Marathon Petroleum Corporation (MPC) Q1 2014 Earnings Report, Transcript and Summary

Welcome to the First Quarter 2014 Earnings Marathon Petroleum Corporation Conference Call. My name is Sylvia, 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 Tim Griffith. Tim Griffith, you may begin.

Okay. Thank you, Sylvia. And again, welcome to Marathon Petroleum Corporation's First Quarter 2014 Earnings Webcast and Conference Call. The synchronized slides that accompany this call can be found on our website at marathonpetroleum.com under the Investor Center tab. On the call today are Gary Heminger, President and CEO; Don Templin, Senior Vice President and CFO; Mike Palmer, Senior Vice President of Supply, Distribution and Planning; Pam Beall, Senior Vice President of Corporate Planning and Government and Public Affairs and President of MPLX; and Rich Bedell, Senior Vice President of Refining. 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. 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.

Thanks, Tim, and good morning, and thank you for joining our call. We reported this morning that we generated nearly $200 million of income during the first quarter despite the number of challenges. The MPC team successfully completed significant turnaround activity at our 2 largest refineries in Galveston Bay and Garyville. This was the first turnaround at Galveston Bay since we acquired the facility in February of last year, and we were pleased to complete the work on schedule with no major surprises. This project, along with other maintenance work across our operations, made up the largest quarterly combined turnaround activity in our history, with expenditures of approximately $470 million for the quarter. This continued investment in our system helps ensure we maintain the highest levels of asset integrity, and enables us to drive continued top-tier operational performance. Market conditions during the first quarter were challenging. Volatile but generally narrower crude differentials were partially offset by higher crack spreads. Adverse weather conditions in the form of low temperatures and heavy snow accumulations in most of our markets brought challenges to the entire supply chain, from crude deliveries to the gas pump. Despite the market challenges and adverse weather conditions, I was very pleased with the team's focus on strong operational performance. We also continued to diversify our asset portfolio during the quarter. On April 1, we expanded our renewable fuels capabilities with the purchase of a biodiesel manufacturing facility in Cincinnati, Ohio. This facility has the capacity of approximately 60 million gallons per year of biodiesel and is well positioned, logistically, near the Ohio River. This facility fits well with our existing marine and terminal system. We also acquired an additional 7% interest in Explorer Pipeline, which increased our ownership interest to 25% in that system. This investment is consistent with our strategic objective of meaningfully growing our midstream portfolio and adding to the stable cash flow segments of our business. Despite the challenging market conditions in our Refining & Marketing segment, we returned $812 million of capital to shareholders through dividends and share repurchases in the quarter. Don will provide more information on this activity shortly, but I want to highlight that we remain confident in our ability to generate cash to continue our balanced approach to investing in value-enhancing investments in the business and returning capital to our shareholders over the long term. We are encouraged by the signs of improving market conditions, with Refining returning to full run rates that support our positive outlook for the business. Market dynamics, including inventory levels and continued increases in domestic production, are leading to widening crude differentials, which we believe will persist for some time. And with that, I'll turn over to Don to review our financial performance for the quarter.

Thanks, Gary. Slide 4 provides earnings both on an absolute and per share basis. Our first quarter 2014 earnings were $199 million compared to $725 million in the first quarter of 2013. First quarter 2014 earnings include pretax settlement expenses of $64 million, which we've historically been presenting as a special item in arriving at adjusted earnings. First quarter earnings were also impacted by a $29 million pretax accrual for 2013 bonuses that were paid in 2014. As you know, our bonuses are based on relative performance to our peer group, and certain of that information was not available until 2014. Earnings per diluted share were $0.67 for the first quarter of 2014. We reported EPS of $2.17 per share for the same period last year. The waterfall chart on Slide 5 shows by segment the change in earnings from the first quarter of 2013 to the first quarter of 2014. The primary driver for the change was the decrease in Refining & Marketing segment income. As shown on Slide 6, Refining & Marketing segment income from operations was $362 million in the first quarter of 2014 compared with $1.1 billion in the first quarter of 2013. The changes from 2013 was primarily due to the narrowing crude oil differentials and higher direct operating costs, partially offset by wider crack spreads. Results were also impacted by refining throughputs, which were lower than expected due to heavy turnaround activity and severe weather in the quarter. The unfavorable earnings impacts associated with the narrowing crude oil differentials are found in the columns for the sweet/sour differential and the LLS to WTI differential. The increase in direct operating costs quarter-over-quarter is primarily due to the significant turnarounds that occurred in the first quarter that Gary referred to earlier, as well as an additional month of operating expenses associated with the Galveston Bay refinery. Our earnings were favorably impacted by wider crack spreads as reflected in the LLS 6-3-2-1 crack. All of the gross margin indicators utilized spot market values and an estimated mix of crude purchases and products sold. As a result, differences in our actual product price realizations, mix and crude costs quarter-to-quarter, as well as various other items like refinery yields, are reflected in the other gross margin column, which was a $148 million net benefit versus the same quarter last year. Turning to Speedway segment results from Slide 7. Income from operations were $58 million in the first quarter of 2014, compared with $67 million in the first quarter of last year. The cold weather impacted all aspects of Speedway's business. Light product gross margin was about $8 million lower in the first quarter of 2014 compared with the first quarter of 2013. The decrease was primarily due to $0.015 per gallon lower gross margin. Merchandise margin was $192 million in the first quarter of 2014 compared with $184 million in the same period last year. This $8 million increase was primarily due to higher merchandise sales and higher merchandise margins. Speedway's operating and other expenses were also $9 million higher during the first quarter of 2014 compared to the first quarter of 2013, primarily driven by an increase in store count and additional operating costs associated with keeping our facility safe for our customers during the adverse weather conditions. On a same-store basis, gasoline sales volumes decreased 0.7%, and merchandise sales, excluding cigarettes, increased 5.3% in the first quarter of 2014 compared with the 2013 first quarter. In April 2014, we've seen a slight decline in demand, with an approximately 1% decrease in same-store gasoline sales volumes versus the prior year, primarily due to higher average gasoline street prices. Slide 8 shows changes in our Pipeline Transportation segment income. Income from operations was $72 million in the first quarter of 2014 compared with $51 million in the first quarter of 2013. This increase was primarily attributable to an increase in transportation revenue and pipeline affiliate income, partially offset by higher operating expenses. $17 million of the $22 million increase in transportation revenue is attributable to the recognition of deferred transportation credits during the quarter. The remainder was primarily due to higher average tariff rates. Slide 9 presents the significant drivers of changes in our cash flow for the first quarter of 2014. At March 31, 2014, our cash balance was nearly $2.2 billion. Operating cash flow before changes in working capital was a $641 million source of cash. A long-term debt increase of $264 million is primarily associated with MPLX's acquisition of additional midstream assets from MPC. As Gary highlighted, we continued delivering on our commitment to return capital to shareholders, with $689 million of share repurchases and $123 million of dividends paid in the first quarter. Slide 10 shows that at the end of the first quarter, we had nearly $2.2 billion of cash and approximately $3.7 billion of debt. With EBITDA of about $3.9 billion during the last 12 months, we continue to be in a very manageable debt position, with leverage of 0.9x EBITDA and a debt-to-total capital ratio of 25%. Turning to Slide 11. During the last 12 months, we generated $2.1 billion in cash from operations and $550 million of free cash flow. Over this period, we've returned $3.5 billion to shareholders through dividends and share repurchases. This was more than 6x our free cash flow over that period. During the first quarter of 2014, we purchased approximately 8 million shares for $689 million through open market repurchases. It is our intention to continue returning capital to our shareholders that is not currently needed to support the operational and investment needs of the business, and we continue to believe share repurchases are the most efficient way to do so. There was $1.17 billion outstanding on our share repurchase authorization as of March 31, 2014. We intend to remain focused around our efforts to balance careful investment in the business with returning capital to our shareholders. Slide 12 provides updated outlook information on key operating metrics for MPC for the second quarter of 2014. For comparative purposes, those same metrics for the second quarter of 2013 are also shown. Please note that estimated pension settlement expense is now included in the outlook information for corporate and on other unallocated items. With the recent published requirements around Tier 3 gasoline, I also wanted to provide an update on our projected compliance costs. Based on our current understanding of the standards and the changes necessary to our system, we broadly estimate that the costs could range from $750 million to $1 billion, and would be incurred between now and the end of 2019. We will continue to refine these estimates as well as identify opportunities to reduce the impact. I will note that the capital spending outlook we shared with you at our Investor Day in December included estimates for these costs. Now, I will turn the call back over to Tim Griffith.

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

[Operator Instructions] And we have Ed Westlake from Crédit Suisse. Edward Westlake - Crédit Suisse AG, Research Division: Just on, obviously, the quarter there was obviously a lot of turnarounds at Galveston and Garyville. I -- Do you have a number for the opportunity costs? And then maybe if there were any sort of self-help improvements you've made at those refineries in terms of future profitability, if you could give us some color as to what changes you've made to the assets during the turnaround, if any.

Yes, Ed. We calculate the lost opportunity was approximately $150 million due to the maintenance activities that we had the first quarter. And we're very pleased with the -- as Galveston Bay has come back up and the run rates and how it's performing, and the same way with Garyville. Recall at Garyville we did 2 things. We had our normal maintenance of around the crude unit, but then we also had also did the big hydrocracker expansion. And Rich, you want to take a couple of minutes to talk about what you did at Garyville?

Yes, the hydrocracker expansion was one we talked about at the investor meeting last year. And that's where we took the capacity from 90,000 to 110,000 barrels a day, and that's online and running just fine. We did the -- there was a crude unit component to that distillate project that was done last fall and that was another 10,000 of distillate. Edward Westlake - Crédit Suisse AG, Research Division: Great. And then a separate question just on the Mid-Con. Obviously, there's a lot of crude that's sloshing down to the Gulf, and that's helping profitability in the Gulf, but the Mid-Con crude markets seem relatively tight at the moment. I'm just -- any color in terms of what you're seeing in terms of the Mid-Con crude balances for light and heavy.

Let me turn that over to Mike.

Yes. Ed, right now, I don't think that there's anything particularly about the Mid-Con. I mean, I think you're referring to the lower balances of Cushing. And certainly, those balances are lower, but I think that really when we look out here at the second quarter, I think that what we're seeing right now are differentials are starting to come our way. The Brent TI spread has been widening. We're starting to see that some of this length that we've seen in the DOE numbers on inventories, we're starting to see that the differentials are starting to react to that. So it looks like we're heading into a pretty good period for crude differentials.

And we have Paul Cheng from Barclays.

Gary, after this major turnaround, do you view Galveston Bay now, from a hardware standpoint, has been raised to the standard that you want or that you need another turnaround cycle before you would get there?

Sure, Paul. And it's good to hear from you, I haven't heard from you in the last couple of quarters. And so the Galveston Bay turnaround, we're very pleased, and no, I don't think it takes another cycle. Of course, we will continue to improve as we go through the cycles. But then as I said in my remarks, we didn't have any surprises. And we implemented a -- our planning model and our plant maintenance model for doing turnarounds, we implemented that. We started it last year but this is the first big turnaround. And we had very, very good results of being able to control the timing, control the cost. And I'll turn it over to Rich to how he sees the plant, but as I said to Ed Westlake's question, we're very pleased coming out of this turnaround what we're seeing, and how we're seeing the crude unit run.

Yes, Paul. We just -- this was a sort of a basic turnaround where we went in and did a lot of cleaning and upgrading in both the crude unit and the rig [ph] Unit. It was our first chance to get a full turnaround in any of the units there. There are additional turnarounds out in the future years, '16 and '17 and -- but the upgrades on these were -- there's no big capital improvements on these units. Those will be continuing as we evaluate those opportunities. It was really just a routine turnaround.

And Paul, as we continue down the path here, and this was always in our original plan, we will continue to upgrade the safety environmental -- or excuse me, safety instrumented systems and relief valve projects. We'll continue to update those in coordination with our turnarounds. But as I said, very pleased with the management team there, very pleased with the workforce and how they were able to complete this turnaround.

The second question I think is for Don and Mike, maybe I get 2 parts here. Don, on the corporate unallocated the first half runway [ph] seems to be about for the -- in the Refining business, about in the $200 million, $210 million a quarter, which is lower than what in the past. Is that a reasonable run rate going forward that we can use? And secondly, for Mike, any way to estimate what is the PADD III total crude storage capacity that you can share?

Paul, I missed the first part of your question -- this is Don. I missed the first part of your question.

If I look at in the first quarter and also your second quarter guideline on the corporate and other allocated item in the Refining business, seems to be now running at 200 million to 210 million barrels -- sorry, to $210 million a quarter, which is lower than the historical past. And so my question is that on a going forward basis, is that a reasonable run rate that we can use?

Yes. I -- Paul, I believe that corporate and unallocated, it is -- that's a normal -- a more normalized rate. I will add though, that we will have pension settlement expense that goes into that number. This year, our pension settlement expense occurred this -- in the first quarter. Last year, our big charge for pension settlement expense occurred in the second quarter. So you would expect and you see it in our guidance here, you'd expect to see about $60 million of pension settlement expense into second quarter of '13, and our outlook for the second quarter of '14 is about $5 million. Mike?

Yes, okay, Paul. We had our economics group take a look at the inventory capacity in PADD III. And they tell us that the EIA estimates at about 273 million barrels. Of that, there's something like 73 million barrels in refinery tankage. So that's the information that we have, Paul.

We have Doug Terreson from ISI Group.

Staying with refinery costs, is there any segmentation on 100,000 barrels per day of loss throughput between turnarounds and whether -- is there any insight into the mix there?

Let me answer it this way, Doug. A lot of it was due to weather, and it wasn't necessarily crude but the subable was feedstocks, and we had planned because we have these 2 big turnarounds, being able to move feedstocks between refineries and moved some of the feedstocks back up into the Midwest during that period of time. And the polar vortex, we would get one in the Midwest and turnaround the next week, and get one in the Gulf Coast. And it kept hampering our ability to move some of the feedstocks that we have planned to move on the water, up the river system, as well as from refinery to refinery. So I would say more than 1/2 of it was due to the feedstock movements.

Okay, I see. And then just to clarify, Gary, a minute ago, you mentioned that the opportunity cost was around $150 million. And then, when you think about the higher turnaround expenses versus 1 year ago, which looked to me to be about over $380 million. It seems like these 2 factors affected profits by $400 million, $500 million versus the year ago period. Is that the way you guys are thinking about it?

Yes, it is, Doug. I believe, Don, it was about $300 million incremental?

Yes, the incremental turnaround cost was about $300 million, Doug, you got that, correct.

So, and then around -- another $150 million of what we call lost opportunity. And then just some of the incremental demurrage cost you're setting with fog-related issues going back and forth with -- trying to move from refinery to refinery on the water would have had some additional operating costs that was not included in this number.

And Doug, I think there's -- the $300 million is a pretax number. The $150 million that Gary was talking to you about was an after-tax number. So make sure we're not mixing apples and oranges there.

Okay, that's not an insignificant number either way.

And we have Doug Leggate from Bank of America Merrill Lynch.

Gary, can I ask you to dig a little bit deeper into the capture rate? One of the moving parts that we don't really get great transparency on is rack margins. And I'm just wondering if you could help us understand a little bit of what's happening there sequentially from Q4 to Q1, but also how things are kind of shaping up as oil prices kind of start to stabilize here a little bit. And I've got a follow-up, please.

Sure, Doug. As you know, that is one of our probably biggest competitive advantages and -- is our logistics system and our terminals and the way we can move products, and therefore, I can't get into the rack margins on a quarter-to-quarter basis or even a current basis. But I will say, if you look at the inventories and if you look at the inventories Q4, looked at the inventories Q1 and looked at them by PADD, and you can see where there have been some real challenges in the marketplace of being able to supply some markets. And I think that can give you a hint that there's some markets that have been very advantageous to supply.

So is it fair to assume that you guys can benefit from that in the current quarter as oil prices stabilize?

It's not necessarily driven by oil prices, it's delivered -- it's driven by supply and how you can get that supply into the market. So yes, we have been able to move our product into some very key markets and, I think, have done very well being able to accomplish that.

I guess, I was just assuming there was some kind of lag effect on tight oil prices denting your margins and then things kind of stabilize out again. But I'll take it off-line. [indiscernible]

But you are -- Doug, you are correct. The higher oil prices, if you go all the way down to the retail level and looked at Speedway's performance for the quarter, being able to, with higher oil prices, move that price all the way to the street at the retail level, it takes time to be able to accomplish that. And so you are correct there on how the oil prices reflect. But I would say, from a wholesale standpoint, it's really been driven more by the supply and, again, some weather-related issues, being able to get that supply into the marketplace both first quarter and as we lean into the second quarter.

I appreciate that, Gary. My follow-up, I'm not sure who wants to take this, but it's really going more back to the inventory situation on the Gulf Coast and the shift that we've seen from PADD II to PADD III. I'm just curious on your opinion on this because utilization rates and yourselves included have, obviously, you're doing a terrific job running as hard as you possibly can, I guess, for the whole industry as well as Marathon. But because of that it seems that on an adjusted basis, supply basis that inventories in the Gulf may not be as tight as they look. So I'm just kind of curious on your perspective on how that plays out as we go into peak run rate season, if you like, in terms of your expectations for how those differentials relative to Brent could play out, how we get there.

Yes, Doug, this is Mike Palmer. And it's an interesting comment you make with regard to days of supply because I think you're right. When you do the calculation, the days of supply that we have right now, the calculation that you guys went through, I think, is right. The days supply is not in that bad a shape. But I guess what we expect to have happen is we do know that these inventories are building. And we've been surprised that we haven't seen more of a differentials widening on the sweet crude than what we've seen to date. In fact, we've seen probably a little more on the sour side. So what we expect is, as these inventories continue to build, we do expect to see the light differentials widen out a bit and give us an opportunity.

And our next question comes from Chi Chow from Macquarie Capital.

Mike, I just want to follow-up on that last comment there when you said the sours are widening out more than the sweets. What is causing that? Is there a specific dynamic you're seeing on the relative weakness on the mediums?

Well, I think, probably a part of that is just due to individual refinery issues that have occurred in the Gulf. So as we watch these differentials kind of, not just on a monthly basis but on a daily basis, we've seen opportunities where the sour crudes -- the sour Gulf of Mexico crudes have looked pretty attractive, and that will constantly shift. I think right now, it's starting to shift back more in favor of the light sweets.

We can't really see the data on our end with the details. But how do you see the inventories in the Gulf Coast stacking up between the Texas Gulf Coast region and Louisiana? And are there some inefficiencies still in getting barrels into St. James that may be holding up that LLS price?

I think, there still are inefficiencies in the Gulf Coast. I think that's very true. I mean, the most dramatic thing that we've seen, I think, would have to come back to Midland. And if you track West Texas sour or if you track Midland WTI, I think you've seen that those differentials have widened out. So the capacity, the pipeline capacity to move barrels out of the Midland area has certainly been a factor. We don't have a lot of great data with regard to inventories in the different parts of the Gulf either, but we suspect that probably there are some additional inventory in the Nederland area. Again, as the pipes have expanded and allowed crude to move down into Nederland, we're not sure that the takeaway logistics have kept pace. So that may be, those 2 areas may be where we're seeing a reasonable amount of this Gulf Coast surplus.

Chi, this is Gary, let me add a couple more comments. So in fact, we were just yesterday, looking at some of the production that's coming in -- the new production that's coming in from the Gulf this year, and that's going to really land over in the St. James area and some significant increase in the Gulf Coast production. So that's something to keep an eye on. And the other thing that we're watching very carefully is as you look at inventory growing in the Gulf Coast, therefor PADD III and how that has continued to grow, week after week, I think the DOE showed yesterday, was up 5.7 million barrels of additional inventory, is the time that it starts backing up to the Mid-Con or backing up to Cushing is where we're keeping a close eye on that to show how much inventory, as Mike related earlier how much inventory or shelf capacity there is in the Gulf Coast. As that starts to fill up in the -- in PADD III and move back to Cushing is when you know that, I think, things are going to even lighten out more.

All right, a lot of dynamics going on right now. Just as a follow-up on Gary, I just want to ask if you had any updated views on how regulators in Washington may be considering the whole discussion on crude oil exports, changes in the Jones Act, RFS, any updated thoughts on that end?

We continue to be -- work on these issues and be very close to the discussions back in the mid part of the quarter we had some meetings on the export discussions. And then at the same -- in the same discussions talked about how inefficient the Jones Act is to the transportation sector and how inefficient the renewable fuel system is to being able to deliver products to consumers. And I will say all of that is caught up with a number of other discussions that are going on in D.C. right now, and I don't see any movement on any of those. Of course, we're waiting on the final rule to come out of the EPA on the ethanol blending requirement for this year. Still expecting that. That's probably going to be the latter part of this quarter before we hear what the final rule making is on the ethanol blend component for this year. A lot of discussion continues on with the Jones Act, but I think Senator Landrieu was very forward in her comments that she does not support any change to that legislation. So accompanied with the Jones Act and very top level Discussion on crude oil exports. We don't see anything moving on either side.

Okay. Was there a general acknowledgment that all these issues are somewhat interrelated and it's not -- that everything has to be considered, I suppose?

I would say that most of the folks that we have met with understand that this is a dynamic situation and that you just can't peel the onion back one layer and come up with a decision. You have to look at the total market. And yes, there totally is an understanding of the dynamics involved.

And we have Paul Sankey, Wolfe Research, online with a question.

Gary, there's been obviously a ton of questions on the turnarounds, and I think you fairly clearly stated that these were not capital improvement cost overruns, they were more weather related. What I was wondering is the extent to which now, looking forward, creep is back. You're coming out of these turnarounds with higher capacity and, I assume, yet higher ability to run light sweets. Can you just talk about the outlook for how the industry is increasing its capacity and specifically Marathon is and the extent to which you were able to increase your light sweet throughputs by the same token?

Yes. And I think that -- and I stated on one of the first calls on the turnaround we're very pleased with how Galveston Bay came out. And anytime you'd want to do a big revamp and turnaround of a crude unit, you would expect that it's going to run better than as you go into a turnaround. It's just going to run better. As I look at creep across the entire industry, it certainly is hard to separate between creep and those who have just -- are replacing a medium barrel with a lighter barrel, therefore you can get more throughput in a crude unit, generally. So it's really hard, Paul, to calculate creep. I'll let Mike or Rich here add into what they're seeing in the industry and/or our refining.

Yes, Gary, I mean, if I could interrupt. So is it -- can you give us a sense as to how your capacity specifically has grown? Just for example, as we head for summer, is it a given percentage higher than it was 1 year ago? And any observations, obviously, on the industry would also be very interesting.

So yes, Mike's prepared to talk about that.

Yes, Paul, let me just give you a couple of thoughts, I guess, that I have and maybe Rich can add to it. But it's very interesting. In the first quarter, kind of Gary alluded to some of the weather-related issues we had. But one of the problems that we had during the first quarter was that we were buying light sweet crude and it was not being delivered. There were production issues, there were issues with moving crude by water. The trains were a problem. Our big problem in the first quarter, one of them, was that we weren't getting all the light sweet crude that we were trying to buy, and we're now just now starting to come out of that. The other thing that I would say is that the amount of light sweet crude that refineries can run, there are hard limits that Rich can talk about, but it's very much a function of pricing. And I can tell you that within our system, we still need to see wider discounts when we look at, for example, Light Louisiana Sweet versus Gulf of Mexico sour or Mars. We see these differentials really kind of on the breakeven so that we go either way from week to week. So I think once we start to see additional production of the shale crudes, we should get to a point where it really gives us incentive to bring more of this light sweet crude in the system, which we can still do. Up to this point, that -- we have not run into any problems with regard to how much we can run. We can run more.

So could you give us a number on that? Is it 100,000, 200,000, 300,000 more a day?

Well, I don't -- I'm not sure that I can really give you a good number. As I say, it's a function of price.

Okay, good answer. But okay, interesting. Was I going to...

Oh.

Plus, I guess, Paul, the other question you had about are we increasing our crude capacity, nameplate-wise, we're not doing that now. We usually do that based on a full year run in what we do. But coming out of the turnaround, especially with Galveston Bay and Garyville, you're coming out with clean exchangers. Everything's ready to go, and we typically run a little bit more during those time periods. But when we talk about our overall refining capacity, we use the annual averages.

Great. And I just had a follow-up, which is the old question about how much you're exporting of what products and the same store sales demand numbers that you're seeing.

Yes, Mike will take care of the export numbers.

So Paul, this is Don. Our exports for the first quarter were 223,000 barrels a day, and of that amount about 50,000 barrels a day was gasoline.

Yes, and let me just add to that, Paul, by saying that our exports in the first quarter were down, and they were certainly impacted by the turnaround activity that we had. We didn't have the volumes to export that we would have without the turnarounds. And as we got out of the first quarter back into the April kind of time period, I think we're returning to more normal levels.

Okay. And our next question comes from Evan Calio from Morgan Stanley.

I guess my question, Gary, there's a lot of embedded value in MPC, and I'm sure that drives the buyback and then drives the buyback condition for you. But on midstream specifically, do you believe that MPC is being valued or fully credited for the embedded midstream value at the C-corp? And how do you think about ways to potentially call that out or pull that forward?

Well, that's a very pertinent question, Evan. And no, I do not believe that -- as we started the MLP in October of 2012, that's one of the key factors that we looked at as a lot of people advised, they saw that value. That value has not pulled through. I think a very small part of that value has pulled through into MPC. We certainly are being recognized with MPLX and how we're growing MPLX, and we're -- it's being recognized not only on the amount of drop-down capacity that we have but also the organic work that we've been doing and how we're trying to get ahead of the curve on the organic work being the Sandpiper-SAX pipeline that we spoke about, the incremental investment in Explorer, and we talked about the splitters. So that is being recognized -- it's being recognized with MPLX that we're growing that midstream reserve, if you will. But it still is not being pulled through at the level that we think we deserve. And that was a big part of our analyst briefing that we had in December, is that we still believe, and it's why we continue to buy back shares, is that we believe there's a tremendous value still embedded within our strong and stable cash flow businesses that is not being fully recognized.

Do you think a faster or bigger pace of monetizations would result in unlocking the value at the MPC level?

We continue to look at the pace. In fact, I think the market has been very, very receptive of the rhythm that we've put in place within MPLX. To go in and say, let's just do a faster monetization is -- that is -- also can lead to destroying value if you do not have, again, this reserve base teed up. So I think it's a delicate balance, a fine line in what that rhythm of growth. And you just take the compounding effect out for a number of years at the growth rate that we have been public with in our midstream business so -- in between a 15% to 20% number, and that compounding is -- becomes quite a big number quickly. And that's why we've been so aggressive, and I think we've been very fortunate in how we're growing this business and growing the stable. But we continue to look at our rate of growth, continue to look at our midstream assets. Pam Beall is here with us who is the President of MPLX. Pam, do you want to add anything to this?

Well, really Gary, I think you summed it up right. We think that we created MPLX to participate in the growth and build out the infrastructure to support the production of oil and natural gas. We also did it to highlight the substantial value that our midstream assets can provide to MPC and the flexibility it provides to the company. We think a more measured pace is the right way to go to retain flexibility both for MPC, and we think that's what the MLP's investment community really favors, is the ability to see that the MLP, especially sponsored MLP, have a long runway of potential growth potential. Because part of the total return is the growth rate, and part of the return is [indiscernible]. We like this measured approach.

And I'll say, Evan, that you'll recall my closing remarks in our analyst meeting in December were that we're going to grow our stable cash flow businesses, and that being midstream and retail, and we've been very successful in the balance of the fourth quarter and the first quarter of continuing to add to those base.

I mean, that's a good segue for a question to the retail, another segment that's valued in the market on a higher stand-alone basis. I mean, how do you think about that segment or even MLP potential within the wholesale fuels business or even, conversely, retail inorganic growth potential? I'll leave it there.

Right. You're right, Evan. And the way we look at this is that we have multiple levels of optionality. The -- we are fully aware of some of those different structures. But I also want to be consistent that we believe there's a tremendous value and a value around synergy within MPC of having this very strong retail base and knowing how you're going to move your product and the efficiencies of moving your product through the marketplace that we've been able to capture historically. However, that does not say that we will forever maintain that type of a structure. We're fully aware, and we continue to do a lot of analysis on what the best way forward would be. And -- but for now, we think we're in a very good position.

And now we have Roger Read, Wells Fargo Securities, online with a question.

I guess one follow-up off of Galveston Bay following the turnaround. I think Paul asked it earlier, Paul Cheng. But now that you've done the turnaround and you're thinking about how the unit operates relative to what it was doing before or what you think it can do now, can you give us any quantifiable way to think about how the unit runs better, whether it's a yield, whether it's lower cost, a combination of the 2?

All right, I'll let -- Rich, you want to please handle this?

Well, we definitely see better yields, better cut points that -- off of the crude unit that just went through the turnaround. And again, you get a little bit better throughput, too, because of the clean exchangers, but the cuts are also much better, especially between resid and gas oil. So we're seeing that, and that's just a matter of getting everything cleaned up and running it. So there wasn't any real big revamp of the unit. It's all based on just getting it in better condition.

And Roger, you'll recall at the analyst meeting that I said at the end we need 1 more year to really get our arms around and get this plant running like we want it. This was the first big turnaround that we've accomplished, and we accomplished it under our control of how we do turnarounds, and that went very well. So my outlook -- and I know Rich and I spent a lot of time on this, our outlook for this refinery is that with the strides that we've made in a very short time, we're expecting it to get better and better. And -- but the thing I want to come back on, we're very impressed with the workforce that we acquired when we bought this plant. And they know how to run refineries, and we have a great management team there as well. So I'm very pleased with what we're seeing on the front end.

Okay, so that's helpful. So a quick summary would be you feel better about the acquisition today than you did at the time you made it in terms of just the quantifiable things you can achieve with it?

I felt very good on the day we announced the acquisition, and I even feel better.

Okay, that's helpful. And then the last question I had, just on the exports. Obviously, you addressed the issues that held them back in Q1. You've had time to spend a little money and time expanding some of the key side issues and then the work here at Galveston Bay. So if you were to think about what max export capacity is, can you give us an idea of what that is today and maybe what that'll do over the next 12 to 24 months?

Well, what we've said, Roger, in our Analyst Day briefing, as well as I believe we updated this in the fourth quarter, we would expect by 2016 to be able to move this out to around 450,000 to 475,000 barrels per day of exports by -- in that time frame. I mean, in fact, I think it's 2018 because we have to tie the kind of the last piece to a turnaround that we have scheduled down the road.

Yes, I would say Roger, this is Don, our view before that sort of major incremental leap is that we would get to about 350,000 barrels a day, and then there will be an incremental leap that will take us -- that will require capital but will get us then to that 475,000 number that Gary referred to.

Okay. So you did I think it was about 250,000 in the third quarter and a similar level in the fourth quarter, fell back a little bit here and then what, by 1 year from now the 350,000? Or are we thinking more like 2 years to get to that level?

Well, for the fourth quarter, I think we were just under 300,000 barrels a day. So that incremental 50,000, I think, will -- we're doing a great job of evaluating how to be more efficient and how to make sure that we're maximizing the product placement with crude receipts and with making sure that we're taking advantage of both the availability at Garyville and at Galveston Bay. So I think the 350,000 is not that far away from the 300,000 that we had at the end of the fourth quarter -- or for the fourth quarter.

And our next question comes from Blake Fernandez from Howard Weil.

I had a question for you on condensate splitters. Gary, I know you've already kind of addressed your thoughts on crude exports, but there had been some rumblings in the industry from the E&P side that they may be able to export condensate, and it seems like some of your peers are taking a little bit more of a measured approach to it. If I recall, I'm looking at some of your previous slide packs, you had a decent amount of spending in '14 on condensate splitters. So just any updated thoughts there, I would appreciate it.

Right. Blake, the condensate splitters that we've talked about on the front end here of our business and technical plan are in Canton and Catlettsburg. So they're really all around the Utica and Marcellus, which would not -- I don't think would -- because of the transportation costs to be able to move the river system, that I don't see that the Utica and Marcellus really tees up that well for export. So I'll ask Rich to talk about the spending that we plan and the timing that we have planned for Canton and Catlettsburg, and those 2 splitters are ongoing right now.

Yes, the Canton project will be completed at the end of this year. And then in the second quarter, we'll have the Catlettsburg project finished. Canton is 25,000 barrels a day, and Catlettsburg is 35,000 barrels a day of the condensate.

So -- and so that is all Midwest production at, I should say, really Eastern side of PADD II production that will go into those splitters. And I understand that the measured approach and the desire by some to be able to look at condensate splitting or -- condensate that has been split for export, and we'll continue to see how that moves down the path.

Perfect, that's helpful. The second question was, I guess, more a clarification. I think you mentioned in the prepared remarks a decline in demand. And I guess if I heard correctly in April, that doesn't seem to be kind of consistent with the DOE numbers we're getting. I was just hoping maybe you could give a little clarity around that.

Yes, Blake, this is Don. The decline that I mentioned was just Speedway demand, and I would say that our -- and that market, obviously, is a Midwest market. So we think the recent run-up in prices at retail have had an impact on that.

Okay. So that's really not winter related or anything that we saw in 1Q? This is more recent, right?

Yes, the 1Q was down I want to say 0.7%, so -- on a same-store basis. This was the -- we were trying to give an April number, and that's down about 1%. But once again, we think a lot of that is really reflective of the fact that the price at the pump is $0.20 or $0.25 generally higher than it was 1 year ago.

And the next question comes from Jeff Dietert from Simmons & Company. Jeffrey A. Dietert - Simmons & Company International, Research Division: It's Jeff Dietert. I was hoping to get a comment on your expectations for oil imports into PADD III. And they've been relatively sticky so far this year, roughly flat year-on-year. And we've got increased pipeline barrels, rail barrels and flat imports coming in, which is contributing to the build here in April in front of what looks like a relatively active maintenance period on the Gulf Coast. Could you talk about your expectations for those imports?

Well, Jeff, this is Mike Palmer. As we all know, most of the light sweet crude is no longer coming into the Gulf. It's pretty much been eliminated. So the next step is going to be starting to back out either light sour or medium sour crudes. And I think, as I mentioned earlier, that certainly could happen as the spreads start to give us incentive to do that. So I would think that if production continues in this country along the growth path that we've seen, that you're going to start to see some of that foreign light sour and medium sour start to get backed out. Jeffrey A. Dietert - Simmons & Company International, Research Division: And they've been a little bit sticky so far. I mean, most of the oil imports are priced off of domestic grades, which have to be priced attractively for the U.S. Gulf Coast refining market. Some of the exporters have joint ventures, term sales, strategic interest in sustaining U.S. market share. Do you think we need to see a substantial discount relative to international prices in order to reduce those imports?

Well, I guess my feeling is that yes, you're going to need to see and have a perception that you're going to have this discount that's going to be ongoing. But up to this point, what I would argue is that, again, it's breakeven between some of the -- even the U.S. Gulf of Mexico sour crudes and the light crudes on the Gulf Coast are close. So you can go back and forth between those 2 grades in terms of economics. So we need to start to see the light sweet crudes -- if that's where the surplus is going to be, which we would expect, we need to see the discounts start to widen and last for a period of time.

And Jeff, if you look at the kind of the world economics and the producers in West Africa, in the North Sea, not that much of the North Sea production comes to the U.S. anymore but mainly West Africa and some of the South American countries. As Gulf Coast production continues to increase, there's going to be friction because those producers are still looking for a home for their crude. And the home, of course, they can take some to Asia. However, you look at some of the Middle East producers and how they're increasing and ramping up their production to Asia, there's a -- quite a bit of friction and pressure on being able to deliver those barrels into Asia. So I think this bodes well, back for our initial comments, that we see spreads will persist, the wider spreads will persist, because those countries are still looking for a home for their crude, and I think the friction point becomes the Gulf Coast. Jeffrey A. Dietert - Simmons & Company International, Research Division: Okay. And secondly, could you provide an update on the Garyville Resid Hydrocracker Project? I think I saw some news that you were applying for permits. Anything to dissuade you from continuing to analyze that project?

I'll let Rich handle that.

That was the resid hydrocracker project that we submitted our air permit. But throughout this year, we have a more detailed engineering effort going on. Our decision point on this project will be in the first quarter of next year. But everything still looks very good on the project.

And our next question comes from Faisel Khan with Citigroup.

This is actually Mohit Bhardwaj for Faisel. Gary, just looking on the Gulf Coast, there's a lot of crude coming over there, and there are new inventories building up. Just from a logistic standpoint, you mentioned some of the factors that are getting crude into Texas City or into Garyville and also supplying product into the Florida markets, which you are sort of benefiting from. Are there any opportunities that you see right now that you can share with us?

I'm sorry, opportunities -- I missed the...

Oh, On the logistics side to smoothen some of the transportation on the crude side. And also, products are getting into the Florida markets that you -- that are sort of tight and you sort of benefit as well from it because of the wholesale margins.

Yes, the way we have been having our transportation of refined products into the Florida market, and we have a virtual pipeline on the water -- on the Gulf that we're supplying both out of Texas City, Galveston Bay and Garyville into the Florida and some of the other Gulf Coast terminals into that marketplace. So we're in very good shape as far as the transportation mode that we're using there. The -- this incremental production that I've talked about coming from the Gulf Coast from a crude standpoint, we are in great shape because a lot of that is going to be plumbed up to come through LOOP.

All right. All right. And just one final quick one for me. Any indication on the RIN expense for this quarter?

RINs?

The RIN expense was $71 million for the quarter. That was purchased RINs.

And our last question comes from Paul Cheng from Barclays.

Just a quick follow-up. Gary, when we're looking at Galveston Bay based on your unit cost estimate in the second quarter for the Gulf Coast, they seems to be still high comparing to the Garyville. Any plan what you may be able to do in terms of reducing the costs there? And also there for Mike, in your conversation with whether the Mexican -- or with the Mexican, have the tone or the attitude have changed now in terms of how they're looking at the Gulf Coast market?

Paul, this is Don. Let me take the unit cost question. We don't provide specific information on individual refineries, but I think it's fair to say that Garyville is, if not the most efficient, one of the most efficient refineries from an operating cost perspective. And so, there will always, I think at least in the foreseeable future, be a gap between their operating costs and those at Galveston Bay. There's also a structural difference in that Galveston Bay has a very large aromatics complex and this very large resid hydrocracker complex. So the -- you -- I don't think you'd ever expect to see a parity on that because of the different configurations.

Sure. But, I mean, I guess my question is that are you comfortable and happy about the current unit cost in Galveston Bay or that this is an area of focus?

Paul, this is Gary. As I mentioned in December, this is top of mind, top of mind every day as an area of focus. Rich is doing a great job. Just completed the largest turnaround they've ever had there in one cycle and did it right according to our plan. And our plan through these turnarounds is to improve the operability, to improve the mechanical availability, therefore lowering the unit cost. Are we where we want to get to yet? No. Are we making progress? Yes.

How about...?

Yes, Paul, Paul, this is Mike Palmer. Paul, we really don't have any indication that the Mexicans have changed their thoughts about the U.S. Gulf Coast. I really don't have anything that I can tell you there.

And we have no further questions at this time.

Okay. Thanks, Sylvia. Well, again, we'd like to thank everyone for joining us this morning and for your interest in Marathon Petroleum Corporation. If you have additional questions or would like clarification on the topics discussed this morning, Beth Hunter and Jerry Ewing will be available to take your calls throughout the day. Thanks for joining us.

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