you give us some guidance on what to expect on yields between gasoline, distillate and pet chems?

Chi, this is Garry Peiffer. I think, in the past we pretty much said and, for the time being, it's probably reasonable that it's roughly 1/3 gasoline, 1/3 distillate and 1/3 petrochemicals, at the moment. So intermediates, I mean, the intermediates, so we're going to continue to optimize that and, again, we've only been operating it here for a few months so we're trying to see where the sweet spot is for yield and the crude slate. So that's kind of where we're at the moment, and it is a bit less, in terms of gasoline yield than our other facilities would be, but that's just the market and the processes that they have in place there at the Galveston Bay refinery.

Okay. On the pet chem side, what sort of products are you producing at the plant? Are they mostly aromatics? Or there's...

Yes, Chi. This is Rich Bedell. Yes, we have a large aromatics production, as well as propylene. And so that's primarily at this benzene, toluene, xylene and propylene.

Okay. I guess, Gary, you talked a little bit or mentioned Chicago, I kind of want to ask you about near term here. There's been certainly a lot of flooding activity in the whole Midwest region, can you talk about any impact to your refineries or your other assets due to the flooding? And maybe comment on the margin strength there, we're seeing.

Well, fortunately, Chi, we've not had any flooding or any problems with our refineries. Robinson, Detroit, Catlettsburg are running full out. We have a little bit of a maintenance going on at Canton, but it's still running well. But the -- what you look at, with the problems of the river system, being able to get product down the river, due to the flooding, I think are -- were possibly some turnarounds from some of our competitors in the Midwest. And thus, led to very high crack spreads. They've been in the high teens to low $20 on the Chicago side here for the last couple of weeks. So we expect, and you look at the pipelines, certainly, the market is looking to replenish the inventory, when you look at Explorer and some of the other pipelines that are full coming north. But we've been very fortunate. We haven't had any problems in our plants.

Good. So it sounds like you're capturing a lot of the upside?

Yes, sir.

Our next question is from Blake Fernandez of Howard Weil.

I was hoping you could maybe give us an update on the export market? Obviously, we see natural gas prices moving up a bit. Differentials have come in, at least, at the beginning of 2Q, and I think rumblings of Venezuela ramping back up. I was just curious if you could give us a feel for how that arb spread looks.

Blake, this is Mike Palmer. If you -- again, if you looked at the numbers, you'd see that in the first quarter, we did export about 121,000 barrels a day of diesel and about 9,000 barrels a day gasoline. And in the fourth quarter, we were just -- we were a little higher than that. We were about 151,000 barrels a day of diesel. The market will dictate to us kind of everyday how much we actually export. We are always looking at the tradeoff between selling export barrels and selling bulk into the pipelines. So we're looking at economics every day. I think that, in the first quarter, there were a number of factors that tended to cause a bit of a weakness in the export market. Certainly, there was Europe. Europe was fairly weak. We had more competition in the U.S. Gulf Coast with Motiva coming on. And with a weak harbor, New York Harbor, I think that there was competition from the New York Harbor that was a little unusual as well. And there may have even been some volatility from the uncertainty surrounding RINs. So it was a little weaker in the first quarter. We continue to expect that exports are going to be a very important part of our business, and we're very positive about exports going forward.

Okay. Great. The second question, you mentioned RINs, and I don't mean to get into the regulatory front too much, but I am curious on the earn out that you have on Texas City. Can you help me understand, is any potential RINs increase, is that part of the margin calculation that dictates your payout or does that come in after the fact?

No, Blake. It's based on a gross margin calculation, and you look at the ASCI index, and Garry Peiffer, I think, has the details here.

Yes, this is Garry Peiffer. It's just based upon the spot market values for the refined products. So whatever the spot market values are for the refined products, that's what goes into calculation. Now to the extent that RINs affects the spot market values, there will be an impact. But the actual calculations, just based on spot market values, for the ASCI index, as well as for the refined products.

And also, Blake, you need to look at the output, as Gary had mentioned earlier, about 1/3 of the output is on the petrochemical side, and that does not carry a RIN with it. It's not in the calculations. It's just a 3, 2, 1.

Right.

Our next question is from Doug Terreson of ISI.

My question's also on Galveston Bay, but it's a little bit more broad. I think a few minutes ago, you mentioned the opportunity related to advantaged crude oil, and it just sounds like you guys are just scratching the surface in that area. But there were other categories, too, that were opportunities on this transaction. Meaning product logistics and synergies with other Marathon refineries, market integration and some more. And so, I realize it's early, but I just wanted to see if you could provide any insight or color on the opportunities that may materialize related to that plant, thus far.

Sure, Doug. And our strategy, when we purchased this plant, is that we were not going to purchase just a merchant refinery. We picked up 1,200 branded locations, approximately 1,200 branded locations, 4 terminals and Colonial line space. We have been able to utilize some of our Colonial line space. So far, 3 other intrastate pipelines we picked up. So all these things encompass opportunities and synergies. As Mike mentioned earlier, the month of February, the crude has already been purchased and we needed that to have a smooth transition. But as we go forward, certainly, we're looking at synergies, not only with our current Texas City plant, but other plants, and because we have the distribution assets that we can move feedstocks into the Midwest if we need to, or we can move things from our Texas City refinery over to this plant and vice versa. The other thing that we're looking at, that we think are going to give us some opportunities -- and we're a very big supplier into the State of Florida and, heretofore, we had supplied a lot of that out of Garyville. Well now, we can move bigger ships into Florida and be -- and pick up synergies from just the efficiency and the way, as Mike Palmer was just talking about, exporting into the South America, Latin America markets vis-a-vis Europe, and how we -- the parallels we have out of Garyville versus Galveston Bay. We have some good logistics that we can pick up there. So all of those things are in the works right now. Again, we've only been operating for a few months, but we certainly have all those things in our plans and how I think we can pick up some further efficiencies on the way we loads ships.

Our next question is from Paul Cheng of Barclays.

I have to apologize. I joined late. So some of the questions that you may already answer. Gary, have you guys provided any financial information in terms of the BP Texas City for 2 months? What kind of financial contribution there may have been?

Yes, Paul. This is Don Templin. We indicated on the call that the incremental -- estimated incremental EBITDA from Galveston Bay for the 2 months was $150 million.

After tax or before tax, Don?

EBITDA.

EBITDA, okay. Don, do have some balance sheet data, what is the market value in excess of book for your inventory?

$6.1 billion.

$6.1 billion. And Don, the working capital for the quarter is a positive $1 billion. Is it related primarily to the timing of the tax payment or there is something else?

No. It's a combination of a number of things, Paul. But broadly, our payables are up $2.5 billion, and that payable increase is a combination of 3 things: a price increase, crude oil prices were higher at the end of the year -- at the end of March than they were at the end of the year; and then a volume increase because of Galveston Bay; and then there's also a volume increase because, in December, we were heading into a turnaround period and now, we're heading out of a turnaround period. So payables were up about $2.5 billion. Receivables were up $900 million, primarily related to Galveston Bay. And then net inventories, after the inventories that we acquired, we acquired about $900 million worth of inventories as part of the Galveston Bay acquisition, but net inventories were up about $500 million and that was largely related to price changes.

Okay, very good. And Gary, just curious that with Hess putting up their retail and wholesale terminal business up for sale, strategically speaking, does it fit into your system or that is the -- they really is primary in the Northeast and that doesn't really fit to you guys?

Well, Paul, if you look at their terminals, they're not only in the Northeast, they're also in the Southeast. So they're across the entire Eastern Seaboard. And their retail really encompasses the Eastern Seaboard as well. The only place we would have -- we don't have any direct control of retail in the Southeast markets today. We have a large branded presence. So I would say if there's any overlap, certainly, it would be a step out and we're -- I complement Hess, I think they have very looking good-looking assets.

Okay. And on -- I think, earlier, that you probably may have already mentioned, on BP Texas City with their crude purchase agreement that is going to be over soon and you start to utilizing your own trading department and all of that, what kind of potential benefit that we may be seeing? I mean, will you be able to quantify the amount?

Well, Paul, that agreement was only for one month. It was just in transition. They purchased for the month that we were taking over. So there was no agreement beyond that, and we're going to be very careful not to get into the types of crudes and stuff that we're going to buy for competitive reasons. But we are -- Mike and his team are deep into optimizing this plant as we speak.

And for the month of May, is it still their old purchase agreement or that is based on your new agreement already?

No. It's our own, and we started our -- Mike, we started our own in March?

It would have been March, Gary.

March. So we've done March, April already has been our own crude purchases.

Okay. A final question for me. I think there's a debate in the industry, at least in the investment community, that butane and naptha may be increasingly become so abundant that pricing will be very attractive. So the question is that, can you bring more of those products into your gasoline pool? Or that you're already maxed out? And if the price really become very attractive, what needs to be done in order for you to be able to bring more and that how much more, what is the maximum you can do?

This is Rich Bedell, Paul. On butane, you're really limited by the gasoline specs on vapor pressure, and we already blend up to the max there. On naptha, it's just going to be a play between intermediate price or running crude and generate your own naptha. So we'll just take a look at that, how it happens.

But, I mean, can you actually blend more of the naptha than what you currently already existing in the gasoline pool, I guess that's the question. That's stretching between what you buy from the crude and generate your own naptha or that you purchase. I'm talking about on an absolute level, can you blend even more than what you already did, to date?

Theoretically, yes, you can do that. You can -- you have to adjust your octane, you have to adjust the -- re-optimize your plants and that may not be the optimal solution, but we look at those economics all the time and decide how we want to blend it and what's optimal.

But there's no -- so that means that just probably need capital investment in order for you to do substantially more?

I wouldn't say investment, Paul. I would say it's optimizing. If it's the optimal way to blend today, we would be doing that. So what Rich is saying is, we have some room. It's just, everyday, we will run our optimization models to determine what is the best.

Our next question is from Jeff Dietert of Simmons. Jeffrey A. Dietert - Simmons & Company International, Research Division: TransCanada recently announced that Keystone XL, the Northern Atlantic, has been delayed into the second half of 2015, and I was hoping I could get some commentary from you on how you think that impacts potential logistics? Does it make rail more attractive? Would you consider rail at Garyville and Galveston Bay? And how does that impact your plans on the pipeline side as well?

Jeff, this is Mike Palmer. Yes, the delay doesn't come as a big surprise to us. We were expecting that it would be delayed from what they had earlier said. But the other thing is that you have to also factor in, the Enbridge Gulf Coast Access pipeline that should be complete in 2014. So I mean, as you know, we're already -- there's already the Seaway line that was reversed, from Cushing down to the Gulf, and that line is -- the plans are to twin that line, and then Enbridge is going to build another large diameter line that's basically going to twin Spearhead. So it's not as if there won't be an outlet for significant additional volumes of Canadian crude into the U.S. system. So -- and I think that when that happens, it will have an impact, certainly, on the incremental supply, it will give the incremental supply out of Canada another home. There could be some additional railing that occurs as well, but that's very expensive, and I don't see that as a long-term solution for Canadian heavy crude. Jeffrey A. Dietert - Simmons & Company International, Research Division: And just quickly, with the Permian pipes coming in and the Seaway volumes that are already there, are you seeing a price differential from Houston versus St. James for similar quality crudes? And how much might that be?

Well, the Longhorn pipe just began and the Permian Express has yet to come on, so it's not as if we have a lot of pipeline capacity that's come in yet. But we will always expect that there will be some differential between Houston and St. James, because the crude is being produced in the West and the transportation cost into Houston is going to be less than it is into St. James. And that's going to be several -- $2 to $3, depending upon how you move it.

Our next question is from Faisel Khan of Citigroup.

I just want to get a clarification on Slide 2. The percentage of WTI-priced crude at 22% for the second quarter, does that also include WCS?

It does not.

Okay, what would that number be for the quarter?

We don't give that number.

Okay. And then just one last question on the -- you guys talked about the chemicals product yield out of the Galveston Bay facility, but can you give a little bit more detail on that, between aromatics and olefins, because they're widely different sort of products and product margins, so that would help us understand a little bit the profitability of the refinery.

This is Garry Peiffer. We really haven't broken it down to that level of detail, and it's really change within valuation, U.S. pricing, so, at this point, we just don't break it down to that level of detail.

Our next question is from Robert Kessler of Tudor, Pickering, Holt. Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: A question about your Utica investment plans there and the incremental condensate splitting you've got planned. Having done the engineering now, presumably you've profiled the yield structure out of a typical barrel of Utica condensate. Can you give some indication as to what the product mix looks like, as you've engineered it?

Okay, Robert. We are in the -- when we say we've engineered, the conceptual engineering is complete. We are just in now to the front-end engineering and we do not have the yield structures and optimizations complete at this time yet. So it'll be awhile until we have that finished. Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Can you provide a rough indication on what you're seeing for total Utica volumes right now? And maybe some kind of split between crude and condensate?

Mike can handle this for you.

Yes. I can give you a little information. Obviously, the Utica production has come on more slowly than was anticipated. I think we've talked before about our volumes being in the 2,000 to 3,000 barrel a day range. That's still the case today, and it's somewhat volatile. But I think the important point with the Utica is that there have been a lot of wells drilled. I think the latest numbers that I have is there have been over 600 permits issued, there have been just slightly over 300 wells drilled and you've only got 89 of those that are producing. So you've got 70% of the wells that have been drilled and are waiting to get hooked up to gas processing and that, really, is the bottleneck right now. You've got companies out there that are spending billions of dollars on this infrastructure, and we fully expect to see our Utica condensate volumes ramp up significantly this year and then significantly, again, in 2014. So it still looks very optimistic to us. Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Last one for me. Can you provide the average throughput for the quarter with the 2 months that you owned Galveston Bay?

No. We can't. We do not give out individual refinery information. Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: . You did say that you went in and turned around just after purchase. Can you give some indication of how many days and what portion of the refinery was down for that turnaround?

Yes. Rich can handle that here.

Yes. There was a section of the residual hydrocracker unit, so that was just that portion of it and some catalyst change and so some hydrotreaters.

Our next question is from Roger Read of Wells Fargo.

I guess to keep on with the Galveston Bay parade here, at the time you acquired this unit, you indicated, I believe, $700 million to about $1.2 billion in annual EBITDA. Obviously, good start with the first 2 months in the first quarter. I was wondering with the crude changes with, I would say, overall, the ability to probably run it a little more efficiently than the previous owner, are we thinking the top end of that range now for 2013? And can we think of it as better in '14, again, as you pursue the turnarounds and improve efficiencies?

This is Garry Peiffer. When we gave that previous guidance, we were anticipating some of those things occurring in that guidance. So we're still in that same band of EBITDA, and the first 2 months, as suggested, kind of puts us right in the middle of those numbers. So I think we still feel comfortable, that range of the guidance that we gave previously.

And Roger, this is Don Templin. I mean, in that range, the price that was used was -- that the top end of the range was at $15 or so, for the ASCI 3, 2, 1 and the bottom end of the range was $11, and we're right in the middle of that. So I mean, I think, from a modeling perspective, that's how you would think about it.

Okay. And that actually kind of helps me lead into the next question which is, we look at the -- there are a lot talk about the kind of light-light spreads here. But if we look at the light-heavy spreads, we've seen those tighten up quite considerably, kind of from the end of last year into beginning of the second quarter. Can you maybe help us understand a little bit how you can move around? Which heavies you're able to use? Maybe how much flexibility you have, in just a broad sense along the Gulf Coast, to kind of counteract that contracted spread?

Yes, Roger. This is Mike Palmer. As these spreads move around, Roger, I can tell you that we have almost complete flexibility. We're very closely watching spreads, for example, between Mars, Poseidon, Southern Green Canyon, the medium sours, as opposed to LLS or Eagle Ford, or one of the other light grades, light sweet grades on the Gulf, and these volumes are basically all spot. So from month-to-month, we -- and not only month to month but from day-to-day, we will back out sour and bring in sweet, if that's what the economics say to do or vice versa. So we have tremendous flexibility.

Okay, but, I mean, fair to say that as the spreads have closed, overall, that's going to impact, I mean, obviously, pick a better crude on a given day. But I mean, all in all, we have seen a contraction as we kick off Q2 here. I was just wondering what kind of impact that could have on sort of a broader Gulf Coast refining margin.

Roger, why don't we get back to you and we'll be able to answer that question in more detail. Pam will call you back to review that, okay?

Our next question is a follow up from Ed Westlake of Credit Suisse. Edward Westlake - Crédit Suisse AG, Research Division: I thought this would have been asked already, but just on the RINs. Maybe -- I don't want to get your blood pressure up by the end of the call, but what are you doing to reduce exposure and any thoughts about things like using biodiesel to meet ethanol RINs, et cetera, just to limit the potential upside to those costs next year?

Ed, this is Mike Palmer. Obviously, this has been on our minds and not just in the current market, but we've been looking at this for, obviously, the last several years. And we've made investments within our system to be able to blend as much, not only ethanol as possible, but also the biodiesel. So we're in relatively good shape. Obviously, we still have a purchase requirement for RINs. But we've got a very good team that's looking at various ways that we can produce RINs outside of the norm, and that could be in a number of different ways. So just rest assured that we have a number of things that we're looking at doing that could reduce our RIN exposure and too early to talk about anything specifically, but we're going to continue to look at that.

This is Don Templin. We did, for the first quarter, we were -- we paid about or we expensed about $15 million, or purchased about $15 million of RIN a month. And last year the comparable number was about $10 million a month. Edward Westlake - Crédit Suisse AG, Research Division: Yes, I guess sort of March was probably much higher than the average in the first quarter. I don't know if you have that number.

We don't give it by month. I'm sorry, Ed.

This is Garry Peiffer, again. On that sweet/sour differential, we've given the sensitivities in the past but now with the more capacity or the bigger capacity with Galveston Bay, every dollar change in that sweet/sour differential that we included in our market metrics, that we put on our website, equates about $225 million of after-tax financial effect. So every dollar has that type of sensitivity to our bottom line. $225 million annually per dollar change after tax.

And our next question is a follow up from Paul Sankey of Deutsche Bank.

Yes, I just thought of the RINs thing, I just wondered how you expect 2014 to play out? Because obviously it looks like it's going to be a major shortage, that gets even worse in 2015.

Well, Paul, I will say it and it'd be very hard to forecast other than if you look at the total math and reaching the blend wall here in 2013 and not having available the cellulosic option and advance cellulosic is in question, certainly we've had -- the industry had several conversations with the EPA and members of the administration to really talk through how to combat this issue. So I would just say, stay tuned. The administration focused on Washington, D.C. are very cognizant of this problem, the blend wall came at them much faster than they were expecting. So we are working this issue hard within the industry, and we will continue to do so.

But my understanding, Gary, is the EPA is pointing to the legislators, and the legislators don't really care because the gasoline price is low.

Well, there are 2 ways that you can handle this. The first is that the EPA does have a waiver opportunity within their jurisdiction on a year-by-year basis. So that's something that they certainly could employ if there is a shortage of RINs. And secondly, you have the legislative piece. Legislative, obviously, would take longer than the waiver option. But we're working both sides very hard, Paul.

We have no further questions. I will now turn the call back over to Pam Beall.

Thank you, Christine, and thanks to everybody for joining us today and for your interest in Marathon Petroleum. And should you have additional questions, Beth Hunter and I will be in the office today to take your calls. So, thanks again.

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