Marathon Petroleum Corporation (MPC) Q2 2013 Earnings Report, Transcript and Summary

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 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 C. Michael Palmer - Senior Vice President of Supply Distribution & Planning

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

Welcome to the Second Quarter 2013 Earnings Call for Marathon Petroleum Corporation. My name is Cliff, and I will be your operator today. [Operator Instructions] Please note that this conference is being recorded. I would now like to turn the call over to Ms. Pam Beall. Ms. Beall, you may begin.

All right. Thank you, Cliff, and good morning, everyone. Welcome to our second quarter 2013 earnings webcast and conference call. You can find the synchronized slides that accompany the call on our website. And on the call today are Gary Heminger, President and CEO; Garry Peiffer, Executive Vice President of Corporate Planning and Investor and Government Relations; Don Templin, our Senior Vice President and Chief Financial Officer; Rich Bedell, our Senior Vice President of Refining; Tom Kelly, our Senior Vice President of Marketing; and Mike Palmer, our Senior Vice President of Supply, Distribution and Planning. If you turn to Slide 2, please read the Safe Harbor statement on this slide. It is a reminder that we will be making forward-looking statements during the presentation, as well as the question-and-answer session. Actual results may differ materially from what we expect today. And factors that could cause actual results to differ are included here, as well as in our filings with the Securities and Exchange Commission. And now, I'll turn the call over to Gary Heminger for our opening remarks.

Thank you, Pam, and good morning to everyone. Thanks for joining us today. If you'd please turn to Slide 3. MPC had a strong operating quarter. At our Detroit refinery, our upgraded units ran well, and we continue to be pleased with these operations, where we were able to process additional volumes of lower-priced Canadian heavy oil. We are also pleased with the integration process of the Galveston Bay refinery, and the plant there is operating well. Light product exports from our Garyville and Galveston Bay refineries increased significantly to 190,000 barrels per day during the second quarter of 2013, which is the highest level of exports we have achieved. Speedway posted strong financial results, primarily due to an increase in the fuel and merchandise gross margins. In May, MPLX, the master limited partnership we formed last year, acquired an additional 5% equity interest in MPLX Pipe Line Holdings, LP. MPLX also increased its second quarter distribution 4.6%. We remain committed to positioning MPLX among the top MLPs, and we are targeting a distribution growth rate of 15% to 20% for, at least, the next several years. We will continue to pursue opportunities that support that intent. Several developments resulted in lower earnings for our second quarter of 2013 compared to a very strong quarter we achieved a year ago. During the second quarter of 2013, the industry experienced refinery crude runs that were higher than both the last year and the 5-year average, with much of the increase in PADD III. This contributed to a drawdown of crude inventories to meet refining demand and a narrowing of crude spreads. In addition, gasoline inventories were higher than last year and the 5-year average. As a result, the U.S. Gulf Coast market was weaker, and cracks were lower compared to the second quarter of last year. The Chicago market experienced greater-than-usual volatility during the quarter, primarily due to significant maintenance at area refineries. When the Chicago refinery -- Chicago area refineries came back online, a short supply situation in the Midwest quickly reversed into a long supply situation. Rapid movement in spot prices in the market are not always reflected immediately, as wholesale racks -- at wholesale racks or on the street. We believe another factor impacting the market realizations was the rapid rise in the price of RINs, or renewable identification numbers. Our product price realizations, when compared to spot market values, were lower in the second quarter of this year than in the second quarter of last year. In the meantime, we, along with the rest of the industry, are urging the EPA, the administration and members of Congress, to address this unworkable Renewable Fuel Standard to avert potentially a significant harm to consumers and the economy in both the short term and long term. Now going forward, we expect 2013 demand to remain flat for gasoline, but up approximately 3.2% for diesel, Brent-WTI crude spreads to revert to quality and transportation cost differentials and indicators of a forward curve would suggest the spread will be in the $7 to $8 range. However, we expect continued volatility. We expect the market to fully recover the cost of compliance with the Renewable Fuel Standard in the long term. For MPC, our ongoing commitment to returning capital to our shareholders was demonstrated by the nearly $1 billion MPC returned to its investors through dividend payments and share repurchases during the second quarter. Our confidence in the cash flow prospects of MPC's business was further underscored by the 20% increase in the regular quarterly dividend announced yesterday. Disciplined investing in MPC's business and regular return of capital to our shareholders will continue to be critical elements of our business model. And now, I'll turn the call over to Don Templin to review the financial results for the second quarter. Don?

Thanks, Gary. Slide 4 provides earnings and adjusted earnings data, both on an absolute and per share basis. Our second quarter 2013 adjusted earnings were $632 million compared to $867 million of adjusted earnings in the second quarter of 2012. Adjusted earnings per diluted share were $1.95 for the second quarter of 2013 compared to $2.53 during the same period last year. The second quarter 2013 earnings included a $60 million pre-tax adjustment for cumulative pension settlement expenses resulting from the level of employee lump-sum retirement distributions occurring in 2013. The second quarter 2012 earnings included a similar $83 million pre-tax pension settlement adjustment. The earnings lock chart on Slide 5 shows, by segment, the change in adjusted earnings from the second quarter of 2012 to the second quarter of 2013. The primary driver for the change in our adjusted earnings was the decrease in income from our Refining & Marketing segment, partially offset by an increase in income from Speedway and the Pipeline Transportation segments and lower income taxes. As shown on Slide 6, Refining & Marketing segment income from operations was $903 million in the second quarter of 2013 compared with just over $1.3 billion in the second quarter of 2012. The change was primarily due to narrower crude oil differentials and lower product price realizations relative to benchmark neat fuels. The unfavorable earnings impacts associated with the narrowing crude oil differentials are found in the sweet/sour, LLS to WTI and prompt versus delivered margin indicators on the slide. Since all of these indicators utilize spot market values, any change in our actual product realizations quarter-to-quarter are reflected in the other gross margin column also shown here. Our product price realizations compared to spot market values were lower in the second quarter of this year than in the second quarter of last year due to a number of factors, 2 of which are worth noting. First, about 40% of our refining capacity and almost all of our purchase for resale activity is in PADD II. The Chicago refined product spot market experienced significant volatility in the second quarter of 2013, primarily due to refinery maintenance activities in the Greater Chicago area. As a result of that volatility, our actual product price realizations relative to spot market prices were lower quarter-to-quarter. The second factor affecting our product price realizations was the impact of the increase in the price of renewable identification numbers, or RINs. When the cost of a RIN was less than $0.01 for E10 gallon, the relative impact of RINs on spot market values and on wholesale product price realizations was immaterial. Therefore, the only RINs impact we discussed previously was the financial impact of the RINs we purchased from third parties to cover our needs as an obligated party. Our cash cost for RINs was approximately $20 million per month for the second quarter of 2013. In addition, we believe our product price realizations relative to spot market prices were also impacted by the dramatic increase in RIN prices. During the quarter we believe that the prices of ethanol-blended fuels, exported fuels and other transportation fuels that do not trade our RIN obligation were generally lower than spot market values. We believe this occurred because non-obligated blenders and retailers could make an acceptable margin discounting to some degree the RIN value from the cost of the renewable fuel. As you know, we utilized an LLS 6-3-2-1 crack spread that includes neat gasoline and diesel fuel spot market values for approximately 5/6 of the product value. We believe the traditional crack spreads using neat gasoline and distillate spot market values versus the biofuel blends that are actually sold could overstate refiners' earnings due to the impact of RINs. The increase in direct operating costs quarter-over-quarter is primarily due to the acquisition of the Galveston Bay refinery and is consistent with our guidance. The Galveston Bay refinery did contribute positive earnings during the second quarter. On the next 2 slides, we provide earnings walks for each of our other operating segments. On Slide 7, Speedway's income from operations was $123 million in the second quarter of 2013 compared with $107 million in the second quarter of 2012. Speedway's light product gross margin was about $12 million higher in the second quarter of 2013 compared with the second quarter of 2012. The increase was primarily due to a $0.01 per gallon higher gross margin for the second quarter of 2013 compared with the second quarter of last year. Merchandise margin was $212 million in the second quarter of 2013 compared with $203 million during the same period last year. This $9 million increase was primarily due to an increase in the number of convenience stores we operated last quarter. On a same-store basis, gasoline sales volumes were flat in the second quarter of 2013 compared with the 2012 second quarter. Speedway's same-store merchandise sales, excluding cigarettes, increased 4.5% over the second quarter last year, which is noteworthy, considering the second quarter last year was up 10.1% from the same quarter in 2011. Speedway's average retail gasoline price during the second quarter of 2013 was nearly the same as the second quarter of last year. Slide 8 shows changes in our Pipeline Transportation segment income. Income from operations was $58 million in the second quarter of 2013 compared with $50 million in the second quarter of 2012. This increase was primarily attributable to an increase in transportation tariffs, offset by higher operating expenses and depreciation. A portion of the increase in transportation tariffs was related to the formation of MPLX. A number of items made up the unfavorable operating expense variance, the largest of which were costs now incurred by MPLX following its IPO in October 2012. Slide 9 presents the more significant drivers of changes in our cash flow for the second quarter of 2013. At June 30, our cash balance was just over $3 billion. Operating cash flow before changes in working capital was a nearly $900 million source of cash. The working capital use of cash of almost $1.3 billion noted on the slide primarily relates to the timing of receipts and mix of crude and feedstock volumes as of the close of the second quarter of 2013. In addition, we had a decrease in the crude taxes payable due to the timing of estimated tax payments. Also, as shown on the slide, is the $882 million of cash used in the second quarter share repurchases that Gary highlighted earlier. Slide 10 shows that, at the end of the second quarter, we had just over $3 billion of cash and approximately $3.4 billion of debt. With EBITDA of over $6.3 billion during the last 12 months, we continue to be in a very manageable debt position, with leverage of 0.5x EBITDA and a debt to total capital ratio of 22%. This strong liquidity position enables us to support our core liquidity requirements and continue our focus on capital return to shareholders. Turning to Slide 11. During the last 12 months, we generated over $5.5 billion in cash from operations and $2.8 billion of free cash flow. Over this period, we've returned 81% of this free cash flow to shareholders in the form of dividends and share repurchases. During the 2013 second quarter, we returned nearly $1 billion to shareholders through dividends and share repurchases. This exceeded the free cash flow in the quarter. We purchased approximately 11 million shares for $882 million through open market repurchases, and we continued to repurchase shares into July. In July, we repurchased approximately 3.9 million shares for about $273 million. It is our intention to continue returning capital beyond the needs of the business to our shareholders. Slide 12 provides outlook information on key operating metrics for MPC for the third quarter of 2013. For comparative purposes, those same metrics for the third quarter of 2012 are also shown. The July market data document will be published later today on our Investor website. We will continue to work to identify market metrics that enhance visibility to MPC's earnings in light of the recent volatility in RINs, just like we did in early 2012 when we first experienced the big difference between crude oil prompt and delivered prices. Our mission continues to be value creation for our shareholders. We are committed to pursuing opportunities to create near- and long-term value and believe the returns to our shareholders will reflect that focus. We will be balanced and disciplined in our approach to capital allocation, as we continue to assess the opportunities in front of us. Now I'd like to turn the call back to Pam Beall.

Thanks, Don. [Operator Instructions] And with that, now, Cliff, I'd like to open the call to questions.

[Operator Instructions] Our first question comes from Ed Westlake from Crédit Suisse. Edward Westlake - Crédit Suisse AG, Research Division: Thanks for the waterfall chart on the Refining & Marketing Q-over-Q. One question on the $313 million other gross margin. You said that include RINs, $60 million, for 2Q, leaving $250 million left over. How much -- how would you separate that between being short product in the Chicago area and having that spike? And how much do you think, if you had to guess, would be this difference between product pricing that we see on the screen versus actual product prices as you sell it out of the refinery? That would be helpful.

Hello, Ed. This is Garry Peiffer. Well, as you've heard from others, it's very difficult to try to separate out the impact of -- fundamental supply and demand impacts from the RIN impact on our relative price realizations. But what Don was trying to describe in his remarks was the fact that, in addition to that $65-or-so million that we actually expended to buy RINs from third parties, there's also other effects that go on in terms of our product price realizations at the wholesale level, if you will. So we would say that the majority of that amount, the $313-or-so million, was impacted by the spike in crack spreads and product prices in the Chicago market and the effect that RINs had on our product realizations and costs in the second quarter. Edward Westlake - Crédit Suisse AG, Research Division: And, I guess the...

Compared to spot -- that's compared to spot, Ed. So we're comparing it to spot values. Edward Westlake - Crédit Suisse AG, Research Division: And so, as that spike is unwounded in the third quarter, spot should be a bit more relevant, but RINs will still be an issue?

That would be correct, assuming they stay at the high levels also. Edward Westlake - Crédit Suisse AG, Research Division: Okay. And then, the other comment, you said Galveston Bay was still profitable. Would you be able to give us a sort of a run rate of EBITDA in the third quarter -- in the second quarter as you did for the first quarter?

Ed, this is Gary. What we've decided, as you know, we gave you that number at the end of the first quarter. We've just operated it for 2 months. But for competitive reasons, and as you know, we have never broken our refineries out individually. We gave that because it was just after starting up Detroit and just after acquiring Galveston Bay. For separate competitive reasons, we're not going to give out the numbers individually going forward. Edward Westlake - Crédit Suisse AG, Research Division: Would you give a Gulf versus Mid-Con split?

Not at this time.

Our next question comes from Paul Sankey from Deutsche Bank.

Gary, one of the big positives out there is the export number that you spoke about. Could you just remind us where you were in Q1? You said -- I think you said 190,000 barrels a day in Q2. Could you give us an indication firstly of the split between gasoline and distillate there; and, secondly, where that product is going and how much more you think you can grow that number?

Right. Yes, we had 190,000 barrels per day here in the second quarter. It's 151,000 barrels per day in the first quarter. And, Garry, do you have the breakdown of...

It's primary diesel fuel, what we're exporting. Roughly, 170,000 to 190,000 was diesel fuel. And I guess, as a practical limit, I think we're pretty close to a capacity, although every time we seem to say that, our schedulers and engineers find a way to eke a little more out. But at 190,000 barrels a day, that compares to second quarter last year of 121,000. But obviously, we have Galveston Bay in there as well that's accounting for some of that difference. So roughly, that's probably our practical limit in that neighborhood of 190,000 to 200,000 barrels a day.

And the other thing, Paul, that we're doing is -- you've heard us talk about this before, both at Galveston -- excuse me, at Garyville where we're doing some capital expenditures in order to be able to improve on our gasoline exports. Today, you need to be able to let the gasoline settle out. And so, the way we operate today is basically online and straight through the tanks. But in order to be able to certify it and go into some foreign countries, you need to be able to settle it out. And we're investing in some incremental tankage to be able to do that. So in the future, we will be increasing our gasoline exports. And then, we're also now looking at how we can improve on the exports out of Galveston Bay. So Garry is right, from the assets, as they set today, we think we're pretty much at the peak. But we are investing in both to be able to increase that number into the future.

Maybe 1 slight clarification. The 151,000 Gary referred to was fourth quarter of 2012 and first quarter of about 121,000. So we have a little bit of a dip there. But 121,000, first quarter of 2013; 151,000, fourth quarter of 2012.

Right. Thank you.

In fairness to what you're saying and I know you said you don't want to break down individual refineries, but you had been running Garyville and you had permitted, I think, for it to be a much bigger refinery than it was originally nameplate, if you like. Can you talk a little bit more about where you are in terms of, firstly, Garyville, and, secondly, your overall capacity and how much you think that will grow with the CapEx that you're expending?

Right. And the CapEx I was speaking to, Paul, is not in the processing side, it's on the actual logistics side and how we move the barrels out of the refinery, either through pipelines or via the dock and exports. Let me ask Rich to clarify -- Rich Bedell here to clarify 1 thing. There was some discussion this week about a certain permit. And Garyville continues to run very well. And as you recall, we had ability to run incrementally 180,000 barrels per day. We now have a permit to run 290,000. That's in the new expansion we put on, and it's running very, very well. But, Rich, why don't you talk about the question we had earlier this week about the permit?

Yes, there was -- an article came out that said the hydrocracker expansion at Garyville was going to be completed in the third quarter of this year. It's actually going to be in the first quarter of next year. The -- it's all part of a -- it's really 4 segments to a diesel optimization project that Garyville that go in, in various phases, and 1 phase of it is in the third quarter of '13, which is going to be a crude improvement diesel recovery project there and then the hydrocrackers in the first quarter of 2014.

Our next question comes from Paul Cheng from Barclays.

Two quick questions, if I could. One is a simple one. What is -- Gary, based on your best guess, how much do you think is the RIN cost being passed through so far or that you guys have been able to pass through?

Well, Paul, this is Garry Peiffer. As I said, it's really difficult to estimate the RIN effect versus just normal supply and demand. So I wouldn't even want at this point hazard a guess how much is actually being passed through to the consumer. However, I guess, I would add, as Don suggested, that we do believe a substantial part of that is being reflected in the spot market values that you're seeing for gasoline and diesel fuels. So we do think that the -- if you look at, kind of, what the economic additions were in the second quarter and what we would have expected the crack spreads to be in the second quarter adjusted for how the Brent and LLS prices move, plus the fact that gasoline imports were similar to past years, so that means the importers will have to acquire a RIN, we're still making money, bringing barrels to the U.S. versus their next best alternative that we still think that there is some of -- there is a substantial amount of RIN being reflected in the spot market value.

Say, along that line, Garry, can you help me understand? I'm trying to think of -- in the ethanol market, when you guys sell a refined gasoline in your billing invoice to your customer, you identified that what is the output price and then what is the ethanol in the past fuel cost in the invoice? Why can't the industry do something similarly to the RIN? Is there anything that stop you guys in doing it? Because by doing it this way, a, then we know that whether it's been possible; and, b, it will also allow a transparent way for the consumer to know that how much they're being get hit. And if you really want MPC to act to change the role to a million more realistic program, it seems like you need the consumer to speak up.

Yes. We've thought about that suggestion over the last few weeks and months. And I guess, it's really going to be impacted by competitive conditions, Paul, and we obviously are not the only marketer so we'd have to consider the -- what the competition is doing. But because there's some marketers out there what we would call non-obligated marketers that Don referred to who are net sellers of RINs. And then, we have obligated parties who are buyers of RINs comminuting at the wholesale level, it's going to be very confusing for the buyer of those E10s and other biofuels to say, is there a tax added on or not a tax added on or separate line charge. So probably, if it were to be done most effectively, it would have to be done at the spot market level, but I don't think you're going to see it happen there either. So we're not optimistic that that's going to happen, unless competitive conditions dictate it does.

Can I just sneak in a real short one for Don? What is the market value of the inventory overall?

$5.1 billion.

Our next question comes from Chi Chow from Macquarie Capital.

I'm curious on, here in the third quarter, the impact of the backwardated WTI market. Could you give us some comments and maybe your outlook on what impacts this is going to have on market structure measured here in the third quarter, what percent of crudes you purchased on a CMA basis and any thoughts on the outlook on how the curve will trend going forward here the rest of the year?

Yes. Chi, this is Mike Palmer. It's pretty -- I think it's pretty hard to forecast the extent of that backwardation and how long it's going to last. Obviously, what that tells us about the market is that there are companies out there that believe that supply is short today, and that's the reason that the market is in this backwardated phase. As I said, again, we don't try and forecast what those numbers are going to be going out. I think that there are a number of reasons that you could point to, to say that worldwide that there has been some shortages. It's hard for us to see that in the Gulf Coast. We have no problems supplying our refineries.

And, Chi, this is Garry Peiffer. On the CMA question, obviously, when you buy on a CMA basis and you're in backwardation, that otherwise increases the cost versus the calculation if you're in contango. So that would have a negative effect on the crack spread calculation if we're in backwardation. So I'd say the majority -- or most of the domestic crudes that we buy have a CMA pricing basis to them. So most of our domestic crudes are affected by that market structure in terms of what we acquire. So if they're in backwardation, that's going to be a bit of a drag versus a contango, which is a bit of a benefit.

Are your Canadian barrels priced on a CMA basis as well?

No, they're not.

No? Okay, okay. And then, secondly, can you give us some comments on the EBITDA contribution of DHOUP in the third quarter?

Yes. Chi, I just had that discussion. I'm sorry, you must have missed it. But what we have decided -- we did give that number after the first quarter and the same for Galveston Bay after 2 months in the first quarter. And competitively, we've decided not to give those numbers out individually going forward. I had the same question. We break them out kind of Midwest versus Gulf Coast. And at this time, we decided not to go that direction either. And as we've had discussion with many -- I should say, most of you in the past, these are very competitive numbers for us in the way we source our crude, and we just think that's the best thing for us to do going forward.

Okay. That's fair. So maybe I'll try this then. We've seen some volatility on the WCS pricing and differentials. Can you talk about your outlook on how you see the Canadian heavy dips trending here going forward?

Right. I'll -- let me have Mike cover that. But as you know, here in the second quarter, there are several production issues on the Canadian side, different producers who had downtime, a couple of upgraders that had some downtime. So that really affected the market in the second quarter and narrowed the spreads significantly. They have since widened out and widened out quickly. And let me have Mike go over the forward curve and what he sees now.

Yes. I guess, what I would say is, as Gary pointed out, we did hit a patch here where there were several production issues in Canada, and it doesn't take a lot to move the differentials. But as we look out through the end of the year, we know that there is a significant additional Canadian heavy that's due to come online. The Exxon crude volume is one of the major pieces, and it's been continually pushed back. But it will be available later in the year. And that, coupled with several other projects -- we believe that the differentials are probably going to widen out a bit from the point they're at today.

In that same -- to that same question, let me add one more thing, Chi. As you look going into the remainder of the year, as some of our competitors possibly bring up some heavier crude units, that's also going to change the historical shipping patterns and probably some of the historical marketers some of the sweet barrels are being replaced by these heavy barrels that we think will also have a positive effect on Midwest refineries running those sweet barrels.

Our next question comes from Evan Calio from Morgan Stanley.

On Galveston Bay, and not asking a break-out question here, yet you've been running the unit for an entire quarter. Could you discuss what you've learned there, good or bad, and update on the pace of potential feed changes to improve profitability, primarily the pace to source more Houston or Corpus-based crudes given the current discounts and, I guess, our expectation of forward and balance in that market?

Let me ask Rich to talk about, as you say, the pace of play on the refinery operations itself, how he's seeing some of the changes and operating practices and safety practices that he's been able to achieve. And then, Mike Palmer will take the latter question.

Yes. Evan, this is Rich. Overall, we're very pleased with the Galveston Bay refinery and how it's operating. The safety record, both personal and process safety, has been excellent there for the 6 months we've been running it, and we've been working to incorporate our standards and our operating philosophies in the plant, and they've been very well received by the workforce. So overall, the direction of the refinery, we're very pleased with it in the short time that we've had it. I think Mike can comment a little bit about the crude changes.

Yes, sure will. Evan, we've made some pretty substantial changes already when we -- and of course, a lot of that is the fact that we're optimizing this plant every day. But the pipeline infrastructure continues to be built out. So what we've been able to do up to this point is pretty much displace the foreign sweet crude that have been coming into the plant with the domestic crudes that you had mentioned. I mean, we're running more West Texas sour, Eagle Ford, those types of domestic crudes. And frankly, we -- what we did was we look at the markets every day to optimize those slates. So it's not to say we won't run the foreign cargo crude, but we're always looking for the best barrels. We think, going forward, domestic is where it's at.

Great. If I -- a second question, if I could. I know we've discussed -- but PADD II gasoline imports have tapered since 2010 from all regions with some uptick recently into driving season. And as you look forward primarily in the first quarter when that market is more balanced due to seasonal demand, could you update us how you see the potential to move more product out of region and potentially into the East Coast?

Well, Evan, we don't want to get into our detailed strategy on how we're going to move products out, but you are correct. And if you go back in history, the PADD II certainly imported more from PADD III and some from PADD I historically. And due to the significant increase in run rates by PADD II refiners, that has negated the need to import as much. But certainly, we are looking at how and probably more so on the diesel side than the gasoline side and diesel side in the shorter quarters on how you balance things. But I'm sorry, we can't get into our individual strategy of how we're going to move our product into additional regions.

Our next question comes from Blake Fernandez from Howard Weil.

I had a question for you on Capline. I'm not sure how specific you can be, but there's been a lot of chatter that some of the strength we've seen in LLS pricing recently has been attributable to increased flows on Capline, basically the feed via BP/Whiting ramp-up. And I was just curious if you could provide any color there.

Yes. I don't know, Blake, that we can provide you any information on what any competitors are doing. I think, overall, again, what we do is we look at LLS or other crudes that we might move up Capline relative to other alternative crudes that we can run. I don't think that we've seen major changes -- major shifts on Capline over the past couple of quarters.

Okay, okay. The other question for you is a bit of a one-off, but it's on the chemicals side. Some of your peers are obviously evaluating some opportunities to use existing infrastructure and enter the chemicals business. And I didn't know if you've looked at that or if any of your facilities may have some opportunities there.

Right. Let me have Rich take that. This isn't the chemicals side but just to refresh that we have talked about a couple of splitters, 1 in Canton, 1 in Catlettsburg as a way to be able to utilize the feedstock that doesn't get into the chemicals side of the business. But that is something that we certainly have ongoing. But Rich will cover some of the chemicals as -- because we're -- also just took over a big chemical operation. About 1/3 of the output of Galveston Bay is really on the chemicals side. So, Rich?

Yes. I mean -- and we continue to look for opportunities to where to invest. But our focus lately has really been on the condensate splitters, to take advantage in the Utica, moving more of the light crudes through our system and then optimizing in Galveston Bay and its aromatics picture there. So if you're talking about -- referring to Valero's methanol plant, no, we're not looking at anything in regard to a methanol plant.

Our next question comes from Jeff Dietert from Simmons. Jeffrey A. Dietert - Simmons & Company International, Research Division: A question for Mike, and this would be a bit of a follow-up, I think on Evan's question, but it looks like your WTI-based feedstocks have been declining in recent quarters and other sweets have been increasing. I suspect a lot of that is the integration of the Galveston Bay refinery. But are there other factors impacting those shifts and how do you expect that to go going forward?

Yes. Jeff, I guess, what I would say is, if you look at the chart that we published in the second quarter, the percentage of the WTI-based crudes remained about the same. It has gone down from previous quarters, and I think that was a result of bringing Galveston Bay on that didn't have access to as much WTI-based crude. But the interesting thing about the second quarter is that we actually ran a higher crude rate. So in order to maintain that 22% level, we actually did increase the volume of the WTI-based crudes that went into the system. The other thing I think you'll find -- I think the other thing you'll find of interest on that chart is that the other sour crude went down, whereas the sweet crude did go up. And that's pretty much just a result of, I guess, the story that we've been telling you guys, and that is that the sweet crudes are getting more attractive as -- through time, as they continue to grow. And we've been very much focused on the crudes from North Dakota or the Eagle Ford. Jeffrey A. Dietert - Simmons & Company International, Research Division: Very well. Mike, you guys have a good view into -- about the Gulf Coast and the Mid-Con and crude markets. Could you talk to us about what you expect the WTI-Brent differentials to look like through the second half of this year and what 2014 average might look like?

I guess, Jeff, the way I'd answer that is just to say that, if you go back and take a look at the second quarter, we began the second quarter with a Brent-TI spread around $12.5, and it moved out to around $4.5. By the end, it changed about $8. We then moved to flat. And after it was at flat, it moved to about $3.80 again. And now, it's in another dollar. So the one thing I would say to you is that it's going to remain extremely volatile, and that's the only thing we know with certainty. I think that, as Gary said earlier, when we think about the ARB, really, what we think about is that you've got a transportation cost to get those barrels from Cushing to the Eastern Gulf, where they need to go to clear. And so, when we look at the forward curve and see that it's around that $7 or $8 level, that makes some sense to us. But at the same time, we know that there is a lot of emphasis on these spreads and there's going to be a lot of trading activity. So the pendulum will move back-and-forth. There's going to be a lot of volatility.

And, Jeff, that's why I made my comment earlier that you're going to see possibly a big swing later in the year, as some other refiners possibly bring up heavier crude units. That's going to put more light sweet crude back on the market in different regions of the country. And I think it's going to change some pressure points and also lead to that widening out that we're talking -- that Mike was just talking about and I spoke about earlier.

Our next question comes from Robert Kessler from Tudor, Pickering, Holt. Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: I just wanted to push a point that you made earlier on light crude supply tightness. You said that globally, at least, there are some signs of shortages, but you, of course, had no problem sourcing your crude in the U.S. Gulf Coast. And I just wanted to push that point a little bit. Obviously, if we look at LLS and it's at a premium of Brent. So on that benchmark, that would imply the Gulf Coast is actually tighter than Brent or has been in recent history. That's, of course, if you believe LLS is representative of the coastal delivered price, and I think we generally don't. But that's really my question is what does your average coastal delivered price look like relative to LLS, particularly with Galveston Bay?

Well, I think, again, when you look at LLS, it's not a huge stream today. And on the margin, obviously, it couldn't command a premium to Brent that wouldn't be happening today. But I guess, again, as I tend to look forward and we think that the light sweet crude coming from, again, the Permian Basin or the Eagle Ford, perhaps even North Dakota continuing to move south, we just believe that, that LLS differential can't last, that it will turn into a discount at some point. Exactly when that happens is very difficult to understand. Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: What would you say you're getting for delivered price in Houston today relative to LLS?

Well, I guess, we just don't get into that kind of a detail. We probably can't answer that question.

Our next question comes from Jason Smith from Bank of America Merrill Lynch.

It's Jason on for Doug. Just come back to Galveston Bay again. I know we've spent some time on the crude slate. I mean, now that you've had a few months at the plant, have you found any incremental opportunities maybe with the existing Texas City refinery nearby?

Rich?

Yes, we have -- we found a number of synergies between the 2 plants in moving feedstocks and optimizing the operations between the 2. And we have projects that we're looking at to further increase that.

Okay. And should we maybe expect a synergy update at the Analyst Day later this year?

Yes, it's one of our plans, Jason, to be able to give you a little more color around Galveston Bay. We'll have many more months of operation at that time, but we'll give you more color then.

Got you. And on the Garyville hydrocracker, is there any chance you'd be willing to share a cost and potential EBITDA estimate there?

We do not -- this is a revamp. This is not a brand-new hydrocracker. It's a revamp of our big plant that we put on because we could see some low-hanging fruit. And, Rich, do you have any more color?

Well, I mean, at our first Analyst Meeting in New York, we did give some guidance around that. And it's basically 4 different projects that, at that time, we said it was about $250 million over 4 years. And the EBITDA based on 2011 prices was $160 million is what we told you all.

Our final question comes from Roger Read from Wells Fargo.

The question I had is maybe fairly straightforward, but I noticed the yield to gasoline lower in this quarter. I'm presuming at Galveston Bay its different product output. But is there anything else going on? I mean, is this a function of cracks in the market, RINs cost, anything like that that's taken it down from the low 50s to the upper 40% of gasoline blend stocks yields?

No, I think it all has to be due to Galveston Bay coming on. As I said, approximately 1/3 of their output is on the chemicals side. So that would account for the majority. Then you'll have a little maintenance in different plants here and there. So that could be maybe less than 1% as you take refineries down for maintenance. It just depends on which unit, but the most should be GBR.

Okay. And the only other question I had, with the Ho-Ho line expected to be shut down here at the end of this month, I believe, for the reversal later this year, any thoughts on the impact that will have on pricing of crudes out of the Gulf of Mexico or LLS in terms of the very near term and anything you can provide in terms of thoughts on that?

Yes. This is Mike Palmer. I guess, it's bound to have some impact, although a part of that line is already down. So I wouldn't think that, that's -- I wouldn't think there would be anything that would be dramatic.

I'd like to turn the call back over to Pam for closing remarks.

Okay. Well, thank you, Cliff. Thanks, everyone, for joining us on the call today, and we'll be in the office for the rest of the day. So you can call and ask for myself, Beth Hunter and Jerry Ewing [ph], who's new to -- a recent addition to our team. So thanks, everybody, for your interest. Bye-bye.

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