Marathon Petroleum Corp (MPC) 2011 Q2 法說會逐字稿

Welcome to the Marathon Petroleum Corporation second quarter 2011 earnings conference call.

My name is Monica and I'll be your operator for today's call.

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

Later we will conduct a question and answer session.

Please note that this conference is being recorded.

I will now turn the call over to Pam Beal.

Pam Beal, you may begin.

Thank you, Monica, and welcome, everybody, to Marathon's second quarter 2011 earnings call.

A synchronized slide that accompany this call can be found on our website at Marathonpetroleum.com.

On the call today are Gary Heminger, our President and Chief Executive Officer; Garry Peiffer, Executive Vice President of Corporate Planning and Investor and Government Relations; and Don Templin, Senior Vice President and Chief Financial Officer.

If you turn to slide 2 you will see it contains a discussion of forward-looking statements and other information included in this presentation.

Our remarks and answers to questions today will contain forward-looking statements.

They are subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied by such statements.

In accordance with Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995, Marathon Petroleum Corporation has included in its form 10 filed with the Securities and Exchange Commission and the earnings release issued earlier today cautionary language identifying important factors, but not necessarily all factors that could cause future outcomes to differ materially from those set forth in the forward-looking statements.

Please note that in the appendix to this presentation is a reconciliation of quarterly net income to adjusted net income and other data that you may find useful.

Now I would like to turn the call over to Gary Heminger for some opening remarks.

Thank you, Pam.

If you go to slide 3.

As you know, Marathon Petroleum Corporation was spun off from Marathon Oil Corporation effective June 30, 2011.

This transaction was executed as planned and we now have all of our people, processes, and financing in place to operate as a best in class independent downstream Company.

We have a strong balance sheet, an investment grade credit rating and a number of projects under way that we believe position us well for earnings and cash flow growth.

On July 27 of 2011 we declared our first quarterly dividend of $0.20 per share payable on September 12 of 2011 to the shareholders of record on August 17 of 2011.

During the second quarter, we continue the optimization of our expanded Garyville refinery and increased our distillate exports from Garyville to approximately 70,000 barrels per day.

With modest additional investment, we believe we can increase our distillate exports, providing us with additional options to place production in higher value markets.

Upgrades to our Detroit refinery are approximately 63% complete.

This project remains on budget and on schedule for completion in the second half of 2012.

This project will allow us -- I should say should allow us to process an incremental 80,000 barrels per day of heavy Canadian crude, lower our feed stock costs, and increase Detroit's crude oil refining capacity about 15% to 120,000 barrels per day.

During the second quarter we continued to benefit from wider differentials between West Texas Intermediate and other wide sweet crudes, as well as the differential between LLS and our normal slate of sour crudes.

This increased our income from operations despite further signs of a weak economy.

During the second quarter 50% of the crude we processed was sour.

Leveraging our logistics systems, we were able to increase the amount of the crude we processed that was linked to WDI pricing and Canadian heavy to about 35%, up from approximately 33% in the first quarter and about 25% in the fourth quarter of 2010.

If oil production in North America continues to grow faster than the logistics to deliver this production to consuming markets, we expect wider differentials to continue.

During the second quarter of 2011, Speedway completed the purchase of 23 convenience stores in Chicago, Illinois and Northwest Indiana, which strengthens its presence in this important geographic area.

All of the locations have been rebranded under the Speedway flag and we are very pleased with the initial results of these operations.

This is a segment of the business we intend to grow in contiguous areas through a combination of greenfield sites and selective acquisitions.

At our Speedway retail business, we realized strong gasoline and distillate gross margins during the quarter.

This partially offset the impact of lower gasoline and distillate sales volumes, primarily associated with a 166 convenience stores sold as part of the December 2010 sale of our Minnesota refinery and related assets.

The spin-off of Marathon Petroleum from Marathon Oil Corporation effective June 30, 2011 was the right transaction at the right time.

Our fully integrated approach and sharp business focus provide operational flexibility and the ability to efficiently move petroleum-related products through our system.

Looking ahead, not only do we expect to continue to benefit from the Garyville expansion, which is in full production and is operating above its name plate, Crude Oil Refining Capacity, but also our Detroit heavy oil upgrading project should come online during the second half of next year.

We are also optimistic about the growth prospects for our Speedway retail operations.

We expect these investments to enhance our earnings and our cash flow for many years to come.

And now I'll turn it over to Don Templin, who will review the financial results for the quarter.

Don?

Thank you, Gary.

Slide 4 provides net income and adjusted net income data, both on an absolute and per share basis.

Our second quarter 2011 adjusted net income of $819 million reflects a 94% increase from the $422 million earned in the second quarter of 2010.

The waterfall chart on Slide 5 shows by segment the change in adjusted net income from the second quarter of 2010 to the second quarter of 2011.

The primary reason for the increase in our adjusted net income was the increase in refining and marketing income, partially offset by higher income taxes.

For the 2011 second quarter, the effective income tax rate was 40% compared with 37% in the second quarter of 2010.

Our 2011 tax rate was impacted by changes in state income tax legislation, primarily in Michigan.

This resulted in a $17 million tax charge during the 2011 second quarter that has been treated as a special item.

The refining and marketing variance analysis is shown on Slide 6.

Refining and marketing segment income from operations was $1.26 billion in the second quarter of 2011 compared with $590 million in the second quarter of 2010.

This increase was primarily the result of higher refining and marketing gross margin, which I will discuss on the next slide.

Before I do that, I wanted to explain the $63 million in other items.

This change is primarily due to higher refined product transportation costs and incremental incentive compensation accruals due to our strong results during the first half of 2011.

Slide 7 shows a few of the economic drivers contributing to the improved refining and marketing gross margin for the second quarter.

Our gross margin in the second quarter of 2011 benefited from a wider WTI-LLS differential, a wider sweet/sour differential and higher Chicago and US Gulf coast track spreads.

A WTI-LLS differential increased nearly $12.00 per barrel from an average of $4.11 per barrel in the second quarter of 2010 to $16.09 per barrel in the second quarter of 2011.

The sweet/sour differential increased approximately 25% from an average of $8.78 per barrel in the second quarter of 2010 to $11.08 per barrel in the second quarter of 2011.

In addition, our blended Chicago US Gulf Coast LLS crack spread increased from $3.20 per barrel in the second quarter of 2010 to $5.53 per barrel in the second quarter of 2011.

Our average refinery inputs were 1,372,000 barrels per day or 21,000 barrels per day lower than the second quarter last year.

This primarily reflects the impact of the December 2010 sale of the Minnesota refinery, partially offset by the Garyville major expansion, which is operating at higher rates than the comparable quarter last year.

I should also mention that our refining and marketing results included higher derivative gains in the 2011 second quarter compared with the same period last year.

While the pricing mechanism we have in place for domestic crudes allows us to price them close to the time they are refined without the use of derivatives, our foreign crude purchases start pricing as much as two months before we process them.

As a result, we use derivatives to float the price of our foreign crude purchases until closer to the time we begin processing them.

As a result, during the 2011 second quarter derivative gains totaled $234 million compared with $73 million in the 2010 second quarter.

Turning to Slide 8, Speedway's income from operations was $80 million in the second quarter of 2011 compared with $83 million in the second quarter of 2010.

Speedway's gasoline and distillate gross margin was about $10 million higher in the second quarter of 2011 compared with the second quarter of 2010.

The higher gasoline and distillate gross margin, which increased from $0.117 per gallon in the second quarter of 2010 to $0.15 per gallon in the second quarter of 2011, was partially offset by lower refined product sales volumes.

These reduced volumes were primarily associated with the 166 convenience stores that were part of the December 2010 sale of our Minnesota refinery and related assets.

The lower merchandise gross margin dollars and lower expenses in the second quarter of 2011 also primarily reflects the effects of the Minnesota asset disposition.

Same store gasoline sales decreased 5% and same store merchandise sales were flat in the second quarter of 2011 compared with the 2010 second quarter.

The lower same store sales reflect weaker demand and the impact of the higher price level of gasoline.

The average retail gasoline price was $3.74 per gallon during the second quarter 2011 compared with $2.69 per gallon for the comparable quarter last year.

In July 2011, we continued to see lower demand with an approximately 4% decrease in same store gasoline sales, which we believe is a result of the weak economic recovery in the United States.

Slide 9 shows the pipeline transportation segment income.

Income from operations was $54 million in the second quarter of 2011 compared with $48 million in the second quarter of 2010, primarily associated with increased volumes that were transported.

The table on Slide 10 provides an analysis of cash flows for the second quarter of 2011.

At June 30, 2011 our cash balance was $1.622 billion.

Operating cash flow before changes in working capital was $1.068 billion.

The working capital changes of $1.031 billion noted on the slide primarily relate to a seasonal increase in inventory volumes.

Capital expenditures and investments during the quarter were $345 million, primarily related to our Detroit heavy oil refinery project and the acquisition of 23 convenience stores.

The slide also reflects the various cash movements required to implement this [in] transaction.

We expect capital spending for the full year 2011 will be approximately $1.3 billion, including approximately $158 million of capitalized interest and corporate items.

Slide 11 shows that at the end of the second quarter we had $1.6 billion of cash and approximately $3.3 billion of debt.

Our cash adjusted debt-to-capital ratio was 16%.

On July 1, 2011, we completed a new trade receivable securitization facility in an aggregate principle amount not to exceed $1 billion.

Along with our $1.6 billion in cash and our $2 billion revolving credit facility, this should provide us with significant flexibility to manage our operations and to pursue value enhancing organic growth opportunities and selective acquisitions.

As we look forward, we expect our refining crude oil inputs to be approximately 1.2 million barrels per day for 2011 versus 1.1 million barrels per day for 2010, in spite of the fact that we sold the Minnesota refinery effective December 1, 2010.

As you know, our historical corporate costs do not reflect all of the costs of operating as a standalone Company.

We estimate these costs will total an incremental $50 million pretax on a normalized annual basis.

Finally, assuming no other special items during the remainder of 2011, we expect the overall income tax rate to be approximately 38% for the full year.

Now I will turn the call back to Pam Beal.

Thank you, Don.

Before we open the call to questions, we ask that to accommodate all who wish to ask questions, you limit yourself to one question plus a follow-up.

You may re-prompt for additional questions as time permits.

And with that, we'll now open the call to questions.

(Operator Instructions) Doug Terreson of the ISI Group.

Congratulations on your results.

My question's on Garyville's performance in relation to the expectations when the plant was [drained] last spring, meaning you guys have always seemed pretty confident that you would be able to perform well at that plant, but it seems that production and yield are exceeding expectations and so I was wondering if you could provide some insight on this item and really any expectation that you may have for future progress at that facility.

Well, Doug, this is Gary.

Thank you for your comment.

Yes, we are performing very well.

Very pleased with the design engineering and the operation there at the Garyville.

You recall last fall we did request an increase in the permit and it was approved and we've been operating well above its nameplate capacity.

Have now increased the total capacity, nameplate capacity to 464,000 barrels per day.

Both on the crude side and on some of the other process units, we've been outpacing.

We believe we have some additional work that we could do to even debottleneck further as we go into 2012.

Don't have the details yet, Doug, nor the engineering complete on what that will be, but we certainly see upside in the plant, even from where it's operating today, which as I said earlier is significantly above the nameplate capacity.

Okay, great.

Thanks a lot.

You're welcome.

Ed Westlake of Credit Suisse.

Yes, two questions.

The first one, we just treat derivative gains as part of continuing operations, I think as you highlighted on your opening remarks to say that they just compensate for timing differences.

Can you just confirm that they just help your profits just to move in line with benchmark margins and walk through that?

This is Garry Peiffer.

That's correct.

We're just trying to emulate what the crack spreads you're using to forecast our earnings are doing.

So that's correct.

Good, I'm glad that's cleared up.

Just on the operational cash flow, very strong number, $1.07 billion CapEx in the quarter, as you said about free cash flow of about $700 million.

Can we talk a little bit about after [de-hoop] or even before, what are you planning to do with this excess free cash flow?

I'm thinking particularly in terms of returns of cash to shareholders.

Ed, this is Don Templin.

I guess, first and foremost we want to make sure that we maintain our investment credit profile.

So that's the underlying objective of many of the things that we will be doing.

Then I think secondly, we're going to look for opportunities, growth and value enhancement opportunities that are both organic and inorganic.

And I think then after that, we're going to make sure we're analyzing our sort of dividend policy and, as you know, our board of directors regularly reviews this on a quarterly basis.

So in terms of order of priority I would say investing in the business and making sure we're taking advantage of both organic and inorganic opportunities will be our focus.

And given the cash flow generation, I presume this will be up for review at the next board meeting.

When is that?

Next board meeting's in September.

Okay, thank you.

Paul Sankey of Deutsche Bank.

Yes, I will ask a follow-up to that one, if I could, on cash uses.

Acquisitions, I think you've been fairly clear that a major refinery acquisition would be very unlikely, particularly something outside of your fairway, I guess I'll call it, and that really the kind of expectations you're talking about are more in the retail and it's much smaller area.

Thanks.

Well, Paul, I think I've been very clear that we don't have any appetite to go across the Atlantic today, nor go to the West Coast and just do a merchant type of an acquisition.

But please understand, we do our homework and all of our analysis on anything that might be available and some that aren't always public that they are available.

So we do our analysis on all of those.

But you are correct, our plans right away are to continue to do, that Don just said, some of the inorganic debottlenecking at Garyville and I'm sure we will have some at Detroit once we finish the heavy oil upgrading project, which would give us some very good returns.

I've stated that we want to continue to invest in our retail operation, both the Speedway and the Marathon brand to continue our strong presence in the markets of which we serve.

And then we will go from there.

Gary, you've also talked about an ongoing CapEx level, I guess post Detroit, that's quite a way below where you're at now, correct?

Yes, next year we still have 1.2 to the 1.

-- was it?

About $1 billion next year.

About $1 billion, okay, I'm sorry.

About $1 billion left in total next year, Paul, which would include Detroit.

And then the run rate after that would be in the $750 million, $800 million range based on what we know today.

Now, that does not include some of these organic projects that Don spoke to, nor does it include -- we do have a fair amount of money in that number to be able to continue to invest in Speedway, but we don't have any major acquisitions in there.

So as you can tell, though, $700 million to $800 million is still a very small number, I should say, based on what we have invested over the last five to eight years.

Yes, I think you would be -- on that number annually, you would be generating free cash flow just on your quarterly cash flow on this quarter.

Just finally, on the level of debt that you, I guess, that you would consider you want to carry and above which -- any cash above which would be considered excess to requirements and that will be it for me, if you could just indicate what that level is.

Paul, this is Don.

We'll regularly evaluate sort of our debt level.

Right now we're at roughly $3.3 billion.

We just went out with those senior notes that are relatively new.

I'm not anticipating in the short-term that we're going to make a change either way.

Okay, thank you, gentlemen.

Our next question comes from Arjun Murti of Goldman Sachs.

Please go ahead.

Gary, in your opening remarks you noted, obviously, the very wide brent TI spreads and the LLS TI spreads and the challenges and the takeaway capacity to other region for crude oil supply leading to these spreads.

Can you talk about some of the solutions you see?

I think everyone's familiar with the longer term pipeline options, but before those pipelines, barging is something, I think, Marathon has some expertise in.

What is the practical capacity that you can take barging volumes through?

Can you give any economics as the kind of differential or costs associated with that?

And maybe beyond barging, what are some of the other shorter term options you see before the pipeline solutions come into play?

Thank you.

Well, Arjun, that's a multi-part question and let me say there are many competing factors that really I think are causing the WTI or the LLS-WTI spreads.

We go back to the first part of the year and really review the sweet, light sweet crudes that are required in the world because of the ultra low sulphur fuels that need to be manufactured in Europe and some other refineries in Asia.

That's number one, followed by the Libya problems and so it really depends on when we see Libya crude coming on.

That might affect the total global value of brent and therefore pulling LLS along with that.

So then I bring you back domestically and what happens and you kind of look at that corridor from Canada all the way to the Gulf Coast.

Absolutely there's a talk of a big pipeline that's going to go from Cushing down to the Gulf Coast.

But as I've said many times publicly, I don't believe that is the ultimate answer.

It all is going to come back to how much Bakken is produced and what the rate of growth is in the Bakken.

Then you have a new competing factor as you go down to the southern part, down towards the Gulf, in the Eagle Ford coming on and coming on very strong.

At one time, it was determined that, well, just the pipeline to the Gulf Coast would take the pressure off of Cushing and take the pressure off of some of these WTI-type crudes in the north.

Now you have that new pressure point being the Eagle Ford.

Yes, partially on the river is a very small solution, I would say.

And it's not so much the barge traffic, Arjun, as it is who has the capacity and how can you load barges in different markets up and down the river, is really I think the solution to your question.

So today that number is quite small in context with the total amount of crude that's moving into that marketplace.

So a long winded answer to, I think, a very complex issue driven by market dynamics and I didn't even get into the incremental Canadian production that's going to be produced and eventually land in the Patoka Wood River market as well.

So all those things I just mentioned are going to compete against each other, which I think lends us towards a wider differentials for a longer period of time.

Gary, that's very helpful.

I think clearly that one of the key assumptions is crude oil supply growth out of these shale plays in Canada continue.

So if we take that as a given and in the absence of pipelines and if barging is ultimately limited, can rails solve this problem?

Or we really are waiting for the big pipelines, whatever year or decade that turns out to be?

Well, you're absolutely right.

And, Arjun, let me turn it over to Mike Palmer here.

Mike is our Senior Vice President of all of our crude supply and knows the logistic systems very well.

So let me ask Mike to make a few comments on this issue.

Yes, Arjun, we've looked at this pretty carefully.

And I think Gary's pretty well hit it right on the nose.

When you look at either barging or rail or trucking, which would be the other alternatives to a pipe, the assets just don't exist.

And what can be done is in such small volumes that with the continued growth that we see in the shale plays, as well as in Canada, we just don't think it makes a difference.

So bottom line, until we believe, until one of these pipeline projects actually comes to fruition, it's very, I think, it's very unlikely that we're going to see these spreads come together a lot.

Arjun, let me make one other point.

When you look at the refineries across the midcontinent today and those refineries that kind of go from Oklahoma to through Ohio, all of those refineries have their own pipeline systems servicing those refineries today.

So we don't require incremental pipeline space to be able to get the crude into those refineries.

What is really required is some laterals, if you will, to be able to tie into those systems that run to not just Marathon's, but other refineries in the same region of the country today.

And I think the competitive factors that I've mentioned earlier is what's going to still be the kind of the unknown dynamic of how fast this production comes on stream.

Yes, eventually, there will be some pipelines that can be put into service that may take some of this crude to the water, but I think that is a much longer time coming.

That's really helpful.

Appreciate the answer.

Thank you.

Paul Cheng of Barclay Capital.

Gary, along to Airgun's question, I just want to say more specifically for Marathon, your Midwest system represent 54% of your total capacity.

Your TI link is at 35%.

So what step you could be taking to move that TI link much closer to 54% and how quickly you could do it?

Believe me, we are working on many ideas, as well, to kind of fit in with the explanation I just gave on how you can do some laterals or what you could do to increase your off take.

They are not ready for prime time yet.

So I don't want to get into those in detail yet.

We are working on what some of those opportunities can be.

And when you look at -- when we say we have 50%, 54% of our refining capacity in the midcontinent, that's true, but also a number of those barrels are supplied into the Gulf.

Some could be imported and we're looking at many different advantage crudes.

So it's not always just a barrel that's coming in a WTI-type barrel.

And the other big thing is when we finish [de-hoop] WCS, so the heavy Canadian will be a big part of our appetite, not only around Detroit, but we're running some derivatives, if you will, around, of heavy crudes through some of our other plants in the Midwest also.

Gary, is the Detroit currently getting the crude supply, the inland crude, including the onshore lower 48 and Canadian or they is really getting more on the offshore crude?

Let me ask Mike Palmer to discuss that.

Paul, at Detroit the heavy supply that we bring in today is pretty much all Canadian.

That's where the values really are.

In the rest of the slate, it's a mix.

It's both Canadian crude, as well as crude that we bring in from the lower 48 and sometimes it's cargo crude.

So it's a real mix.

It depends upon the crude economics at that point in time that we evaluate continuously.

Okay.

And if kind of two quick questions.

One, Gary, in the past that you guys have said pipeline MLP is not really fit into what you guys want to do, because the pipeline is really not strategic, wondering if that have any change seeings now that you are an independent Company in your (inaudible).

Right, Paul.

And let me just back to the other question, I just want to add one more thing.

We've always been (inaudible) at about 20,000 barrels per day of heavy Canadian is what we take into Detroit today.

So, I wanted you to know that the increment, the 80, was on top of that 20.

I wanted to clear that up.

Yes, Paul, very good question on the MLP.

As always, we continue to do our homework.

But as illustrated in the market today, with the big WTI-LLS differentials, the flexibility that our system gives us today, has given us historically, and we believe will give us the flexibility to monetize into the future.

We think it's just greater than the value of putting it off into an MLP.

So as we said, 32 days old in our new Company here, we still are going down the fairway that we think those assets live best within our corporate structure.

A final one for Gary Peiffer.

Earlier that you talking about the derivative gain, matching the benchmark indicator, I presume you are referring to the cash earning, not the report earning, because in LIFO, the report earning that is already, it doesn't matter which barrel that you (inaudible) that is always based on the -- costs already.

Am I interpret your comment correctly or that you're really talking about the report earning will not have changed at all?

Well, wouldn't have 3change at all.

It is kind of an absolute.

We're saying for the most part, the way the derivatives that we put in place, maybe it's a step back a minute, Paul, we've had a lot of conversations about derivatives.

Many years ago we used to use the synthetic P plus approach to price our domestic barrels which we were buying, and as you recall, we changed that approach on our domestic purchases a few years ago and now we do the calendar month average or we contract with our domestic suppliers to buy the crude on a basis that basically is at the same time that we refine the crude into refine products.

So we are able to price those domestic barrels that we buy basically at the same time as we refine the barrels.

The foreign crudes, though, we don't have that ability to use a contract arrangement to do it, so we use financial instruments, derivatives to essentially allow us to price the crudes into our refineries at approximately the same time as we refine them.

So we're mimicking to a pretty great extent what is going on with the crack spread indicators, because as you know, the crack spread is basically nothing more than comparing the current spot values of refined products to the prompt month price of crude, which is next month's price.

So in our case, what we're doing with those derivatives, and you're right, when you get into LIFO we are -- once we take those barrels into the -- take title to them, they come into our system.

But basically, the answer is that all we're doing is mimicking the crack spreads that all of us follow every day in terms of what we make on those barrels that particular month.

Okay, thank you.

Mark Gilman of -- The Benchmark Company.

Gary, to what extent have you locked in firm additional heavy crude capacity and pipeline arrangements to get that additional 80,000 to Detroit?

Well, we are in the process and -- let me first of all back up, Mark.

Today we move a lot of crude, about 100 -- we run just a little bit over 100,000 barrels per day, so obviously we have the pipeline capacity to move those barrels into Detroit today.

Granted, we'll be changing to a slate and it would be a heavier slate.

So we have many different avenues that we're working on to lock that in, but we feel very confident and we're in good shape on how we're going to be delivering that crude into Detroit going forward.

Is that synonymous with saying you don't have any firm transportation?

That's not what I said.

I said that we have many avenues, but I'm not going to get in publicly into what the firm transportation agreements we have are yet.

Nor is there necessarily a dedicated supply source at this point?

From a -- we do not have a dedicated supply source, if that's what you're driving toward.

It's always been our plan that we want to be a net buyer, if you will, and whatever the market value is and as we see the production continue to increase in Canada and some other opportunities in different fields coming out of Canada, we want to be, as I say, a market buyer.

Spot buyer.

Spot buyer is what I mean.

And one other one for me.

Gary, I assume that you're a significant seller of rigs, gasoline rigs at this point.

Give me an idea if that's true, what kind of contribution that makes, and in your mind is that type of business vulnerable at all to the phase-out of the tax credit on ethanol?

Mark, this is Garry Peiffer.

No, we're not a seller of RINs.

A few years ago I think you're right, when we were -- a few years ago we were, but we generated more than we needed in a particular year.

But lately, this year, we're buying on the neighborhood of maybe around $10 million worth of RINs a month or expensing about $10 million worth of RINs a month.

That's really b3eing driven by biodiesel RINs, the pricey RINs that we have to come up with in our system.

So, no, we're not in that seller, we're a net buyer to the tune of, like I said, about $10 million a month.

Okay, thanks, Gary.

Jeff Dietert of Simmons & Company.

I was going to go back to the WTI-LLS topic and ask about the current market.

We see Cushing inventories declining, perhaps not as much as seasonal norms, but they are declining nonetheless.

Pad 2 refining utilization is very high, mid-90s.

So high demand for crude.

Bakken growth has slowed because of weather and we've got the SPR putting 30 million barrels of LLS into the market.

All of those factors would argue for a narrowing WTI-LLS, yet we're at the widest point, about 25 barrels, $25 a barrel today.

Could you provide some insight as to why it's widening here in the demand strong peak season of the month -- of the year?

Yes, let me ask Mike to cover this.

Yes, that's a very good question, because it's difficult to figure out.

I think what I would say is that probably at this point, the things that you're talking about at Cushing are absolutely true.

And in fact, if you look at the inner month spreads that you see in the marketplace today, it reflects exactly what you're saying.

People aren't too concerned about Cushing.

There's plenty of storage.

The refineries are processing a lot.

So containment's not an issue.

But I guess what I would say is that when you look at kind of the macro dynamics that are going on, there is just a lot of money flow that wants to go into Brent versus WTI.

And I think that's the only way you can explain the very, very wide spreads that we see today, because there's certainly no formula that will give you the numbers that we're at, just slightly under $23.

And secondly on another topic, you provide information on the crudes in your sweet/sour differential.

As I compared the '07 to 2010 period to the 2011 period, western Canadian select goes down 5% and Mars goes up 5%.

Could you talk about why that is with Mars trading $20 over WTI and WCS, $18 under WTI, it seems like an unusual switch.

Yes, this is Garry Peiffer.

That's primarily driven, that switch is primarily driven when we sold our Minnesota refinery last year at St.

Paul Park.

We kind of backed off -- not backed off, we used less Canadian crudes this year than we did last year.

So the big switch there, I think you're referring to, is just the difference in our refineries.

Got you.

Maybe a little bit more Mars at Garyville as well, huh?

Correct, correct.

Yes, that's correct.

Yes, Garyville's running, good point, running higher and so we're using a lot of Mars at Garyville as well.

Any thoughts or plans or capability to include Eagle Ford crudes at Texas City?

Mike?

Yes, absolutely.

The Eagle Ford for Texas City is very important to us, obviously.

Today we actually are running as much domestic as we can and the Eagle Ford has actually gotten into what's called the Gulf Coast light stream that we've maxed out on at Texas City.

We're looking at some options that would allow us to back out any foreign crude there that we run at all, because we do expect that we'll run more Eagle Ford in the future.

And that's the intent.

What Eagle Ford volumes are you running now and what's the potential?

Jeff, we really don't -- we think that's very competitive to have that information, so we don't like to give out the volumes that we're buying and what refineries we're sending it to.

Okay.

I appreciate the Q&A.

Thanks, Jeff.

Evan Calio of Morgan Stanley.

Kind of following up on the trans (technical difficulties) let me take a new wrinkle here that what I think could maybe limit your future kind of cap line draws of disadvantaged crude.

Last week more clarity was provided by Utica Shale potentials, a new source of crude production, where in connection with an accelerated rig count activity, Chesapeake called the play Eagle Ford-like.

Now, I know MPC has almost 290,000 barrels of your capacity in or bordering Ohio, actually probably where you guys are sitting right now.

And while it's still early and it appears to be near the Utica fairway, could you provide me with a percentage of your Canton and Catlettsburg runs that are non-price advantaged feed stock today?

Evan, I think it's a little too early to get into that level of detail or really that level of competitive knowledge.

They have only drilled and I've read Chesapeake and some others' discussions on the Utica, as well and Marcellus.

A few wells have been drilled.

Looks promising.

In fact, as you look at the play, dry gas to wet gas, and then getting at more of an oily shale as you go west towards the Ohio border, obviously it sets right in the fairway for Canton and gives us the ability due to our transportation system to take some of that crude, if it were to be developed, take some of it down to Catlettsburg.

The Ohio River is that the way to Catlettsburg, theoretically at this point?

Yes, sir, yes, sir.

So we have a terminal in Mdland, PA, which would give us a way eventually to get some crude down there if need be.

But it's very early in the exploration side and trying to develop those, but I'd come back and say our two refineries are absolutely setting in the backyard of that play and I think we are very well positioned and we will have a tremendous appetite if they can develop the true crude source.

But no comment in terms of what -- how much of that is pulling through cap line or essentially getting from the Gulf Coast into those refineries?

Not today, Evan.

Okay, that's fair.

Also, just a quick follow-up.

I believe Garyville had some unplanned downtime in July for a week.

Could you update us on that and what's going on there, as well as any planned turnarounds through maybe as far as you want to go.

More in Q2 2012, I thought there was another Garyville reformer planned out for January.

And I'll leave it at that.

Right.

We did have some unplanned downtime surrounding our hydrocracker and it was a changer that needed to be repaired on the hydrocracker that kind of straddled the end of the second quarter, early into this quarter.

It's all been repaired and back up and running.

I think we were down circa 20 days or so as we went in and made that repair.

And so I would call it unplanned downtime.

It's fixed, it's operating very well, back up to its capacity we had been running prior to.

Does that limit your sour runs a little bit in the quarter that you just reported?

It was only like three or four days in the quarter we just reported, so it was diminimus.

Perfect.

Thanks, guys.

Yep.

Faisel Khan of Citi.

Can you give us a little bit of an update on the same-store sales.

I know in the quarter you said you were down 5% year-over-year.

I'm just trying to figure out where we trending.

Are we still down 5% into July or getting better or how are we looking here into August?

Faisel, I'm really pleased that you asked that question, because at the first quarter earnings call, we spoke to our same-store sales gasoline volume being down and let me kind of step back and help everyone recall the second quarter of 2010 and how we [led] through the balance of the year.

And really if I want everybody to recall that there was some circumstances outside of our control or anybody else's control that I think really changed a lot of market dynamics how our customers were buying their transportation fuels in the second, third, and partially in the fourth quarter of last year.

But specifically, second quarter of 2010 we were up 5% when the market was probably only up about 1% or so.

So we picked up a lot of volume that I think was being switched from some other refiners during that period of time.

Now, this year we're comparing ourselves on a same-store basis against the same period last year and we're down, we said, 4%, 4.5% in second quarter 2011.

So really we're comparing against a very big increase in the same quarter last year and now we hear the market is down this year in the 2% range.

So we've still been able to hang on to some of that market share we picked up last year, but clearly, we didn't hang on to all of that.

Then in July, we're comparing against a -- last year we were up about 10% in the month of July on a same-store basis.

So we certainly wouldn't expect to hang on to that same amount this year and we're down this year almost 4% versus being up 10% last year.

So, as you can see, in July we're still hanging on to a lot of the market share we picked up, but those -- that big circumstance really was outside of our control last year.

I understand.

There is some year-over-year differences, it's not like you -- well, actually you are looking at apples to apples (inaudible).

There isn't and one other key thing that I spoke about this a little bit on the first quarter call was we calculate approximately 1% drop just in demand because of weather.

That was across the entire midcontinent here in the second quarter.

We had very, very heavy rains in May and then again in different parts of June.

And that just doesn't come back.

That's probably just a 1% decline in the overall demand.

So, I guess, excluding all of these sort of comparison issues, where would you say we were for July in terms of real demand growth across your system if you normalized for all of these issues, do we see demand actually go down again for general gasoline demand in your overall territories or were we kind of flat?

I would say gasoline demand what has happened is if you compare same period this year versus same period last year, we're up about $0.85 a gallon in retail price, about $2.69 last year in the second quarter, $3.74 this year.

Month to date we're about $3.72.

So I would say gasoline price would have a bigger effect on the overall demand, but to kind of put a barometer on it I would say, Faisel, we're probably down in the 2% to 3% range in overall gasoline demand.

Okay, understood.

And then one question on your -- I heard you guys your earlier comments on the derivative gain.

Is that a cash gain or is there any marked to market impact in those numbers?

Yes, this is Garry Peiffer.

We mark to market everything, every month, every quarter we mark to market all of our derivative activity.

But most of our derivative activity is only a month or two out.

So for the most part, it is cash.

Very little of that $234 million gain relates to activities that will come through in the next month or so.

So the majority -- almost all of that $234 million was cash that from a derivative standpoint we benefited from in the second quarter or that was offsetting negative effects on the commodity side as well.

So it was basically cash for cash in the second quarter, with very little carry-over effect beyond the second quarter.

And I understand the use of derivatives for your foreign crude acquisitions, but you also talked about in your press seasonal inventory price exposure.

How much of that $235 million is related to kind of managing your inventory?

It was about $84 million of that $234 million was inventory-related.

Okay, that makes sense.

Okay, thank you.

I think as you might have heard from Don's discussion when we looked at cash, we have pretty substantial increases in inventories in the second quarter, so we've always taken the approach, much like on the crude acquisition, that we are trying to make our money on the crack, not on changes in the price of the absolute price, so any seasonal changes we have in inventories, we -- the physical inventories, we go short and hedge that as well.

Okay.

So we could see that inventory draw kind of diverse itself at the third and fourth quarter?

Well, to a certain degree the cash effect or the P&L effect has already been reflected for the most part during the quarter.

But a working capital effect, because that was --?

The working capital effect, you're right.

That will show up in the third and fourth quarters.

Okay, great.

Thanks for the time, I appreciate it.

Our next question comes from Jacques Rousseau of RBC Capital Markets.

Just a question on the Detroit refinery upgrade.

You've talked about it being completed in the second half of next year and I'm just wondering with the lag time to receive the Canadian oil at the refinery when do you anticipate this project starting to contribute to earnings?

Well, Jacques, we're about 63% complete, as I've stated earlier, and this is the most important construction season that we're in and I'll be able to give you -- by the time we're together in November and have our big analyst meeting, I think we'll be able to give you a more detailed timeline, because as I've also said earlier, once we complete the actual construction, then we will need to tie in some of the process units and have a turnaround in that facility, but we'll lay it all out in more detail when we get together in November and we really lock in our schedule at that time.

And just one other question.

In terms of the derivative gain, what was the gain or loss in the first quarter of this year?

Okay, in the first quarter of 2011 we had a loss of $57 million.

And just by way of reference, in the second quarter of last year we had a gain of $74 million.

Thank you.

Blake Fernandez of Howard Weil.

Congratulations on the strong results.

Thanks, Blake.

Gary, you covered quite a bit of detail in Doug Terreson's first question on Garyville as far as nameplate capacity.

I was curious, though, on the cost side of things.

As I understand it, there was, I guess, a target to reduce costs by about 20% and I was curious if you can give us a status update there.

Yes, Blake.

And we believe and we're very comfortable that we are right in line with the design we had in reducing our overall fixed cost.

So right in line with our plan.

And, Gary, can you remind me the timeframe of when that's supposed to be accomplished or is there one?

We believe we're already there.

Secondly, you mentioned organic projects.

I'm just curious, now that the Company's been split, obviously you're not competing for capital with the upstream.

Could you give us a sense of maybe some of the smaller organic projects that maybe are on the table that could make their way into the budget?

Yes and I probably would be remiss, Blake, if I didn't really say thank you to Clarence Cazalot for all the tremendous capital that he allowed us to invest in the downstream.

We were to be concurrent.

If you looked at most companies and invest a lot more in our downstream versus others.

But I wouldn't say that -- I would never go out and say that I was starved for capital.

I thought we had plenty of capital to say grace over.

But some things that we have found, been very clear that Garyville is operating significantly above its design capacity.

When that happens, then you're producing a lot more product in certain steps of the process units.

Therefore, you might need some room for in -- as you run those process units.

Which draws me back to the debottlenecking.

So not big projects, but we think something very significant rates of return type projects that we will see down the road, but again, I don't believe that we were ever starved for capital.

No, I would agree, I didn't mean to insinuate that.

I just wanted to confirm that there was some smaller projects that could easily make their way on the books and had a decent rate of return associated with them.

I understand that and that's a very good question.

And it's both at Garyville, we are already seeing a few things in Detroit as what we have learned through the Garyville project already the design that is totally engineered at Garyville and seeing how some of the equipment is operating at Garyville, that we're probably going to have some upside organically there also.

Okay, great.

Thanks a lot.

Ann Kohler of CRT Capital Group.

Couple of questions.

First, going back to growth of the Speedway market.

Could you just provide a little bit more color in terms of what the criteria is that you look for when you look for our retail sites?

And also sort of what level you're looking to get to in terms of the amount of throughput that you have that goes through those sites where you are currently and where you would to get to and any timeframe in terms of what you would like to achieve that objective?

Right, Ann.

Here in the Midwest, eight or nine states that Speedway operates, we're very pleased with the tremendous integration we have between the gasoline volume and the merchandise sales.

But what we're talking about is wanting to branch out and be able to move closer to the either the colonial or plantation system where we can deliver Garyville barrels through our proprietary terminal system that we already have.

We think that gives us a very good fit and we can capture the entire supply chain.

So, in and around the Midwest, where we already operate, we will continue to want to fill out some of our markets where there are new interstate locations or new subdivisions being built, so on, so forth.

But as we move into the southeastern, you recall we used to be in a number of states in the southeast, but we didn't have very strong market share that -- nor did we have the density to be able to really justify any big marketing campaigns.

So as we look going into the southeast, we'll want to be closer to our marketing and terminal systems.

And then just on the -- you mentioned that the capitalized interest that you had this year, I would assume that you would have similar level, maybe a bit higher next year as well as you finish up the Detroit project.

Yes, we -- I guess our interest costs would be roughly, I want to say $40 million a quarter based upon our $3.3 billion of debt and I would anticipate that capitalized interest will consume a major portion of that interest cost on a quarterly basis, Ann.

Great.

Thank you very much.

I appreciate it, gentlemen.

Our next question comes from -- of JPMorgan.

My question's been answered, but thank you very much.

You're welcome.

Ed Westlake of Credit Suisse.

Just a follow-on from your comments on Brent and speculative length.

If you believe that, I guess, speculators are pushing up brent relative to WTI, would you consider locking it in, because, obviously, that would underpin some of the cash flow to meet CapEx, inorganic CapEx and perhaps pay higher dividends.

Well, Ed, historically our shareholders have not been too amused by when we lock things in, either whether we win or we lose when we lock things in.

So, I would say at this time that would not be our plan.

Okay, very clear.

And then just a -- could you give us a rough estimate of where do you think you could get to in midcon crude as a percentage of overall runs from where you are today.

Or is it too early to say?

It is too early, Ed.

I think early on when I answered maybe it was Paul was asking some questions about some of the pipeline ideas.

We have many ideas.

We are working on a number of things, but it is too early to get into those details.

Thank you.

Paul Cheng of Barclays Capital.

Gary, in Robinson in Catlettsburg, do we have any low cost opportunity to follow some small capacity expansion, or with those two pretty much quite (inaudible) and the expense would be very costly?

Paul, this is Garry Peiffer.

Nothing significant at this time.

We are looking primarily at Robinson and all plants, kind of to the last question of ways to run more of the midcontinent crude, so I would say given the man outlook in the Midwest, in particular, our focus is more on lowering our feedstock cost more than increasing capacity at this time.

And how about I think you get a new permit to potentially to have Garyville up to more than 500,000 barrels a day.

Have you have any cost estimate that how much it may take to expand in that fashion?

This is Garry Peiffer, again, Paul.

No, not at this point.

As I think we have said, I think that permit is good for two years and we have to -- and that is a stream day rate as well that we are talking about, the 270s, so we wouldn't expect to be have as a sustainable level.

So, that's what we are going through now.

We are going through the testing, seeing what we can do with the new units and making sure that we can do it safely and we can sustain those rates.

So I guess that is kind of a definitely a work in progress at Garyville at the moment.

Thank you.

We have no further questions in queue.

Thank you.

This is Pam Beal and I just want to thank everybody for joining us today on the call and for your interest in Marathon Petroleum.

If you have any follow up questions, you can reach myself or Beth Hunter and our contact information is either on the website or in the earnings call's press release.

Thanks, everybody.

Have a good afternoon.

Bye -bye.

Thank you, ladies and gentlemen, this concludes today's conference.

Thank you for your participating.

You may now disconnect.