Marathon Petroleum Corp (MPC) 2013 Q4 法說會逐字稿

Welcome to the Marathon Petroleum fourth quarter and full year 2013 earnings conference call.

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

(Operator Instructions)

Please note that this conference is being recorded.

I will now turn the call over to Mr. Tim Griffith.

You may begin.

Okay, thank you, Christine, and good morning.

I'll remind everyone that the synchronized slides that accompany this call can be found on our website at marathonpetroleum.com under the Investor Center tab.

On the call this morning are Gary Heminger, President and CEO; Don Templin, Senior Vice President and CFO; Mike Palmer, Senior Vice President of Supply, Distribution and Planning; and Pam Beall, Senior Vice President of Corporate Planning and Governance and Public Affairs, and President of MPLX.

We invite you to read the Safe Harbor Statement on slide 2. It's a reminder that we will be making forward-looking statements during the presentation, and during the question and answer session.

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

Now we'll turn the call over to Gary Heminger for open remarks and highlights.

Thank you, Tim, and good morning.

I want to thank you for joining our call and webcast.

Before I give my comments on our results, I wanted to mention a few changes we have made as a result of Garry Peiffer's retirement in December.

Pam Beall, who many of you have come to know in her prior role as Vice President of Investor Relations, has taken executive responsibility for Corporate Planning, which encompasses Business Development, Economics, and Global Procurement, as well as she becoming President of MPLX.

Tim Griffith, who just introduced me and will be hosting our call, has added Investor Relations to his current responsibilities as Vice President of Finance and Treasurer.

Beth Hunter has been promoted to Director of Investor Relations supporting Tim, and will serve as the day-to-day contact for investors and analysts with help from Geri Ewing.

This is a strong team and demonstrates the importance we place on continued succession planning, growing MPLX, and maintaining a robust dialogue with our shareholders and the investment community.

We'll be making the appropriate personal introductions, as the opportunities present themselves over the next several months.

Now moving on to our highlights.

The fourth quarter of 2013 was a strong finish to an excellent year for MPC.

Operating performance was outstanding, and our financial performance in the fourth quarter reflected a nice rebound from some of the challenging market conditions we faced in the third quarter.

Speedway also had an excellent year, with record annual earnings and operational excellence throughout our nearly 1,500 locations.

Don will provide a little deeper look at the drivers to our financial performance in the fourth quarter and full year shortly.

Importantly, our focus continues to be on the future and balancing value accretive investments, with a commitment to return capital to shareholders over an extended period of time.

The acquisition of the Galveston Bay Refinery in February was an attractive addition to our refining portfolio, and we have been pleased with the developments there in our first 11 months of ownership.

As we continue to evaluate the asset configuration and leverage the talents of the skilled workforce who have joined the Marathon Petroleum team, we believe this facility will become our second powerhouse refinery on the Gulf Coast, further enhancing the operational and logistical flexibility within our system.

As part of our Investor Day in December, we highlighted the focus we have on expanding the higher-valued and more stable cash flow businesses in our portfolio.

Our recently announced planned equity investments in the Southern Access Extension and Sand Piper Pipeline projects are two examples of that focus.

The committed space and equity options we have in these pipelines will enable us to participate in the movement of increasing amounts of North American crude into our Midwest refining region through our Patoka hub, as well as introduce another potential earnings stream to MPLX over time.

We are moving aggressively toward expanding our retail footprint through investments in Speedway, and continued efforts to convert the branded contract assignments we acquired as part of the Galveston Bay acquisition to the Marathon brand.

As we highlighted in December, we have almost tripled the amount of capital invested per year in rebuilds and new locations, and our Speedway business over the previous five-year period.

This includes expansion into attractive contiguous markets in Western Pennsylvania and Tennessee, where we opened our first Speedway locations in 2013 and are planning to expand further.

We also remain mindful of opportunities to enhance margins and optimize the configuration of the other six refineries in our system.

Among many of the opportunities we are evaluating, is a resid hydrocracker at our Garyville refinery.

If we decide to move forward after the front-end engineering and design study we are conducting this year, this investment will give us the opportunity to upgrade resid, a refinery by-product of decreasing value, into ultra low sulfur diesel using hydrogen produced by our low-cost natural gas.

Once operational, such a hydrocracker could add approximately $1 billion of annual EBITDA to our earnings base.

An additional benefit is that nearly 70% of the resid will come from our own refining system.

We will continue to invest in our future, while maintaining our commitment to capital discipline, and focused return of capital to our shareholders throughout the refining cycle.

Combining dividends and share repurchases, we returned $3.3 billion in capital to shareholders in 2013, which represented almost six times the free cash flow we generated over that same time period.

It is worth noting that we have completed about 70% of the $6 billion of share repurchases our Board has authorized since the spin in 2011.

To date, this activity represents 18% of the shares outstanding at that time.

Our shareholders have been rewarded by our focus on value creation, enjoying total returns of 48% in calendar 2013.

The performance places MPC in the top third of the S&P 500 firms in total returns, and follows a very strong 2012 total return of 94%.

Our mission continues to be long-term value creation for our shareholders.

And although we believe the market has not reflected the full value of our business in our valuation, we remain relentlessly focused on driving that value.

We believe our best days are still in front of us.

With that, I'll ask Don to provide a little deeper dive on our results for the fourth quarter and financial performance for the full year.

Don?

Thanks, Gary.

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

Our fourth-quarter and full-year 2013 financial performance was strong.

MPC had adjusted earnings of $633 million, or $2.10 per diluted share, during the fourth quarter of 2013 compared to $760 million, or $2.26 per diluted share, in the fourth quarter of 2012.

For the full year 2013, our adjusted earnings were nearly $2.2 billion, compared to a very strong $3.4 billion in 2012.

Adjusted earnings-per-share was $6.84 for the full year 2013, compared to $9.79 for 2012.

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

The primary driver for the change was the decrease in refining and marketing segment income, which I will describe in more detail on the next slide.

As shown on slide 6, refining and marketing segment income from operations was $971 million in the fourth quarter of 2013, compared with $1.1 billion in the fourth quarter of 2012.

The change from 2012 was primarily due to narrowing crude oil differentials and higher direct operating costs, partially offset by wider crack spreads, higher product price realizations, and increased refinery throughput volume.

The unfavorable earnings impacts associated with the narrowing crude oil differentials are found in the price columns for the sweet/sour differential and LLS to WTI differential.

The increase in direct operating costs quarter over quarter is primarily due to the acquisition of the Galveston Bay refinery and higher turnaround expenses, and is consistent with the guidance we've previously provided.

Our earnings were favorably impacted by wider crack spreads, as shown in the LLS 6-3-2-1 crack price column.

All of the gross margin indicators utilized spot market values, and an estimated mix of crude purchases and products sold.

As a result, differences in our actual product price realizations mix and crude costs quarter to quarter, are reflected in the other gross margin column.

So let me make a few comments about a couple of these items.

First, our actual crude and feedstock acquisition costs compared to the market indicators were more favorable during the fourth quarter of this year than the fourth quarter of last year.

Second, our product price realizations were more favorable in the 2013 fourth quarter than they were in the comparable period last year, primarily due to overall higher margin and the mix and volume of products sold.

During the 2013 fourth quarter, our earnings were also favorably impacted by increased refinery throughput volumes, due in large part to the acquisition of the Galveston Bay Refinery.

These impacts can be found in the volume columns for the LLS 6321 crack, the sweet/sour differential, and the LLS to WTI differential.

Slide 7 provides a similar earnings walk for the refining and marketing segment on a year-over-year basis.

As you will see from the graph, the blended 6-3-2-1 crack spread had a slightly favorable impact on earnings, while the primary driver of the unfavorable variance was narrower crude oil differentials.

The change in crude oil differentials from 2013 compared to 2012 is found in the market indicator columns labeled sweet/sour differential price, WTI to LLS differential price, and the LLS prompt versus delivered.

Direct operating expenses were higher by $1.6 billion, primarily due to the acquisition of the Galveston Bay Refinery and higher turnaround expenses in 2013.

The primary favorable earnings impacts shown are associated with increased volumes, due in large part to the acquisition of the Galveston Bay Refinery.

On the next few slides, we provide earnings walks for each of our other operating segments.

Speedway's income from operations was $83 million in the fourth quarter of 2013, compared with $77 million in the fourth quarter of 2012.

Light product gross margin was about $4 million lower in the fourth quarter of 2013 compared with the fourth quarter of 2012.

The decrease was primarily due to a $0.01 per gallon lower gross margin.

This, however, was more than offset by merchandise margin, which was $205 million in the fourth quarter 2013 compared with $196 million in the same period last year.

This $9 million increase was primarily due to higher merchandise sales and margin.

On a same-store basis, gasoline sales volumes increased 0.2%, and merchandise sales, excluding cigarettes, increased 5.6% in the fourth quarter 2013 compared with the 2012 fourth quarter.

Speedway's average retail gasoline price was $3.14 per gallon during the fourth quarter of 2013, compared with $3.32 per gallon for the comparable quarter last year.

In January 2014, we've seen a slight decrease in demand with an approximately 1.5% decrease in same-store gasoline sales volumes versus the prior year.

This is primarily due to the extreme weather conditions that we've seen through most of the Midwest during the month.

Speedway's income from operations for all of 2013 was $375 million compared with $310 million for 2012.

Light product margins increased by $54 million, as margins averaged $0.144 per gallon in 2013, about $0.01 higher than the 2012 average of $0.132 cents.

On a same-store basis, gasoline sales volumes increased 0.5% in 2013 compared to 2012.

Merchandise margins were $825 million in 2013 compared to $795 million in 2012, for an increase of $30 million.

The increase in light product and merchandise margins were partially offset by increased expenses of $19 million, primarily due to an increase in the number of stores operated in 2013 as compared to 2012.

Slide 9 shows fourth-quarter and full-year changes in our pipeline transportation segment.

Income from operations was $47 million in the fourth quarter of 2013, compared with $72 million in the fourth quarter of 2012.

This decrease was primarily attributable to a decrease in earnings from pipeline affiliates and higher operating costs.

The decrease in earnings from pipeline affiliates is primarily from our investments in LOOP, Explorer, and the Centennial Pipeline.

2013 income from operations was $210 million, compared with $216 million in 2012.

This reduction is primarily attributable to higher operating expenses and depreciation, and a reduction in pipeline affiliate income, partially offset by higher transportation revenue in 2013.

The higher operating expenses and the higher transportation revenue primarily relate to the formation of MPLX.

Slide 10 presents the significant drivers of changes in our cash flow for the fourth quarter of 2013.

At December 31, 2013, our cash balance was $2.3 billion.

Operating cash flow, before changes in working capital, was up $827 million source of cash.

The working capital benefit of $528 million noted on the slide primarily relates to a reduction in our inventory levels at year-end.

As Gary highlighted earlier, we continued delivering on our commitment to return capital to shareholders, with $452 million of share repurchases in the fourth quarter.

Slide 11 shows that at the end of the fourth quarter, we had $2.3 billion of cash and approximately $3.4 billion of debt.

With EBITDA of over $4.6 billion during the last 12 months, we continue to be in a very manageable debt position, with leverage of 0.7 times EBITDA and a debt to total capital ratio of 23%.

Turning to Slide 12.

During the last 12 months, we generated $3.4 billion in cash from operations and $560 million of free cash flow.

Over this period, we've returned almost $3.3 billion to shareholders through dividends and share repurchases.

This was almost six times our free cash flow over that period.

During the fourth quarter 2013, we purchased approximately 6 million shares for $452 million through open-market purchases.

It is our intention to continue returning capital to our shareholders that is not currently needed to support the operational and investment needs of the business.

There is $1.86 billion outstanding on our share repurchase authorization as of December 31, 2013.

MPC leads its peer group in 2013 on the measure of total capital return yield, with 14.4% for the year.

And we intend to remain focused around our efforts to balance careful investment in the business with returning capital to shareholders.

Slide 13 provides updated outlook information on key operating metrics for MPC for the first quarter of 2014.

For comparative purposes, those same metrics for the first quarter 2013 are also shown.

Consistent with our commitment to provide incremental information, the outlook data is presented in a regional format, with key statistics provided for our Gulf Coast and Midwest regions.

Historical information by region for 2013 can be found on our website in the Quarterly Investor packet, the Regional Data tab, and I want to highlight that this regional break out is also provided in our Earnings Release.

You will also note that we modified our gross margin calculation to be more consistent with the gross margin information provided by several of our peers.

Now, I will turn the call back over to Tim Griffith.

Thank you, Don.

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

You may reprompt for additional questions as time permits.

With that, Christine, we're prepared to open up the call for questions.

(Operator Instructions)

Our first question comes from Arjun Murti from Goldman Sachs.

Thank you.

And first of all, thanks for the additional break down between the Gulf Coast and Midwest, which is helpful.

My question, Gary, is there's obviously a lot of questions right now with the growing light sweet shale oil production, where you can stick all of it in terms of the US refining system.

And you all highlight for example, in your disclosure, 65% of your Gulf Coast throughput is sour crude oil.

Can you provide any color in terms of, if the price incentives were there, how much light sweet could you run?

I know there are various limitations, but where you desire to run it, can you provide any color on how flexible your system is?

Sure, Arjun.

I'm going to turn this over to Mike Palmer.

Let me give you one statistic before Mike talks though.

In the fourth quarter and year to date, we ran approximately 53% sour for the entire year, and almost the same amount in the fourth quarter.

So while there's a significant amount of light sweet is available, the economics versus the alternative barrel still guide us to run the light sour and medium sours.

While we can run about 65% of our entire slate, that's not just the Gulf Coast, the entire slate we can run about 65% in light sweet.

It illustrates we ran around 53% sour that the economics still drive us towards that decision.

But, Mike, if you can add some additional color.

Yes, Arjun, I guess probably what I'd have to say is that the amount of light sweet crude that we can actually run in the Gulf Coast, or at any plant, is really a function of the price.

It's a function of the discount relative to our alternatives, and we really can't give you a specific number.

What I can tell you is, that we know that within our system, we know that we still have some logistical constraints for example, that keep us from running as much light sweet as we would like to at certain times when a differential gets really wide.

We're working to get rid of those constraints.

We're also going to be taking on additional barging as we go forward, because we think that will help alleviate some of the constraints.

At the refineries, it's really a function of the price.

So the object that we always have is to maximize our profitability.

As that light discount widens, we can run more light sweet crude at these refineries, and that's what we'll do.

One of the real issues is how do you handle the naptha, and I think you know that in our refineries we're in pretty good shape from a reformer standpoint relative to the industry average.

So that's about as good as I can do for you, Arjun.

We will take advantage of light sweet crude, depending upon what that differential is.

Arjun, let me add one more thing.

I read the piece that was published this morning by you on the volatility of the crude and the light sweet and the saturation, and I thought you were spot on that we're going to continue to have tremendous amount of volatility.

But one thing I want to really put out in more detail was that, if you look at the end of the fourth quarter with the extreme weather conditions that we've had across the US and a number of issues in the Gulf Coast, there's been more volatility and a pull on inventory.

I'm sure you know that there was a major pipeline in the Gulf offshore, the Gulf Coast, that was down due to some operating issues, which took some light sour off the market, then it was going to be blended with some of the light sweet.

And that really upset some of the inventory, and there's been a big draw of inventory in the Gulf Coast and up into the Cushing area.

So, I think this is a temporary aberration in the crude market.

But again, I think your presentation that you published this morning was spot on with the volatility.

Once we get through these reports or get through this inventory cycle, I would expect things to settle down and for that spread to widen back out.

Gary, that's very helpful, and I appreciate that, and thank you, Mike, as well.

Just a very quick follow-up, Gary.

You gave the $1 billion dollars of potential EBITDA in the resid hydrocracker.

Did you give a volume throughput and order of magnitude CapEx that goes with that as well?

Yes.

The CapEx that we gave was $2.2 billion, was our estimate, and that's what the feed is going to confirm and verify that number that we expect the feed to be done by the end of the year.

Timing wise, we would expect if we were to go forward with this project to be complete at the end of 2017, mechanically complete there, and start up the first part of 2018.

And as it increases ultra low sulfur diesel by 28,000-barrels per day.

And I said earlier, about 70% of the resid comes from within our own system today.

So we're confident already with the feedstock supply, it's verifying and confirming the capital that it will take to build this.

That's great.

Thank you so much.

Thank you.

Our next question comes from Ed Westlake from Credit Suisse.

Please go ahead.

Hello, Ed.

Ed, if you had muted your phone please unmute it.

Good morning.

So I was just trying to get a sense of in the fourth quarter versus the third quarter, obviously there's a lot of changes in terms of the profitability.

Now when we think about it, there's crude discounts, there's butane blending in the fourth quarter, there's losses on secondary products.

Maybe give us some color as to which one of those factors you felt was the biggest quarter over quarter.

Thanks.

Yes, I guess, Ed, if you noticed on our slide 6 where we showed that other gross margin, and there's a big $540 million of gross margin.

Broadly, I would say, about 45% of that impact was favorable crude acquisition costs, and about 75% of that amount was favorable crude acquisition costs and refined product realization, and purchase for resale.

So 75% of that $540 million was explained by those three factors.

Yes, and some other companies have been saying that in the Winter period they were able to beat the cracks in the Gulf by doing more exports.

Is that explaining the 30%?

Well we had a very strong export quarter.

We averaged, I think, 298,000 barrels a day for the quarter, the fourth quarter.

So, that was spread between Galveston Bay and the Garyville refinery.

Right.

And final question, just more strategically, just on light crude runs.

Maybe just remind us, if you can or are willing to, about the changes that you're making perhaps at the plant level to process more light crude.

Any additional thoughts in terms of adding things like pre-flash towers and splitters over and above the plans that you've already announced?

Well, Ed, let me take you back.

When we first built the Garyville expansion that opened at the end of 2009, our intent was to run that at about 180,000 barrels per day.

And as you'll recall, we're running this about 110,000 barrels a day above what the design capacity.

And the reason is, we filled up all of the downstream process units from heavy and light sour to medium sour crudes that we're running, and we still have this amount of run space in the crude unit.

So, we have a 110,000 barrel a day basically free crude system to run.

Beyond that, as we said, we're becoming the anchor shipper on the Sand Piper and SAX line.

We're doing crude unit work at Robinson this year.

We're building the condensate splitters at Canton and Catlettsburg.

And then we're working on logistical constraints in the US Gulf Coast, as well as expanding our barging flexibility.

So we have a number of things, and this is top of our mind on how to be able to take advantage of the light sweet crude.

Okay.

Thanks very much, Gary.

Thank you.

Our next question comes from Chi Chow from Macquarie Capital.

Please go ahead.

Great, thank you.

Want to follow-up to your answer on Arjun's question earlier.

You seem to suggest that you didn't really change the percentage of sour crude runs in the fourth quarter.

I'm just wondering if you can comment on the pricing dynamic you saw on the sour and medium crudes in the quarter?

I'm assuming that they were just discounted along with what we saw on the LLS Brent spread, but any comments on how the pricing dynamic worked on those crudes?

Yes, Chi, this is Mike Palmer.

Hello, Mike.

When we look at the fourth quarter, the pricing dynamics for domestic crude were very favorable.

Of course, that was a period when the Brent WTI spread was widening out.

The domestic crudes, LLS, and Mars were both priced very attractively relative to the arb, and that's one of the keys to the profitability in the fourth quarter.

Domestic crudes were a discount that made a lot of sense.

Actually, when you look at LLS versus Mars over the fourth quarter, it didn't vary all that much.

It was between $4.50 and $5.50 generally.

And then when you look to the really heavy barrels in Canada, they were very attractively priced as well.

Getting probably between $25 and $35 a barrel discount.

So, I think what I would say for the fourth quarter again, is just domestic crudes were very well priced for our system.

Mike, how about the foreign crudes?

I know you still bring in foreign mediums in particular into the Gulf.

Were those pricing right along with Mars?

Yes.

The foreign crudes that we bring in were attractive relative to the sour alternative in the Gulf.

Okay.

I guess that suggests that both Mars and the foreign barrels that they're moving with LLS then.

And is that dynamic going to continue long term in your view, that these crudes seem like they're going to be priced off where LLS moves?

Yes, I think going back to the basic dynamic, we're going to have this continued production growth in the light sweet crude that's going to end up on the Gulf Coast.

But I think, as we've said before, that other barrels, the other sour barrels, if they want to find a place in the refineries they're going to have to compete.

So there's going to be changes in differentials, don't get me wrong, but these other sour barrels are going to have to compete as well, and we believe they will.

Great, thanks.

Appreciate that.

Then one final question in your guidance first quarter.

Thanks for breaking out the expense per barrel by region.

I'm just wondering, with the turnaround expense, it looks pretty high in both regions.

Are the turnarounds going to be concentrated here in the first quarter, or can you say what might be ahead for the rest of the year?

Sure, Chi, this is Don.

Yes, we'll have a very heavy turnaround activity in the first quarter compared to probably all of the other quarters.

But we will, when we have big turnarounds coming up, we will continue to incorporate that in our outlook guidance with enough time period for you all to be able to model that.

And, Chi, you'll recall at our Analyst Day meeting, we spoke about Galveston Bay.

And I think the quote I used was we need one more year of -- so to be able to really get with the turnarounds to be able to get this plant like we want it.

And so you'll see that turnaround expense, part of it as around that plant, but our strategy and the plant is performing very well.

Our strategy is to go in and get this plant tuned up like we want it to be, and we would expect by the end of this year to have a majority of the heavy turnaround complete at that plant.

And as I said, this becomes the second powerhouse refinery we have in the Gulf.

Excellent.

Great, thanks Gary.

Appreciate it.

Thank you.

Our next question comes from Robert Kessler from Tudor, Pickering, Holt.

Please go ahead.

Hello, Robert?

Robert?

Hello, can you hear me?

There we go.

Sorry about that.

My question is somewhat related to Chi's, and the North America pricing dynamics for the mediums and heavys.

You had some comments about the fourth quarter.

I'm interested the first quarter, what you're seeing today.

A couple things peaked my interest.

One is, more pipeline capacity, I'd say heavy pipeline capacity, now coming down to the Gulf Coast with market link switching to heavy barrels.

It seems to have helped narrow the Canadian differential, and presumably put more heavy barrels in the Gulf Coast region on the market.

What are you seeing in the first quarter as it relates to the availability and pricing structure for those heavy barrels?

And then somewhat related to that, the imported heavy.

Say, Saudi's and others coming in with mediums or heavys.

The Saudis appear to have narrowed their price discount versus ASCI, albeit very slightly, to say $0.80 for February versus $1.90 in December.

Are they effectively pulling out of the market very slightly, and is that price change in the posted prices matched with any noticeable change in your commercial discussions with them?

Hello, Robert, this is Mike Palmer.

If you come back to your first question relating to the heavy crude, as you know, the trans Canada market linked line did come on stream here in January.

And right now, it's primarily the light sweet line fill I think that's moving to Houston.

But we do understand that that will be followed by heavy crude, more than likely.

We had already seen the Canadian heavy.

And if you look at the benchmark, Western Canadian Select, we'd already seen that differential that had been as high as $35, $36 earlier come into around minus $20 to minus $18.

And it looks -- if you look at the forward curve, it appears to be fairly stable at that kind of a level.

I think that part of what was happening there, even though there continues to be growth in the Canadian heavy, as you know, the BP Whiting facility did get its Coker project complete.

And there was an additional demand in the market for the Canadian heavy.

But I think as we look forward, we would expect that Canadian heavy to be still an important crude.

It will still be attractive, although we might not see the very wide differentials that we've seen in the past, once you have that ability to clear it into the Gulf Coast.

So I guess that's the situation that we see for the heavy crude.

In terms of Middle Eastern crudes, I would, certainly from our standpoint, that continues to be a very important part of our crude slate, and we don't have any reason to believe that it's not going to be competitive going out in the future.

We would expect to see the barrels and the same basic pricing relationship that we've seen in the recent past.

Okay, can I ask for some clarification?

You mentioned alleviating some logistical bottlenecks in the Gulf Coast region relating to crude access.

Can you specify what those are?

You also mentioned some more barge capacity, it sounded like.

Are those related?

Is that Gulf Coast region barge purchases, or something like that?

Yes, I can't give you a lot of detail, but let me just give you my thoughts.

We know -- when these pipelines get built, and Seaway was a good example, the trans Canada market link is another good example.

You get a trunk line that completes.

And you've got trunk line capacity, but you don't have necessarily all the connectivity that you need for all the different plans that have a potential requirement for those crudes.

And that sort of thing continues in the marketplace, where you get basic pipeline capacity, but you don't have all of the connectivity you need to bring all those barrels in.

And every refiner has to look at their own specific logistics to see where the constraints are, if any, and then to correct those.

So while I'm not going to get into detail, I can tell you that within our own system, we know that we continue to have these various constraints around the system.

And we're constantly working on those to try and remove those constraints to bring in more crude.

And we believe that most other refiners have the same sorts of issues.

That's why you see, when you look at exports that continue to rise, you look at the various -- and we talk about the fact that we're not saturated with light sweet, that's what our engineers do every day is to find ways to alleviate these bottlenecks to continue to increase when the price signals are there.

So does that answer your question?

That's helpful.

And just a quick one from me on the new regional disclosure.

Did I miss it, and do you intend to break out the gross margin as well in addition to the cost by region?

No, we don't intend to break out the gross margin.

We intended to provide operating data that allowed people to model that.

Okay, thank you.

Thank you.

Our next question comes from Jeff Dietert from Simmons & Company.

Please go ahead.

Good morning.

Marathon has been a -- can you hear me okay?

Yes, Jeff.

Marathon has been a leader in condensate splitters and activity in the Utica, but condensate is a big issue in the Eagle Ford, and we're hearing condensate volumes were rising in the Permian, as well.

Could you talk about the condensate supply opportunities on the Gulf Coast?

Is condensate an even bigger challenge than light crudes within the Gulf Coast market?

Is it tougher to blend?

Talk a little bit about the condensate market on the Gulf Coast, and how you see that evolving.

Jeff, this is Gary.

In fact, we look at condensate as an opportunity, not necessarily a challenge.

And we agree that there's going to be a tremendous amount of condensate.

There are already a number of projects in position, we're not going to get out ahead of ourselves here and give away some of our competitive thoughts

But we certainly are looking at some opportunities in and around the Gulf Coast, as well.

Today, we can blend some of that condensate into our system, of course some of the condensate that's looked at as diluent to move up into Canada to bring the heavy barrel down.

But we are looking more at the opportunities we have to be able to bring that condensate into our system, along with the Utica condensate that we've already announced.

Mike anymore color on that?

No, Gary.

I think you've answered the question.

Obviously, we watch very closely the production growth that's coming from all the shale plays, and we understand and recognize that there's significant condensate.

And we're looking at various ways to handle that condensate, including projects.

And timeline kind of 2016 type in service date about as quickly as you could react?

Here are two splitters in Utica are one at the end of 2014, one mid 2015.

And then if you want to look at something ground up in the Gulf Coast, I would say your timing is pretty close.

In the 2016 time frame.

Great, and secondly, your 290,000 barrels a day of product exports are ahead of your expected capacity that you presented at the Analyst Day.

Can you talk about some of your success in growing that export capacity more rapidly than anticipated?

Yes, Jeff.

The market continues to be very robust, without a doubt.

And it's very interesting.

It kind of comes back to what I was talking about when we think about how much light sweet can we actually refine.

We're well above what we thought the limits were going to be in terms of our dock facilities to export finished products.

But when the opportunity presents itself and the economics work, that's one of the things that we're really good at is we're really good at getting around constraints and debottlenecking.

And that's exactly what we've done.

And it's not only hardware, but it's the way that we schedule.

It's being able to move certain products away from docks to other means of moving that product out so that we can make room for exports.

It's all kinds of things that we do to maximize our profitability.

And, as I say, that's really what we do.

Thank you.

Thank you.

Our next question comes from Doug Leggate from BanK of America.

Please go ahead.

Hello, guys, it's actually Jason Smith on for Doug.

Congrats on a great quarter, and thanks again for all the incremental disclosure.

I'm just curious, so we spent a lot of time on crude discounts.

But just on the product side, as a country we're now exporting as much gasoline as we're importing, and you guys are obviously a part of that.

So what do you guys see as the impact on the US as it being balanced on the gasoline price?

Do you think we continue to price off Brent, or do you think we eventually will price off of domestic crudes?

Well I would think for the near future, that we'll continue to price off of Brent.

Because if you look at -- it's not necessarily gasoline and you look at the entire pool, we're exporting more diesel.

But in order to be able to get that diesel, gasoline is going to follow along and diesel is being priced off of the Brent market.

So we would expect for quite some time that we'll continue to be priced off of the Brent market.

Okay, thanks.

And just a quick follow-up, Gary, just on the quarter, I think Garyville was down for a bit in the quarter.

Could you just maybe quantify the lost opportunity costs there?

We do not give that information out, Jason.

But it just went down for some turnaround work, which is typical at the end.

In the fourth quarter early first quarter, that's a good time to be doing turnaround work at Garyville.

But, Jason, this is Don.

Our guidance around throughput would have contemplated the Garyville refinery and any activity that was planned.

Oh, yes sorry.

Yes, I meant more just on the margin side, any lost opportunity cost.

Yes, we do not give that information out.

We think that's too competitive.

And if I could just sneak one more quick one in.

In terms of the export debate within the country, and it's obviously picked up a little bit.

What are you guys hearing now in terms of the potential to export crude at this point?

Well, in fact, I've spoken at a couple conferences, and that was a theme at both conferences earlier in January.

We do not oppose export.

We support free markets, and we are not in the camp of any government mandates.

However, I think as this thing continues to evolve, this discussion continues to evolve, you're going to see it's going to turn into a very comprehensive discussion.

It needs to consider when you consider it crude exports.

It needs to consider the Jones Act, because the Jones Act is a restriction on moving both crude oil and refined product in the US today.

You need to consider a renewable fuel standard, which is a restriction on moving refined products in the market today.

You need to consider the restrictions on pipeline permits, not only the one that has been in the news for a long time around Keystone, but other pipelines that are being considered in and around the US.

And then just lately, you have some of the very serious rail incidents that have happened.

So I think all that is going to need to be taken into context into a comprehensive discussion, Jason, and I think that it will take a long time to have this debate in DC.

Appreciate the thoughts, Gary.

Thanks.

Thank you.

Our next question comes from Blake Fernandez from Howard Weil.

Hello folks, good morning.

Gary, you've already answered one of my questions on the resid hydrocracker as far as reaching FID potentially by year end.

I wanted to confirm that the CapEx budget of the $2.47 billion does not include any spending for that project?

The current year's budget includes the capital for the engineering work that's being done this year, but it does not include any construction costs or anything like that.

So, Don, just to be clear, if it were approved let's say before year end, is there a chance that that budget could nudge up just a tad?

I don't believe so.

If we decided to go forward, we wouldn't be in the field for construction until 2015, and the early part of construction will be all land piling and so on and so forth.

So you wouldn't really ramp up till mid 2015 into 2016.

Okay, got it.

Thanks.

The second question, if we could move away from refining a bit.

On Speedway, if I'm looking at your supplemental trying to get a sense of free cash flow, it looks like you were free cash flow negative in 2012, and then you moved to a positive position in 2013.

And then looking at your CapEx budget for 2014, at least by our numbers, it looks like you're slightly free cash flow positive.

I guess I'm wondering at this point, it seems like you're scalable enough, sizable enough to maybe be a standalone.

And I'm just wondering if you've given any consideration to a spin-out like we've seen others in the industry do?

Yes, Blake, I've said many times and will continue to say, Speedway is an integral part of our business.

We measure something called controlled volume, where we know every day because it improves our efficiency and the way we move products through pipelines, through terminals, through trucks, finally to the consumer.

We think that's the most efficient way to move your product, and it gives us the opportunity to capture margin across that entire supply chain.

And that's what Speedway does for us.

We think Speedway is one of the best operators in the business, and that's seen in their new record this year and income and cash flow.

When you step back then and look at a spin versus continuing to have this as, as I said, a key part of our business, having said that and I've looked at others who have spun off their retail, it has varying degrees of how many years you may have a supply agreement.

And 10 years, 15 years is a very short time.

And then you don't have that supply, you don't have that synergy that we have today.

So, I'm not going to say we will never do that.

We continue to look at this and study this, but I think Speedway has a long way to run as far as growing and continuing to be efficient.

And I think they have one of the best back room platforms in the business, which should help it continue to grow and become more efficient.

So not now, but we'll continue to watch it.

Okay.

Thanks, Gary.

Thank you.

Our next question comes from Faisel Khan from Citigroup.

Please go ahead.

Thanks, good morning.

Just on slide 21 of your quarterly presentation, and I think you've answered a little bit of this, but I want to clarify it.

So on the other gross margin that was above and beyond what you guys realized in the indicator margins, the $658 million, I believe when you were talking about the year-over-year numbers you said 50% and I assume it's the same for this number too, is that of the $658 million, roughly 50% is related to crude acquisition costs and the rest is related to other stuff.

Is that the right way to read slide 21 and that $658 million?

This is Don.

That $658 million is much more weighted towards refined product price realization than the $540 million that I talked about that was quarter over quarter.

So a much higher percentage of that $658 million is product realization.

Can you just go into a little more granularity?

Because obviously, we're using the indicator margins, and then we're not going to be able to pick up a $658 million swing in some sort of other product categories.

So can you go into a little more granularity in terms of what's in that number that allowed you to exceed the indicator margins?

Well, as I said, the biggest piece of that is the price realization.

We also -- and its always been consistently one of the items that shows up in that column is our purchase for resale activity.

So that as a meaningful impact, as well.

But we're not going to provide any more color on that.

I would just say, it's a much higher percentage.

As I said, the $540 million was probably 45% crude, and 30% or so related to refined product realization.

This is a majority of the $658 million is refined product realization.

Okay, that helps.

And then last question from me, with the Ho-Ho pipeline potentially for sale, do you guys have capacity in that line, and is that an asset you'd be interested in?

Well it's certainly a pipeline, Faisel, that we're interested in.

And it can be a good pipeline for us to take barrels coming from the Houston area into the Garyville refinery.

That's probably about the only thing that I can say to you today.

Okay, fair enough.

Thanks for the time guys.

Thank you.

Our next question comes from Evan Calio from Morgan Stanley.

Please go ahead.

Hello, good morning, guys.

I know there's been a lot of questions on light imports and Saudi imports, of which you take some Arab light.

Clearly, it's a more important topic today.

Can you discuss generally how that contract works?

I guess I'm asking, if economics permitted, how you could replace those barrels?

How does the timing on the contract work, given the shipment?

And how easy is it to run, given APIs are close, but clearly crudes have different yields, et cetera.

How easy is that to replace those barrels with local crudes, which also vary on the Gulf Coast?

Yes, Evan.

As we've stated before, we cannot get into any details about our foreign contracts.

And they are term contracts, but I'll just leave it that these barrels have to be priced competitively for us to continue to be interested in that supply.

And I think that tells you that, obviously, they are competitive or we wouldn't be running them.

But that's as far as we can go with talking about those contracts.

Then maybe away from the contract, just could from a refinery level, could you run other local crudes versus that crude, or is there any other run issues that relate to that?

Sure.

As I said earlier, we can run up to 65%, we believe, of our total crude slate in a light sweet crude.

Some of the Middle East crudes have different properties than some of the domestic crudes, and vice versa.

And some have different yield characteristics, but all those go into the equation and the calculus when we make our decision.

And we have been, if you look in total, there's still 1.5 million barrels or so of light sour coming into the marketplace, 1.5 million to 2 million of light sour coming into the marketplace.

It's just not light sweet, it's light sour that you look at too.

So every day, we're looking across the range of crudes that are imported into the US to determine what is the maximum profitable crudes to run.

Well inventory is infected this morning here, so it's some tail wind for those assets today.

And maybe a second question, just your outlook on tier III.

I know that that was proposed last year, and I think EPA's to come out with that at some point in the first quarter.

But have you -- are you prepared to discuss potential impact and potential relative Marathon spending that might be in the 2015, 2016, 2017 time frame?

Any thoughts at this juncture?

Right.

We did state at our Analyst meeting, we had some comment that we are prepared on tier III.

We are not prepared yet, Evan, to get into the details because the details have not yet been completed yet by the EPA.

We expect that probably in the first half of the year, it might even slip a little bit beyond the first half.

It looks as though things are going to be spread out and give us more time to be able to get the investments made in the different plants.

But it's certainly, from what we know in the early discussions, it's not onerous.

Okay, great.

Good results, guys, thanks.

Thank you.

Thank you.

Our final question comes from Allen Good from Morningstar.

Please go ahead.

Good morning, everyone.

Just a couple quick questions on the exports.

You mentioned the efforts you made in debottlenecking that increased your exports above I guess what you previously state your capacity to be.

Could we assume that that 400,000 barrels per day that you previously targeted for 2008 is either maybe conservative, or could be realized earlier in light of some of this debottlenecking, or is it a case where you actually need some new facilities now?

Alan, that's a great question, and I had that same question of the team when I saw the results for the fourth quarter.

But obviously, the position that we took in the fourth quarter and being able to increase the throughputs was very strong, and I applaud the team that was working on this.

So yes, we think we're going to get there sooner, but we do have to do some capital work -- for the next big jump, we're going to have to do some capital work in order to be able to get to that 400,000.

Okay, thank you.

And then just secondly, a lot of talking on light crude and processing more and your ability to do so.

Can you talk a little bit about the impact on yields and maybe your gasoline and distillate split, specifically, how that may change if you do increase light crude runs to the potential you have?

I'll let Mike answer that.

Alan, I guess the main thing that you can say is that when you switch obviously when you look at these light crudes, they do have a different yield fractions than other crude it would be replacing.

And I think I mentioned to you that, one of the issues you get into is, most of these have a pretty good sized naphtha cut.

So you've got to be able to upgrade that naphtha.

You've got to be able to reform it and make higher octane material.

And that's where we've said before, that we're in pretty good shape relative to the industry.

But again, as those volumes grow, all refiners, including ourselves, will look at ways to handle the fractions that first provide bottlenecks.

And it will just be an ongoing iterative process to continue to run more and more of the light sweet crude.

Okay, great.

Thanks for that.

Okay.

With that, we'll wrap up the call.

We want to thank everyone for joining us this morning, and for your interest in Marathon Petroleum Corporation.

If there are other questions or anything that requires clarification, Beth Hunter and Geri Ewing will be available the rest of the day.

Thank you very much for joining.

Thank you.

And thank you, ladies and gentlemen.

This concludes today's conference.

Thank you for participating.

You may now disconnect.