Marathon Petroleum Corp (MPC) 2013 Q2 法說會逐字稿

Welcome to the Second Quarter 2013 Earnings Call for Marathon Petroleum Corporation.

My name is Cliff, and I will be your operator today.

At this time, all participants are in listen-only mode.

Later, we will conduct a question-and-answer session.

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.

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.

Factors that could cause actual results to differ are included here, as well as in our filings with the Securities and Exchange Commission.

Now I will turn the call over to Gary Heminger for opening remarks.

Thank you, Pam.

Good morning to everyone.

Thanks for joining us today.

If you 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.

Pipe 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 Pipeline 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 five-year average, with much of the increase in PAD 3. This contributed to a draw-down of crude inventories to meet refining demand, and the narrowing of crude spreads.

In addition, gasoline inventories were higher than last year and the five-year average.

As a result, the US 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-area refineries came back on line, a short-supply situation in the Midwest quickly reversed into a long supply situation.

Rapid movements in spot prices in a 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 mean time 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 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.

An indicator is the forward curve, which suggests 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.

Now I will 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 walk 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 and marketing segment, harshly offset by an increase in income from Speedway and the pipeline transportation segments, and lower income taxes.

As shown on slide 6, refining and 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, two of which are worth noting.

First, about 40% of our refining capacity, and almost all of our purchase for resale activity is in PAD 2. The Chicago refined products 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 per 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 carry a 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 utilize an LLS 6321 crack spread that includes neat gasoline and diesel fuel spot-market values, or 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 two 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 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 feed stock volumes as of the close of the second quarter 2013.

In addition, we had a decrease in accrued taxes payable, due to the timing of estimated tax payments.

Also shown on this 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 0.5 times 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 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 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 access the opportunities in front of us.

Now I'd like to turn the call back to Pam Beall.

Thanks, Don.

As we open up the call for your questions, we ask that you do limit yourself to one question plus a follow-up.

Of course, you may re-prompt for additional questions as time permits.

With that, now Cliff, I'd like to open the call to questions.

(Operator Instructions)

Ed Westlake, Credit Suisse.

Thanks for the waterfall chart on the refining and marketing Q over Q. One question on the $313 million of the gross margin.

You said that includes RIN's $60 million for 2Q, leaving $250 million left over.

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 at the refinery?

That would be helpful.

Hello Ed, this is Garry Pfeiffer.

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 million or so 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.

We would say that the majority of that amount, the $313 million or so, 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 -- compared to spot.

That's compared to spot, Ed.

As that spike is unwound 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.

Okay.

The other comment you said, Galveston Bay was still profitable.

Would you be able to give us a run rate of EBITDA in the third quarter -- in the second-quarter, as you did for the first quarter?

Thank you.

Ed, this is Gary.

What we've decided, as you know, we gave you that number at the end of the first quarter.

We had just operated for two months.

But for competitive reasons, and as you know, we've never broken our refineries out individually.

We gave that because it was just after starting up Detroit, and just after acquiring Galveston Bay.

As I said, for competitive reasons we are not going to give out the numbers individually going forward.

Would you give a Gulf versus Mid-Con split?

Not at this time.

Okay, thank you.

Paul Sankey, 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?

I think you said a 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?

Thanks.

Right.

Yes, we had 190,000 barrels per day here in the second quarter.

It was 151,000 barrels per day in the first quarter; and Garry, do you have the breakdown of --

It's primarily diesel fuel, what we are exporting, roughly 170,000 to 190,000 was diesel fuel.

I guess as a practical limit, I think we are pretty close to a capacity, although every time we seem to say that, or schedulers and engineers find a way to eek a little more out.

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.

Roughly, that's probably our practical limit, in that neighborhood of 190,000 to 200,000 barrels a day.

The other thing, Paul, that we're doing, as you've heard us talk about this before.

Both at Galveston -- excuse me, at Garyville, where we are 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.

The way we operate today is basically on line and straight through the tanks.

In order to be able to certify it going to some foreign countries, we need to be able to let it settle out.

We are investing in some incremental tankage to be able to do that.

In the future, we will be increasing our gasoline exports.

Then we're also, now, looking at how we can improve on the exports out of Galveston Bay.

Garry's right for the assets as they sit today.

We think we are pretty much at the peak.

But we are investing in both to be able to increase the number into the future.

Maybe one slight clarification.

The 151,000 Gary referred to was fourth-quarter of 2012, and first quarter was about 121,000, so we had a little bit of a dip there.

But 121,000 first quarter of 2013, 151,000 fourth quarter 2012.

All right, thank you.

Further to what you're saying, I know you've 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 was originally -- name plate, 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 are expending?

Thanks.

Right.

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 one thing.

There was some discussion this week about a certain permit.

Garyville continues to run very well.

As you recall, we had built it 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 well.

Rich, why don't you talk about the question we had earlier this week about the permit?

Yes, there was an article came out and 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.

It's all part of a -- it's really four segments to a diesel optimization project at Garyville that go in, in various phases.

One phase of it is in the third quarter of 2013, which is going to be a crude improvement, diesel recovery project there.

The hydrocracker is in the first quarter of 2014.

Great, thank you.

Paul Cheng, Barclays.

Two quick questions, if I could.

One is a simple one.

Want to just -- Garry, based on your best guess, how much you think is the RIN costs being passed through so far, or that you guys have been able to pass through?

Paul, this is Garry Pfeiffer.

As I said, it's really difficult to estimate the RIN effect versus just normal supply and demand.

I wouldn't even want to at this point hazard a guess how much is actually being passed through to the consumer.

However, 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 are seeing for gasoline and diesel fuel.

We do think that if you look at kind of what the economic conditions 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 moved, plus the fact that gasoline imports were similar to past years.

That means that importers who have to acquire RIN were still making money bringing barrels to the US versus their next-best alternative, that we still think there is some -- there is a substantial amount of RIN being reflected in the spot market value.

Say along that line, Gary, can you help me understand?

I'm trying to figure, in the ethanol market, when you guys sell a reformulated gasoline and you're billing invoice to your customer, you identified that what is the (inaudible) price, and then what is the ethanol as a pass-through cost in the invoice.

Why can't the industry do something similarly to the RIN?

Is there anything that stops you guys in doing it?

By doing it this way, A, then we know that whether it's being passed through; and B, it would also allow a transparent way for the consumer to know that how much they been got hit.

If you really want Washington, D.C., to act to change the law to make it more a 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.

I guess it's really going to be impacted by competitive conditions, Paul.

We obviously are not the only marketer, so we have to consider what the competition is doing.

But because there's marketers out there -- what we would call non-obligated marketers that Don referred to who are net sellers of RINs.

Then we have obligated parties who are buyers of RINs competing at the wholesale level.

It's going to be very confusing for the buyer of those E10's and other biofuels to say, is there a tax added on, or not a tax added on, or a separate line charge.

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 are going to see it happen there, either.

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 (inaudible)?

$5.1 billion.

Thank you.

Chi Chow, Macquarie Capital.

I'm curious on here in the third quarter, the impact of the backwardation WTI market.

Can you give us comments on maybe your outlook on what impacts this is going to have on the market structure measure here in the third quarter?

What percent of crudes you purchase 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, this is Mike Palmer.

It's pretty hard to forecast to 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.

That's the reason that the market is in this backwardated phase.

As I say, 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 there has been some shortages.

It's hard for us to see that in the Gulf Coast.

We have no problems supplying our refineries.

Chi, this is Garry Pfeiffer.

On the CMA question, obviously when you buy on a CMA basis and you are in backwardation that otherwise increases the cost versus the calculation if you're contango, so that would have a negative effect on the crack spread calculation if we are in backwardation.

I would say the majority, or most of the domestic crudes that we buy, have a CMA pricing basis to them.

Most of our domestic crudes are affected by that market structure, in terms of what we acquire.

If we are in backwardation, that's going to be a bit of a drag, verses a contango, which is a bit of a benefit.

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

No, they are not.

No?

Okay.

Thanks for that.

Secondly, can you give us some comments on the EBITDA contribution of DHUP in the third-quarter?

Yes, Chi, I just had that discussion.

I'm sorry must have missed it.

What we've decided -- we did give that number after the first quarter and the same for Galveston Bay after two months in the first quarter.

Competitively, we've decided not to give those numbers out individually going forward.

I had the same question do we break them out Midwest versus Gulf Coast.

At this time, we've decided not to go that direction, either.

As we've had discussion with many -- I should say most of you -- in the past, these are very competitive numbers for us and the way we source our crude.

We think that's the best thing for us to do going forward.

That's fair.

Maybe I will 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 diff trending here, going forward?

Right.

Let me have Mike cover that.

As you know here in the second quarter, there were several production issues on the Canadian side.

Different producers who had down time, a couple of upgraders that had some down time.

That really affected the market in the second quarter, and narrowed the spread significantly.

They have since widened out and widened out quickly.

Let me have Mike go over the forward curve, and what he sees now.

Yes, what I would say is, as Gary pointed out, we did hit a patch here where there were several production issues in Canada.

It doesn't take a lot to move the differentials.

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 on line.

The Exxon curl volume is one of the major pieces, and it's been continually pushed back.

But it will be available later in the year.

That, coupled with several other projects, we believe that the differentials are probably going to widen out a bit from the point they are at today.

Okay.

Thanks, Mike.

Appreciate it.

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 markers from some of the sweet barrels are being replaced by these heavy barrels that we think that will also have a positive affect on Midwest refiners running those sweet barrels.

Okay.

Thanks, Gary.

Evan Calio, Morgan Stanley.

On Galveston Bay and not asking a break-out question here, yet you've been running the unit for an entire quarter.

Can you discuss what you've learned there, good or bad?

An update on the pace of potential fee 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?

Good morning, Evan.

Let me ask Rich to talk about the -- 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.

Then Mike Palmer will take the latter question.

Evan, this is Rich.

Overall, we are 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 six months we've been running it.

We've been working to incorporate our standards and our operating philosophies in the plant, and they've been very well received by the work force.

Overall, the direction of the refinery, we are 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 -- of course, a lot of that is the fact that we are optimizing this plant every day.

But the pipeline infrastructure continues to be built out.

What we've been able to do up to this point is pretty much displace the foreign sweet crude that had been coming into the plant with the domestic crudes that you had mentioned.

We are running more West Texas sour, Eagle Ford, those types of domestic crudes.

Frankly, what we do is we look at the markets every day to optimize those slates.

It's not to say we won't run the foreign cargo crude, but we are always looking for the best barrels.

We think going forward domestic is where it's at.

Great, thanks.

If I -- a second question, if I could.

I know we've discussed, but PAD 2 gasoline imports have tapered since 2010 from all regions, with some up-tick recently in the driving season.

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?

I will leave it there.

Well Evan, we don't want to get into our detailed strategy on how we are going to move products out, but you are correct.

If you go back in history, the PAD 2 certainly imported more from PAD 3 and some from PAD 1, historically.

Due to the significant increase in run rates by PAD 2 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 shoulder quarters on how you balanced things.

But I'm sorry, we can't get into our individual strategy of how we are going to move our product into additional regions.

Okay, great.

Look forward to hearing about that in the future.

Thanks.

Blake Fernandez, Howard Weil.

I had a question for you on cap line.

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 increase flows on cap line, basically to feed the BP Whiting ramp-up.

I was curious if you could provide any color there?

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 cap line relative to other alternative crudes that we can run.

I don't think that we've seen major changes, maker shifts on cap line over the past couple quarters.

Okay.

The other question for you, it's a bit of a one-off.

It's on the chemicals side.

Some of your peers are obviously evaluating some opportunities to use existing infrastructure and enter the chemicals business.

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, you know that we have talked about a couple of splitters -- one in Canton, one in Catlettsburg -- as a way to be able to utilize the feed stock.

That doesn't get into the chemical side of the business, but that is something that we certainly have ongoing.

Rich will cover some of the chemicals.

We're also -- just took over a big chemical operation, about a third of the output of Galveston Bay is really on the chemical side.

So, Rich?

Yes, and we continue to look for opportunities to where to invest, but our focus lately has really been on the condensate splitters, take advantage in the Utica, move to more of the light crudes through our system, then optimizing in Galveston Bay and its aromatics picture there.

If you're talking about referring to Valero's methanol plant, no, we're not looking at anything in regard to a methanol plant.

Okay, thank you very much.

Appreciate it.

Jeff Dietert, Simmons.

Question for Mike.

This a bit of a follow-up, I think, on Evan's questions.

It looks like your WTI-based feed stocks 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 -- 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 had gone down from previous quarters, and I think that was the 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 in to the system.

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.

That's pretty much just a result of the story that we've been telling you guys.

That is that the sweet crudes are getting more attractive through time as they continue to grow.

We've been very much focused on the crudes from North Dakota or the Eagle Ford.

Very well.

Mike, you guys have a good view into both the Gulf Coast and the Mid-Continent crude markets.

Could you talk to us about what you expect WTI Brent differentials to look like through the second half of this year, and what 2014 average might look like?

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 $12.50, and it moved out to around $4.50 by the end.

It changed about $8.

We then moved to flat.

After it was at flat, it moved to about $3.80 again.

Now, it's in another $1.

The one thing I would say to you is it's going to remain extremely volatile.

That's the only thing we know with certainty.

As Gary said earlier, when we think about the arm, 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.

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.

Jeff, that's why I made my comment earlier that you are 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.

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.

Thanks, Gary.

Thanks, Mike.

Robert Kessler, Tudor Pickering and Holt.

I just want to push a point that you made earlier on light crude supply tightness.

You said that globally, at least, there were some signs of shortages, but that you of course had no problem sourcing your crude in the US Gulf Coast.

I just wanted to push that point a little bit.

Obviously, we look at LLS, and it's at a premium at Brent.

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.

What is your average coastal delivered price look like relative to LLS, particularly with Galveston Bay?

Again, when you look at LLS, it's not a huge stream today.

On the margin, obviously, if it couldn't command a premium to Brent, that wouldn't be happening today.

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.

What would you say you are getting for a delivered price in Houston today relative to LLS?

Well, we just don't get into that kind of a detail.

Probably can't answer that question.

Thanks, anyway.

Jason Smith, Bank of America Merrill Lynch.

Just coming back to Galveston Bay again.

I know we spent some time on the crude side.

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?

Yes.

We have -- we found a number of synergies between the two plants in moving feed stocks and optimizing the operations between the two.

We have projects that we are looking at to further increase that.

Okay, thanks.

Should we maybe expect a synergy update at the Analyst Day later this year?

Yes, that's one of our plans, JT, 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 will give you more color then.

Got you.

On the Garyville hydrocracker, is there any chance you would be willing to share a cost and potential EBITDA estimate, there?

We did not -- this is a re-vamp.

This is not a brand new hydrocracker.

It's a re-vamp of our big plant that we put on, because we could see some low hanging fruit.

Rich, you have any more color?

At our first analyst meeting in New York, we did give some guidance around that.

It's basically four different projects that, at that time, we said it was about $250 million over four years.

The EBITDA, based on 2011 prices, was $160 million, is what we told you all.

Okay, thank you.

Thanks, guys, appreciate it.

Our final question comes from Roger Read with Wells Fargo.

Question I had, this may be fairly straightforward, but I noticed the yield of gasoline lower in this quarter.

I'm presuming a portion of that is a function of Galveston Bay and its different product output.

Is there anything else going on?

Is this a function of cracks in the market, RINs costs, anything like that, that's taking it down from the low 50%s to the upper 40% of gasoline blend stocks yield?

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.

That could be, maybe, less than 1% as you take refineries down for maintenance.

It just depends on which unit.

But most would be GBR.

Okay.

The only other question I had, with the HoHo 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?

Anything you can provide, in terms of thoughts on that?

This is Mike Palmer.

It's bound to have some impact, although part of that line is already down.

I wouldn't think that that's -- I wouldn't think there'd be anything that would be dramatic.

Okay.

That's it, thanks.

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.

We will be in the office the rest of the day.

You can call and ask for myself, Beth Hunter, and Geri Ewing, who's new to -- a recent addition to our team.

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.