Marathon Petroleum Corp (MPC) 2013 Q1 法說會逐字稿

Welcome to the Marathon Petroleum Corporation first-quarter 2013 earnings conference call.

My name is Christine and I will be your operator for today's call.

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

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

Please note that the conference is being recorded.

I will now turn the call over to Pam Beall, Vice President with Investor Relations.

You may begin.

Christine, I would like for you to make sure that I'm coming through okay, because your initial opening remarks were garbled.

So, can you hear me okay?

I can hear you.

Would you like me to repeat again?

No, but when you speak you are breaking up.

So I just want to make sure that there is a way to make sure that the audience can hear okay and that we will be able to hear them okay as well.

You are coming in clear on my end.

Okay.

All right.

Very good.

Well, we are going to go ahead and proceed then.

Good morning and welcome, everybody, to Marathon Petroleum Corporation's first-quarter 2013 earnings webcast and conference call.

The synchronized slides that accompany this call can be found on our website.

And on the call today, we have Gary Heminger, President and CEO; Garry Peiffer, Executive Vice President of Corporate Planning and Investor and Government Relations; Don Templin, Senior Vice President and Chief Financial Officer; Mike Palmer, Senior Vice President of Supply, Distribution, and Planning; and Rich Bedell, Senior Vice President of Refining.

If you turn to slide 2, please read the Safe Harbor Statement.

It is a reminder that we will be making forward-looking statements during the presentation and during the question-and-answer session.

Our actual results may differ materially from what we expect today and factors that could cause actual results to differ are included here, as well as in our filings with the Securities and Exchange Commission.

And now I will turn the call over to Gary Heminger for some opening remarks.

Thanks, Pam.

And good morning to everyone.

Thank you for joining us.

If you will please turn to slide 3. Our strong financial results this quarter reflect the strategic expansion and optimization of our refining system, favorable market conditions, and increased income from Speedway.

Since the completion of our Detroit Heavy Oil Upgrade Project in November of last year, this project has provided our system with greater flexibility to refine larger volumes of price-advantaged crudes, including Canadian heavy.

The refinery quickly reached its design capacity and performed very well during its first quarter of operations.

Also contributing to our financial performance this quarter was the acquisition of the Galveston Bay refinery on February 1. Results from the first two months of operation have been consistent with our expectations.

Located on the Texas Gulf Coast, our Galveston Bay refinery is well positioned to process growing supplies of North American crude oil.

With expanding access to price-advantaged feedstocks and an array of complex processing units, we are enthusiastic about the prospects of this facility to enhance margins and further leverage dynamic market trends through this strategic acquisition.

We are working hard to integrate this large, very complex refinery and the related assets we acquired into our system, and we are pleased with the enthusiasm and professionalism of the employee team.

Speedway also had a very strong quarter.

It posted increased segment income, primarily due to higher fuel margins and additional revenue from the stores that were acquired last year.

We announced today that we have agreed to sell MPLX an additional 5% interest in Pipe Line Holdings for $100 million.

This transaction, which is expected to close on May 1, will increase MPLX's interest to 56% from the 51% it held since initial public offering in October of 2012.

We believe this dropdown, along with expected throughput increases, positions MPLX to support distribution growth in the near term, and is consistent with our intent to provide an attractive growth profile over the long term.

MPLX also announced today an increase of $0.01 per unit to its quarterly distribution, raising it to $0.2725 cents per unit.

This is the first dropdown following the IPO.

This transaction, along with the increase in its quarterly distribution, demonstrates our commitment to support the growth of MPLX.

We continue to focus on our commitment to balance investments in the business with returning capital to shareholders.

During the first quarter, we returned $547 million to the shareholders through share repurchases and the payment of $116 million in dividends.

As of the end of the quarter, the total remaining share repurchase authorization was $2.2 billion.

And now I will turn the call over to Don Templin to review our financial results for the first quarter.

Thanks, Gary.

Slide 4 provides earnings both on an absolute and per-share basis.

Our first-quarter 2013 earnings of $725 million reflects $129 million increase from the $596 million we earned in the first quarter of 2012.

Earnings per diluted share were $2.17 for the first quarter 2013, compared to $1.70 during the same period last year.

I should note that, as a result of our share repurchases, the weighted-average number of diluted shares outstanding during the 2013 first quarter was 333 million compared to 350 million in the first quarter 2012.

As of March 31, 2013, 327 million common shares were outstanding.

The waterfall chart on slide 5 shows, by segment, the change in earnings from the first quarter of 2012, to the first quarter of 2013.

The primary driver for the change in our earnings was the increase in Refining & Marketing income, partially offset by additional income tax expense.

The improvement in Refining & Marketing segment income was primarily the result of the higher refined product production and sales volumes, attributable in large part to the acquisition of the Galveston Bay refinery on February 1, 2013.

The increase in income tax expense is primarily a function of higher earnings during the first quarter of 2013.

As shown on slide 6, Refining & Marketing segment income from operations was just over $1.1 billion in the first quarter of 2013, compared with $943 million in the first quarter of 2012.

The primary drivers of this increase were the contributions from two months of operating the Galveston Bay refinery, and the first full quarter of upgraded operations at Detroit, partially offset by increased operating expenses or costs.

Utilizing market indicators and actual refinery throughputs, we estimate that the Galveston Bay refinery contributed approximately $150 million of EBITDA for the two months we operated the facility during the quarter.

This income impact is reflected in the changes and market indicators on this slide, and the incremental costs make up a majority of the direct operating cost variance.

In addition to Galveston Bay's success, we estimate the first full quarter of operating the Detroit refinery following the upgrade project contributed approximately $100 million of incremental EBITDA to our quarterly results.

On slide 7, Speedway's income from operations was $67 million in the first quarter of 2013, compared with $50 million in the first quarter of 2012.

Light product and merchandise gross margin combined were about $25 million higher in the first quarter of 2013, compared with the first quarter of 2012.

Light product margins increased by $20 million, as margins averaged $0.1301 per gallon, compared to $0.1096 in the first quarter of 2012.

The Light product margin increase also reflected the impacts of a higher number of stores in the first quarter of 2013, as compared to the same quarter in 2012.

Merchandise margin was $184 million in the first quarter 2013, compared with $179 million in the same period last year.

This $5 million merchandise margin increase was primarily due to an increase in the number of stores compared to the same period last year.

The $8 million increase in expenses also reflects the increase in the number of stores compared to the same quarter last year.

On a same-store basis, gasoline sales volumes increased 0.7% and merchandise sales, excluding cigarettes, increased 0.8% in the first quarter 2013, compared to the 2012 first quarter.

Speedway's average retail gasoline price was $3.47 per gallon during the first quarter of 2013, compared with $3.48 per gallon for the comparable quarter last year.

Slide 8 shows changes in our Pipeline Transportation segment income.

Income from operations was $51 million in the first quarter of 2013, compared with $42 million in the first quarter of 2012.

This increase was primarily attributable to an increase in transportation tariffs and earnings from pipeline affiliates.

Offsetting these increases are higher costs associated with mechanical integrity and depreciation expenses.

Some of the increase in the transportation tariffs was related to the formation of MPLX.

The chart on slide 9 presents the more significant drivers of changes in our cash flow for the first quarter of 2013.

At March 31, 2013, our cash balance was just over $4.7 billion.

Operating cash flow before changes in working capital was a little over $1 billion source of cash.

The working capital benefit of $1 billion noted on the slide primarily relates to an increase in payables that were partially offset by an increase in receivables, both due in large part to the acquisition of the Galveston Bay refinery and related assets.

Payables also increased due to higher crude oil prices at the end of the first quarter 2013, compared to year end.

Excluding the Galveston Bay purchase price, capital expenditures and acquisitions were $197 million during the first quarter.

On February 1, we also made a payment of approximately $1.5 billion to the seller for the Galveston Bay refinery and related assets.

This amount included the purchase price as well as the acquired inventory.

As shown on this slide -- is a $431 million use of cash for the first-quarter share repurchases that Gary mentioned earlier.

Slide 10 shows that, at the end of the first quarter, we had just over $4.7 billion of cash, and approximately $3.4 billion of debt.

With EBITDA of nearly $6.6 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 and continue to focus on capital return to shareholders.

Turning to slide 11, during the last 12 months, we generated $6.2 billion in cash from operations and nearly $3.3 billion of free cash flow.

Over the last 12 months, we returned 42% of our free cash flow to shareholders in the form of dividends and share repurchases.

During the quarter, we purchased approximately 5.1 million shares for $431 million through open market repurchases.

When combined, the dividend payment and share repurchases accounted for 140% of our free cash flow for the first quarter of 2013.

We remain committed to balancing investments in the business with returning capital to shareholders.

Slide 12 provides outlook information on key operating metrics for MPC for the second quarter of 2013.

For comparative purposes, those same metrics for the second quarter 2012 are also shown.

The April market data document will be published tomorrow on our investor website.

I might add, with respect to our outlook information, we received some calls today about our tax rate and we would -- I would suggest using a tax rate of 35% for modeling purposes going forward.

Our mission continues to be value creation for our shareholders.

We are committed to pursuing opportunities to create near- and long-term value.

We will be balanced in our approach to capital allocation as we continue to assess the opportunities in front of us.

Now, I will turn the call back to Pam Beall.

Thanks, Don.

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

And then of course, you may re-prompt for additional questions as time permits.

And with that, we are now going to open the call, Christine, to questions.

(Operator Instructions)

Ed Westlake, Credit Suisse.

Hello, good morning, and congratulations on having DHOUP in Galveston for the first quarter.

Just on Galveston, could you give us an idea of the crude cost in the first quarter, perhaps relative to LLS?

I understand you're still running the old slate and just wondering in terms of progress of switching out imports for domestic crudes and general comments there?

Thank you.

Hello, Ed.

This is Mike Palmer.

Ed, I'm not sure that we can give you the number -- the difference between the crude slate and WTI or LLS -- but I can tell that you if you look at the first quarter, we closed on this transaction in February, and of course, the February supply was arranged by the previous owner during the month of January, so we really have been involved in formulating the crude slates, just during March in that quarter.

When you look at this plant overall, and if you looked in the appendix at the MPC crude slate, you can see that we -- at this plant -- we don't run, at least in the first quarter, quite as much WTI-based crude as we did in the six-plant system.

And of course that will be dictated by the marketplace over time.

The other thing is -- that is important in this plant -- is that we do continue to see value in some foreign sweet cargo crudes, which is related to the aromatics business at the plant.

So again we're working to optimize the crude slate every day and the market will dictate the crudes that we purchase.

But in terms of being able to capture a discounted crude is, there any sense of how many thousand barrels a day you could process at Galveston to take advantage of domestic discounts?

Ed, what I would say is that if you look at the -- where this plant is located, and its access to domestically-produced crudes, what we're starting to see is the pipelines are getting built into the Houston area.

And I'm sure you're aware that the Longhorn Pipeline has just recently begun.

Permian Express will begin shortly.

We're going to continue to have a build-out of pipelines that are going to feed this refinery.

So as domestic crude continues to grow, we expect that we are going to see that crude being run by this plant.

We think it is very well-positioned for that going forward.

Okay.

Thanks, guys.

I will hand over.

I may have other questions later.

Thank you.

Evan Calio, Morgan Stanley.

Good morning, guys.

My question -- my first question -- congrats on the first dropdown to MPLX -- yet I am just trying to understand the sizing and the overall drop-down strategy.

You sold 5% in pipeline holdings for $100 million, but you're still net cash position in MPLX, debt-free, $500 million of credit.

You had assets in the quarter with the Texas City acquisition, so can you just talk me through the strategy on the sizing of the first drop?

And I have a different question, please?

Sure.

This is Garry Peiffer.

We have been consistent both when we did the roadshow before the IPO and since the IPO, that we're looking at this MPLX as a long-term, very transparent, consistent growth type of vehicle here.

And we plan to grow this business both through tariff increases, organic projects that add value and acquisitions, and when we look at the fact that our goal, and it is our strategy to have annual distribution growth in the top quartile of the high-growth, drop-down peers, this is the amount of distribution -- or excuse me, drop -- that we felt we needed to at least from a first drop standpoint, put into the new entity, only six months after we went to an IPO, as well.

So, dependent upon everybody's outlook, a lot of people might have expected us to do the drop a little bit later than six months, but we felt the timing was good to get the first drop done at this point which gives us more earnings power from that drop earlier on in the life of MPLX.

So it is really our goal to achieve this top quartile annual distribution growth that is dictated -- not dictated -- drove us to this type of drop.

Good.

Good way -- you certainly have the assets at the parent level.

Let me ask you a different question, yet related.

I believe you are investing in condensate splitters associated around your Ohio asset in Canton and Catlettsburg to process and provide advantage condensate as it grows from Utica.

Can you provide any details on cost and potential volumes and when you potentially could see those units on stream and also whether you think they're suitable for potentially for MLP?

I will leave it at that?

Well, the last part of your question -- yes, they are suitable.

They qualify for an MLP.

So that's an easy part of the answer.

But what our goal is here is to -- today, we said that at our Canton and Catlettsburg refinery, we believe without any additional investment we can run roughly 20,000 to 30,000 barrels a day in total of condensate at those two facilities.

As the amount of condensate grows there, we want to be in a position to make sure that we can handle more than that amount of volume which we expect to come online maybe in a year or two.

But we are not in the exploration business.

We are just in the refining business.

So we're positioning ourselves with these condensate splitters, which we announced, that when completed, we could go from about 20,000 to 30,000 barrels a day to about 60,000 barrels a day of total condensate throughput.

We have pegged end of 2015, 2016 type of timeframe, for these new units to come online.

That is going to really be driven by how quickly the condensate production ramps up there.

So we are doing the engineering but we haven't finalized exactly when we are going to come online with those new units.

But again, it's -- we will be in position -- that once we exceed that 30,000 barrels a day or so, that we will be in a position to have the condensate splitters there to be able to process the higher volumes.

Great.

And any estimate on cost, as well?

And I will leave it at that?

We've said previously that when you look at all of investments we're making in the Utica -- we're investing in some barges, as you know, we announced that we're signed a letter of intent to convert our Wellsville terminal into a barge loading facility for crude and condensate.

So the whole complement of investments in that area is about $300 million over the next few years is what we're looking at.

So we haven't split that out into particular assets but roughly $300 million over the next two to three years.

Great.

I appreciate it, guys.

Doug Leggate, Bank of America Merrill Lynch.

I'm not sure who wants to take this one, but when (inaudible) was being -- before it came on stream, you had given some indications as to how you expected the contribution to look.

You mentioned the numbers on your prepared remarks.

But I'm just wondering if you can characterize how the project is actually behaving relative to expectations and any differences [in view] going forward and I have a follow-up, please?

This is Gary.

Yes, we had given some earlier indications of $200 million to $350 million.

And we believe after our first quarter of operations that we are right in that sweet spot.

And the plant performed very, very well, as we've stated, in our remarks in the first quarter.

So I would say we're right on target.

Okay, great.

Thanks.

Is there any de-bottlenecking potential down the road, Gary, or is it pretty much running at capacity now?

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

Rich?

Yes, that's right Gary.

Doug, as you know, we've got it up, and it is running very well at design, and as we go forward we're looking at de-bottlenecking opportunities, as we find -- as we gather more information, do more engineering.

So I'm sure, as with any expansions there is going to be some de-bottlenecking in the future.

Got it.

Gary, my follow-up is really, you had been quite vocal about your views on differentials, and obviously, there have been a lot of moving parts this past quarter so I'm just curious if you could bring us up to date with how you're seeing -- what your view of the world is in terms of the sustainability of the Inland versus [international discounts] and perhaps on the heavy outlook as well?

I will be good at that.

Thank you.

All right, thanks, Doug.

And you're right, we have spoken about that a number of times, but let me ask Mike Palmer who runs all of our daily supply operation to give you his view.

Mike?

Okay, yes, thanks, Gary.

Obviously, you have watched the Transatlantic arb -- the difference between Brent and WTI that has come in since early February, from a level around [$22.00] or [$23.00] to around $10 today.

A lot of that -- that we believe was caused by the weakness in Europe, in a very, very heavy turn-around season.

And if you look at the WTI side of the equation, the inventories of Cushing really have not come down.

They are still around 51 million barrels.

But again, I talked earlier, I mentioned a couple of pipelines from the Permian that will direct Permian crude into Houston, so we do think that we're going to see the Cushing inventory start to come down this year.

So what we would say is that with this big move that has taken place, down to just a little bit below $10 on the spread, I don't think we would be at all surprised if that spread would start to move out a little bit again.

I don't think personally that it is going to reach the levels that we saw before, in the $20 level, but to have that arb trade between $10 and $15 would certainly not be a surprise.

That's the confirmation we were looking for.

Thanks, rich.

Appreciate that.

Paul Sankey, Deutsche Bank.

Just as a direct follow-up, you did a nice job there on WTI-Brent.

Could you talk a bit about Heavy versus Lighter crude spreads and also for you guys particularly, the Sweet-Sour ratios, that would be interesting, too?

Thank you.

Yes, this is Mike Palmer.

Probably the most important one to talk about would probably just be the Canadian crude, and if you watch the Heavy Canadian closely, you would have seen an unusual pattern that occurred this year.

We did have the spreads that started to come in, basically in May, to around $15, on Western Canadian Select, and now -- and that really was related to a number of production problems that were occurring in Canada.

Many of those have been resolved.

Production is now increasing.

And you've watched the spread that has started to move apart again, to more what I would call seasonal levels.

When we look at what is happening in Canada, we're still very optimistic.

Exxon is bringing on their Kearl project.

We believe that that crude will start to flow into the marketplace in July.

That will be a very important source of Heavy crude oil for the market.

And in addition to that, if you look at some of the other production for the rest of the year, we think it is very likely that we are going to see Canadian Heavy production increase another 250,000 barrels a day, by the end of 2013.

In addition to the Kearl.

So we continue to be very optimistic about the Heavy Canadian supply.

Great.

And then Sours?

I'm sorry?

Sour crude.

That obviously is a very important differential that we look at for you guys, the Sweet-Sour spread?

And you're thinking in terms of what, LLS-Mars?

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

Again, when you look at the very big picture, certainly one of the things that is going to continue to happen is that in the US, is we're going to continue to see this Light Sweet crude continue to grow.

So I would expect that as we move forward, you're going to continue to see probably the most attractive differentials being in terms of these Light Sweet crudes -- the Bakken, the Eagle Ford, the Utica -- that crude going forward.

But having said that, at the same time, we see very good production growth in the US Gulf of Mexico.

So we would expect to see the Gulf of Mexico being attractive as well.

Yes, the anomalous one would be the premium of LLS that we are seeing.

I'm assume that you are not expecting that to continue as the pipes are developed on the Gulf?

No, we're not.

And actually if you look at it today, we can reconcile Brent -- LLS being $2 to $3 over Brent today.

On the Gulf Coast, there is probably $1 difference in the quality, the value of the two crudes, and in addition to that, it costs $2 to bring a barrel of Brent into the US Gulf Coast.

So with LLS $2 to $3 over Brent, a US Gulf Coast refiner today would probably be indifferent on average.

Everybody is a little different.

But as we move forward and we continue to see the growth in the US domestic shale plays, we would very much expect that LLS will trade at a discount to Brent.

Great.

Thanks a lot.

That counts as four follow-ups.

If I can just throw in one key question, which would be Gary, can you just talk a little bit more about Galveston Bay?

There is an earn out there, but could you also talk about how you feel about the costs and how you can change performance there given that you're now two months in?

Thanks a lot.

And I will leave it there.

I promise.

Thank you.

Well, thanks, Paul.

I was hoping you were going to ask a question about Chicago [difs] instead of Galveston Bay but I will leave that for another time.

Paul, we're very pleased with Galveston Bay on the front end.

We only have two months of operations that were just reported.

The processing kit, we're very pleased with.

We had a turnaround right after we took over the asset, which was planned.

And we came out of that turnaround in very good shape.

But we have a lot of work to do.

And I will say that the employee base that -- in the acquisition -- is very energized, and very pleased to be working with Marathon, and that is -- since we have a very strong base, or employee base, and interest in the plant, that is probably the most important thing.

Now, as we go forward, to go in and get some of the units turned around, over the next couple of years, our plans are such that that will happen, but, you look at the financial performance, $150 million of EBITDA in the first two months, we're very pleased with that.

And we have a very, very strong team that we put in place to operate this plant, and we will perform well there.

Thanks.

Chi Chow, Macquarie Capital.

Thank you.

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

Chi, this is Garry Peiffer.

In the past, we pretty much said and for the time being it is probably reasonable, that it is roughly one-third gasoline, one-third distillate and one-third petrochemicals at the moment.

So intermediates, I mean -- intermediates -- so we are going to continue to optimize that.

And again, we have only been operating in here for a few months so we are trying to see where the sweet spot is for yield and the crude slate.

So that's where we're at, at the moment and it is a little bit less in terms of gasoline yields than our other facilities would be, but that is just the market and the processes that they have in place there at the Galveston Bay refinery.

Okay, thanks, Garry.

On the pet chem side, what type of products are you producing at the plant?

Is it mostly aromatics, or others?

Chi, this is Rich Bedell.

Yes, we have a large aromatics production as well as propylene and so that is primarily benzene, toluene, xylene, and propylene.

Okay.

Great.

Thanks, Rich.

Gary, you talked a little bit, or mentioned Chicago.

I want to ask you about near term here.

There has been certainly a lot of flooding activity in the whole Midwest region.

Can you talk about any impacts to your refineries or your other assets due to flooding and maybe comment on the margin strength there we're seeing?

Well, fortunately, Chi, we have not had any flooding or any problems with our refineries -- Robinson, Detroit, Catlettsburg are running full out.

We have a little bit of a maintenance going on at Canton but it is still running well.

But the -- would you look at what the problems with the river system, being able to get product down the river, due to the flooding, there were possibly some turnarounds from some of our competitors in the Midwest, and those led to very high crack spreads -- they have been in the high teens to low $20s on the Chicago side here for the last couple of weeks.

So we expect, and you look at the pipelines, certainly the market is looking to replenish the inventory when you look at Explorer and some of the other pipelines that are full coming north.

But we have been very fortunate.

We haven't had any problems in our plants.

Good.

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

Yes, sir.

Okay.

Great.

Thanks a lot.

Blake Fernandez, Howard Weil.

I was hoping you could maybe give us an update on the export market.

Obviously, we've seen natural gas prices moving up a bit -- differentials have come in at least at the beginning of 2Q and rumblings of Venezuela are ramping back up.

I was just curious if you could give us a feel for how that arb spread looks.

Yes, Blake, this is Mike Palmer.

Again, if you have looked at the number, you would see that in the first quarter, we did export about 121,000 barrels a day of diesel and about 9,000 barrels a day of gasoline.

And in the fourth quarter, we were just -- we were a little higher than that.

We were about 151,000 barrels a day of diesel.

The market will dictate to us every day how much we actually export.

We're always looking at the trade-off between selling export barrels and selling bulk into the pipelines.

So we're looking at economics every day.

In the first quarter, there were a number of factors that tended to cause a bit of a weakness in the export market.

Certainly, there was Europe.

Europe was fairly weak.

We had more competition in the US Gulf Coast, with Motiva coming on.

And with the weak harbor, New York Harbor, there was competition from the New York Harbor that was a little unusual as well.

And there may have even been some volatility from the uncertainty surrounding RINs.

So it was a little weaker in the first quarter.

We continue to expect that exports are going to be a very important part of our business and we are very positive about exports going forward.

Okay.

Great.

Thank you.

The second question you mentioned Brent and I don't mean to get into the regulatory front too much but I am curious on the earn-out that you have on Texas City.

Can you help me understand, is any potential RINs increase -- is that part of the margin calculation that dictates your payout or does that come in after the fact?

I hope I'm asking that--?

No, Blake, the -- it is at -- based on a gross margin calculation and if you look at the [Askey] index, and Garry Peiffer has the details here.

Yes, it is -- this is Garry Peiffer.

It is just based upon the spot market values for the refined products, so whatever the spot market values are for the refined products, that is what goes into the calculation.

Now to the extent that RINs affects the spot market values, there will be an impact but the actual calculation just based on spot market values for the Askey index as well as for the refined products.

And also, Blake, you need to look at the output, as Garry had mentioned earlier, about one-third of the output is on the petrochemical side and that does not carry a RIN with it.

Yes.

It is not in the calculations.

It is just a three, two, one.

Okay, okay.

Thanks, guys.

Doug Terreson, ISI.

My question is also on Galveston Bay but it is a little bit more broad.

Meaning, a few minutes ago you'd mentioned the opportunity related to advantaged crude oil and it just sounds like you guys are just scratching the surface in that area but there were other categories, too, that were opportunities on this transaction, meaning product logistics and synergies with other Marathon refineries, marketing integration, and some more.

And so I realize it is early but just wanted to see if you can provide any insight or color on the opportunities that may materialize related to that plant thus far?

Sure, Doug.

And our strategy, when we purchased this plant, is that we were not going to purchase just a merchant refinery.

Right.

We picked up 1,200 branded locations -- approximately 1,200 branded locations, four terminals, and Colonial line space.

We have been able to utilize some of our Colonial line space.

So far, three other intrastate pipelines we've picked up.

So all of these things encompass opportunities and synergies.

As Mike mentioned earlier, the month of February, the crude has already been purchased, and we needed that to have a smooth transition.

But as we go forward, certainly we are looking at synergies not only with our current Texas City plant, but other plants and because we have the distribution assets that we can move feedstocks into the Midwest if we need to, or we can move things from our Texas City refinery over to this plant and vice-versa.

The other thing that we are looking at that we think are going to give us some opportunities, we are a very big supplier into the state of Florida and heretofore we had supplied a lot of that out of Garyville.

Well now we can move bigger ships into Florida and pick up synergies from just the efficiency.

And the way, as Mike Palmer was just talking about, exporting into the South America, Latin America markets vis-a-vis Europe, and how we -- the parallels we have out of Garyville, versus Galveston Bay, we have some good logistics that we can pick up there.

So all of those things are in the works right now.

Again, we have only been operating for a few months but we certainly have all those things in our plans.

And how we can pick up some further efficiencies on the way we load ships.

Okay, great, thanks for the color, Gary.

Paul Cheng, Barclays.

I have to apologize, I joined late, so some of the questions that you may already answer.

Gary, have you guys [toward any] financial information in terms of the BP Texas City for two months, what kind of financial contribution that there may have been?

Yes, Paul, this is Don Templin.

We indicated on the call that the estimated incremental EBITDA from Galveston Bay, for the two months was $150 million.

After tax or before tax, Don?

EBITDA.

EBITDA.

Okay.

Don, do you have some [bunch of] data what is the market value in excess of [pope] for your inventory?

$6.1 billion.

$6.1 billion.

And on the working capital, for the quarter, is a positive $1 billion.

Does it relate primarily to the timing of the tax payment or is it something else?

No, it is a combination of a number of things, Paul.

But broadly, our payables are up $2.5 billion and that payable increase is a combination of three things -- a price increase, crude oil prices were higher, at the end of March than they were at the end of the year; and then a volume increase because of Galveston Bay; and then there is also a volume increase because in December, we were heading into a turnaround period and now we are heading out of a turnaround period.

So payables were up about $2.5 billion.

Receivables were up $900 million, primarily related to Galveston Bay.

And then net inventories after the inventories that we acquired -- we acquired about $900 million worth of inventories as part of the Galveston Bay acquisition -- but net inventories were up about $500 million and that was largely related to price changes.

Okay.

Very good.

And Gary, just curious that, with Hess putting up their retail and wholesale terminal business up for sale, [stagistically] speaking, does it fit into your system, or that is, they, really is primarily in the Northeast, and that doesn't really fit to you guys?

Well, Paul, if you look at their terminals, they are not only in the Northeast, they are also in the Southeast, so they're across the entire Eastern seaboard and their retail really encompasses the Eastern seaboard as well.

The only place we would have -- we don't have any direct controlled retail in the Southeast markets today.

We have a large branded presence.

So I would say if there is any overlap, certainly it would be a step-out.

And we're -- I compliment Hess, I think they have very good-looking assets.

Yes.

Okay.

And on earlier, that you probably have already mentioned, on BP Texas City with the crew purchase agreement that is going to be over soon, and you start to utilizing your own trading department get in [North Bend], what kind of potential benefit that we may be seeing?

Will you be able to quantify the amount?

Well, Paul, that agreement was only for one month.

It was just in transition.

They purchased for the month that we were taking over.

So there was no agreement beyond that.

And we're going to be very careful not to get into the types of crudes and stuff that we are going to buy for competitive reasons.

But we are -- Mike and his team are deep into optimizing this plant as we speak.

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

No it is our own, and--

It's your own?

And we started our -- Mike, we started our own in March--?

It would have been March, Gary.

In March.

So we have been -- March, April, already has been our crude purchases.

Okay.

A final question for me.

There's a debate in the industry, at least in the investment community, that butane and naphtha may be increasingly become so abundant that pricing would be very attractive.

So the question is that -- can you blend more of those product into your gasoline crude or that you already max out?

And if the price really become very attractive, what need to be done in order for you to be able to blend more, and that how much more, what is the maximum you can do?

This is Rich Bedell, Paul.

On butane, you're really limited by the gasoline specs on vapor pressure and we already blend up to the max there.

On naphtha, it is just going to be a play between intermediate price or running crude and generating your own naphtha so we will just take a look at that, how it happens.

But can you actually blend more of the naphtha than what you currently already existing in the gas [range polis] that is the question, that's stretching between what you buy from crew and generate your own naphtha, or that you purchase.

I'm talking about on the absolute level, can you blend even more than what you already did to date?

Theoretically, yes, you can do that.

You can -- you have to adjust your octane.

You have to adjust, reoptimize, your plants and that may not be the optimal solution, but we look at those economics all the time and decide how we want to blend and what is optimal.

Yes.

Okay.

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

No, I wouldn't say investment, Paul.

I would say it is optimizing.

If it is the optimal way to blend today, we would be doing that.

So what Rich is saying, is we have some room, it is just every day, we will run our optimization models to determine what is the best.

And Paul, we have got a few more questioners that we would like to get to yet so if you can call back later, if we've got time we would be glad to answer your questions then.

Jeff Dietert, Simmons.

TransCanada recently announced that Keystone XL, the northern leg, has been delayed into the second half of 2015, and I was hoping I could get some commentary from you on how you think that impacts potential logistic?

Does it make rail more attractive?

Would you consider rail at Garyville and Galveston Bay?

And how does that impact your plants upon the pipeline side as well?

Jeff, this is Mike Palmer.

The delay doesn't come as a big surprise to us.

We were expecting that it would be delayed from what they had earlier said.

But the other thing is that you have to also factor in the Enbridge Gulf Coast Access pipeline that should be complete in 2014.

So, as you know, we're already -- there is already the Seaway line that was reversed, from Cushing down to the Gulf and that line is -- the plans are to twin that line, and then Enbridge is going to build another large diameter line that is basically going to twin Spearhead.

So it is not as if there won't be an outlet for significant additional volumes of Canadian crude into the US system.

So -- and when that happens, it will have an impact, certainly on the incremental supply.

It will give the incremental supply out of Canada another home.

There could be some additional railing that occurs as well but that is very expensive.

And I don't see that as a long-term solution for Canadian Heavy crude.

Thanks for your comments on that.

And just quickly, with the Permian pipes coming in and the Seaway volumes that are already there, are you seeing a price differential from Houston versus St.

James for similar quality crudes and how much might that be?

Well the Longhorn pipe just began and the Permian Express is yet to come on so it is not as if we have a lot of pipeline capacity that has come in yet.

But we will always expect that there will be some differential between Houston and St.

James because the crude is being produced in the west, and the transportation cost into Houston is going to be less than it is into St.

James.

And that's going to be several, $2 to $3, depending upon how you move it.

Thanks, Mike.

Faisel Khan, Citigroup.

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

It does not.

Okay.

What would that number be for the quarter?

We don't give that number.

Okay.

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

This is Garry Peiffer.

We really haven't broken it down to that level of detail and it is really changing with valuation -- it is pricing so at this point we just don't break it down to that level of detail.

Okay.

Fair enough.

Thanks.

Robert Kessler, Tudor, Pickering and Holt.

Please go ahead.

Question about your Utica investment plans there and the incremental condensate splitting you've got planned.

Having done the engineering now, presumably you have profiled the yield structure out of a typical barrel of Utica condensate.

Can you give some indication as to what the product mix looks like as have you engineered it?

Say, Robert, we are in the -- won't we say we've ventured near -- the conceptual engineering is complete.

We are just in now to the front-end engineering and we do not have the yield structures and optimizations complete at this time yet.

So it will be a while until we have that finished.

Thanks, Gary.

Can you provide a rough indication of what are you seeing for total Utica volumes right now and maybe some split between crude and condensate?

Yes.

Mike can handle this for you.

Yes, I can give you a little information.

Obviously, the Utica production has come on more slowly than was anticipated.

And we've talked before about our volumes being in the 2,000 to 3,000 barrel a day range.

That's still the case today and it is somewhat volatile.

But the important point with the Utica is that there have been a lot of wells drilled.

The latest numbers that I have is there have been over 600 permits issued, there have been just slightly over 300 wells drilled, and you've only got 89 of those that are producing.

So you've got 70% of the wells that have been drilled and are waiting to get hooked up to gas processing, and that really is the bottleneck right now.

You've got companies out there that are spending billions of dollars on this infrastructure, and we fully expect to see our Utica condensate volumes ramp up significantly this year, and then significantly again in 2014.

So it still looks very optimistic to us.

Thanks for that.

Last one for me, can you provide the average throughput for the quarter, or the two months that you owned Galveston Bay?

No, we can't.

We do not give out individual refinery information.

You did say that it went in to turnaround just after purchase.

Can you give some indication on how many days and what portion of refinery was down for that turnaround?

Rich can handle that here.

It was a section of the residual hydrocracker unit so that was just that portion of it.

And some catalyst [change], as well some hydrotreaters.

Got you.

Thank you very much.

Roger Read, Wells Fargo.

Just to keep on with the Galveston Bay parade here, at the time you acquired this unit, you indicated I believe $700 million to about $1.2 billion in annual EBITDA.

Obviously a good start with the first two months in the first quarter.

I was wondering, with the crude changes, with, I would say overall, the ability to probably run it a little more efficiently than the previous owner, are we thinking the top end of that range now for 2013 and can we think of it as better in '14 again as you pursue the turnarounds and improve efficiencies?

This is Garry Peiffer.

When we gave that preview guidance, we were anticipating some of those things occurring in that guidance so we are still in that same band of EBITDA, and the first two months as suggested puts us right in the middle of those numbers so we still feel comfortable with that range of the guidance that we gave previously.

And Roger, this is Don Templin.

In that range, the price deck that was used, was -- at the top end of the range was $15 or so for the Askey three, two, one, and the bottom end of the range was $11 and we're right in the middle of that.

So from a modeling perspective, that is how you would think about it.

Okay.

And that actually helps me lead into the next question.

Which is, we look at the -- I know there is a lot of talk about the Light-Light spreads here but if we look at the Light-Heavy spreads, we've seen those tighten up quite considerably from the end of last year, into the beginning of the second quarter.

Can you maybe help us understand a little bit how you can move around, which Heavies you are able to use, maybe how much flexibility you have and just a broad sense along the Gulf Coast to counter-act that contracted spread?

Yes, Roger, this is Mike Palmer.

As these spreads move around, Roger, I can tell you that we have almost complete flexibility.

We're very closely watching spreads, for example, between Mars, Poseidon, Southern Green Canyon, the medium Sours as opposed to LLS or Eagle Ford or one of the other Light Sweet grades on the Gulf.

And these volumes are basically all spot.

So from month to month, we -- and not only from month to month, but from day to day, we will back out Sour and bring in Sweet, if that is what the economics say to do, or vice-versa.

So we have tremendous flexibility.

Okay.

But, fair to say that as the spreads have closed overall, that is going to impact -- obviously you picked a better crude in a given day but all in all, we have seen a contraction as we kick off Q2 here and I was just wondering what kind of impact that could have on a broader Gulf Coast refining margin?

Roger, why don't we get back to you and be able to answer that question in more detail.

Pam will call you back to review that, okay?

All right, thank you.

Ed Westlake, Credit Suisse.

I thought this would have been asked already, but just on the RINs, maybe I don't want to get your blood pressure up at the end of the call but what are you doing to reduce exposure and any thoughts about things like using biodiesel to meet ethanol RINs, et cetera, just to limit the potential upside to those costs next year?

Ed, this is Mike Palmer.

Obviously, this has been our mind and not just in the current market but we've been looking at this for obviously the last several years.

And we have made investments within our system to be able to blend as much, not only ethanol, as possible, but also the biodiesel.

So we're in relatively good shape.

Obviously, we still have a purchase requirement for RINs.

But we have got a very good team that is looking at various ways that we can produce RINs outside of the norm.

And that could be in a number of different ways.

So just rest assured that we have a number of things that we are looking at doing that could reduce our RIN exposure, and too early to talk about anything specifically, but we're going to continue to look at that, but--

This is Don Templin.

We did, for the first quarter, we paid about -- or we expensed about $15 million -- or purchased about $15 million of RIN a month.

And last year, the comparable number was about $10 million a month.

Yes, March was probably much higher than the average in the first quarter.

I don't know if you have that number?

We don't give it by month.

I'm sorry, Ed.

Okay.

Thank you.

And this is Garry Peiffer again.

On that Sweet-Sour differential, we have given the sensitivities in the past but now with the more capacity or the bigger capacity with Galveston Bay, every dollar change in that Sweet-Sour differential that we include in our market metrics that we put on our website equates about $225 million of after-tax financial effect to us -- so every dollar has that type of sensitivity feed to our bottom line, $225 million annually per dollar change, after tax.

Paul Sankey, Deutsche Bank.

Yes, I just [further] to the RINs thing, I just wondered how you expect 2014 to play out because obviously it looks like it is going to be a major shortage that gets even worse than 2015?

Well, Paul, I will say it, and it would be very hard to forecast other than if you look at the total math, and reaching the blend wall here in 2013, and not having available the cellulosic option and advanced cellulosic is in question.

Certainly we have had the -- the industry has had several conversations with the EPA and members of the administration to really talk through how to combat this issue.

So I would just say, stay tuned.

The administration and folks in Washington, DC are very cognizant of this problem.

The blend wall came at them much faster than they were expecting.

So we are working this issue hard within the industry, and we will continue to do so.

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

Well, there are two ways that you can handle this.

The first is that the EPA does have a waiver opportunity within their jurisdiction on a year-by-year basis.

So that is something that they certainly could employ if there is a shortage of RINs.

And secondly, you have the legislative piece.

Legislative, obviously, would take longer than the waiver option but we're working both sides very hard, Paul.

Thank you.

We have no further questions.

I will now turn the call back over to Pam Beall.

Thank you, Christine.

And thanks to everybody for joining us today.

And for your interest in marathon petroleum.

And should you have additional questions, Beth Hunter and I will be in the office today to take your calls so thanks again.

Thank you, ladies and gentlemen.

This concludes today's conference.

Thank you for participating.

You may now disconnect.