馬拉松石油 (MRO) 2010 Q2 法說會逐字稿

Good day, and welcome to Marathon Oil's 2010 second quarter earnings call. As a reminder, this call is being recorded. For opening remarks and introductions, I would like to turn the call over to Mr. Howard Thill, Vice President of Investor Relations and Public Affairs. Please go ahead, sir.

Thank you, Nancy, and welcome to Marathon Oil Corporation's second quarter 2010 earnings webcast and conference call. The synchronized slides that accompany this call can be found on our website, marathon.com. On the call today are Clarence Cazalot, President and CEO; Janet Clark, Executive Vice President and CFO; Gary Heminger, Executive Vice President-Downstream; Dave Roberts, Executive Vice President-Upstream; and Garry Peiffer, Senior Vice President of Finance and Commercial Services Downstream. Slide two contains a discussion of forward-looking statements and other information included in this presentation. Our remarks and answers to questions today will contain forward-looking statements subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied by such statements.

In accordance with Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995, Marathon Oil Corporation has included in its annual form on Form 10-K for the year-ended December 31, 2009, and subsequent Forms 10-Q and 8-K, cautionary language identifying important factors but not necessarily all factors that could cause future outcomes to differ materially from those set forth in the forward-looking statements. Please note that in the appendix to this presentation is a reconciliation of quarterly net income to adjusted net income for 2009 and the first two quarters of 2010, preliminary balance sheet information, third quarter and full-year 2010 operating estimates and other data that you may find useful. Slide three provides net income and adjusted net income data, both on an absolute and per-share basis.

Our second quarter 2010 adjusted net income of $792 million reflects a 151% increase from the first quarter results of $315 million, and a 216% increase from the $251 million earned in the second quarter of 2009. The waterfall chart on Slide four shows the first to second quarter change in pretax income by segment, as well as the subsequent change in income taxes. The increase in RM&T's income, partially offset by income taxes, was the primary reason for the increase in second quarter adjusted net income as compared to the first quarter. We expect the overall corporate effective income tax rate, excluding special items and the effect of foreign currency remeasurement of our tax balances to be between 49% and 54% for the full-year 2010.

For the second quarter, the effective income tax rate, including special items and the effect of foreign currency remeasurement of our tax balances, was 51%. E&P variance analysis is shown on Slide five. Compared to the first quarter, the second quarter saw higher liftings largely offset by lower realizations and higher costs. Higher income taxes booked during the second quarter contributed to pushing E&P segment income down 14% from $502 million in the first quarter to $432 million in the quarter just completed. The higher income tax rate in the second quarter is a reflection of the production mix. Second quarter E&P segment income reflects a $29 million pretax gain on derivative activity compared to a $49 million pretax gain in the first quarter. As a reminder, the E&P crude oil contracts expired at the end of June, while the gas contracts continued through the end of this year.

Slide six shows our historical realizations and highlights the $1.29 per BOE decrease in our average realizations, which moved from $53.90 per BOE in the first quarter to $52.61 per BOE in the second quarter. This is largely in line with the $0.83 per barrel drop in WTI and the $1.21 per Mcf decrease in bid week natural gas prices, partially offset by $1.87 per barrel increase in the price of Brent. Moving to Slide seven, as a result of higher international liftings, our second quarter sales volumes increased 7% to the first quarter, to 386,000 BOE per day. During the same period, production available for sale increased 3% to 375,000 BOE per day, primarily a result of the completion of turnaround activity in Equatorial Guinea at the end of the first quarter. The difference in sales volumes and production available for sale was the result of an overlift for the quarter of approximately one million BOE, primarily in Europe.

At the end of the second quarter, our international operations on a cumulative basis were essentially in a net balance lifting position, with an underlift position of approximately 400,000 barrels in EG and a 400,000 barrel overlift put balance in Europe. Domestically, we remained 2.5 million BOE underlifted due to gas storage in Alaska, again on a cumulative or a to-date basis. Turning to Slide eight, second quarter E&P segment income was $12.32 per BOE, a 20% decrease from the first quarter of 2010, primarily due to lower BOE revenues and higher taxes. While total E&P expenses per BOE were relatively flat first quarter to second quarter, E&P expenses, excluding exploration expenses, declined $0.51 per BOE. Slide nine shows the per-BOE trend over the last ten quarters for field level controllable costs and exploration expenses. Field level controllable costs per BOE increased 5% over the first quarter due to the higher international liftings and the related change in production mix compared to the first quarter. The increase in per-BOE exploration expense was largely due to the partial dry hole expense at the Gulf of Mexico Flying Dutchman well.

Turning to Slide 10, the Oil Sands Mining segment lost $60 million in the second quarter compared to a segment loss of $17 million in the first quarter of 2010. The turnaround of both the mine and the upgrader at the Athabasca Oil Sands project decreased net synthetic crude oil sales to 20,000 barrels per day in the second quarter compared to 25,000 barrels per day in the first quarter, and increased cost by $39 million compared to the first quarter. The turnaround cost net to Marathon was $99 million -- $30 million in the first quarter and $69 million in the second quarter -- and fell within previous guidance. Realized process fell from $73.76 per barrel in the first quarter to $65.11 per barrel in the second quarter. Second quarter segment income reflects a $53 million tax -- pretax gain on derivative activity, compared to a $10 million pretax loss in the first quarter.

These contracts continue through the end of this year. The Integrated Gas segment's second quarter income was $24 million, down from $44 million in the first quarter of 2010. Moving to our downstream business, as noted on Slide 11, RM&T's second quarter 2010 segment profit totaled $421 million, compared to $165 million earned in the same quarter last year. Because of the seasonality of the downstream business, I will compare our second quarter 2010 results against the same quarter in 2009. Our crude oil and other feedstock costs were lower than the change in the average price of LLS during the second quarter 2010 compared to the same quarter last year.

The primary reason for the relatively lower cost was the substantial increase in the sweet/sour differential from an average of $3.98 per barrel in the second quarter 2009 to $8.78 per barrel in the second quarter 2010. Total throughputs were up about 20% quarter-over-quarter, due primarily to the Garyville Major Expansion being online the second quarter 2010. The completion of this expansion, plus some other work we recently completed to improve the efficiency of our fluid catalytic cracking units, improved results over the second quarter 2009. Partially offsetting these positive effects was the fact that the relevant blended LLS 6321 crack spread decreased from approximately $5 per barrel in the second quarter 2009 to about $3.20 per barrel last quarter.

In addition, because of the expended refinery capacity at Garyville, total manufacturing and other expenses were higher in the second quarter 2010 compared to the same quarter last year. However, on a per-barrel of total refinery throughput basis, our refining, marketing and transportation expenses -- excluding DD&A, energy-related price FX and bank service charges -- were down about 12% in the second quarter compared to the same period last year. Again, primarily due to our expanded Garyville facility, our average daily refinery crude oil throughput increased 28% from the second quarter last year to the second quarter 2010, to 1,229,000 barrels per day. And as I previously mentioned, average daily total throughput increased 20% to 1,393,000 barrels per day in the second quarter 2010 as compared to 1,158,000 barrels per day in the second quarter 2009.

Our refinery and wholesale marketing gross margin of $0.1337 per gallon is based on a total consolidated refined products volume sold of 1,610,000 barrels per day or about 6.2 billion gallons for the quarter. We estimate that the Garyville Major Expansion contributed in excess of $0.013 to this expansion. Speedway SuperAmerica's light product and merchandise gross margin combined was about $43 million higher in the second quarter 2010 compared to the second quarter 2009. The increase was primarily due to a higher gasoline and distillate margin, which increased from $0.1051 per gallon in the second quarter 2009 to $0.1328 per gallon in the second quarter 2010. Speedway SuperAmerica's same-store merchandise sales increased approximately 4%, while same-store gasoline volumes increased 5% quarter-to-quarter. Slide 13 provides historical performance indicators for the downstream business and previously discussed LLS 6321 crack spread.

Slide 14 provides an analysis of preliminary cash flows for the first half of 2010. Operating cash flow from continuing operations before changes in our working capital was slightly over $2.3 billion. Our cash balance was reduced by working capital changes of $202 million. Capital expenditures were $2.5 billion and dividends paid totaled $350 million, while asset disposals generated proceeds of $1.4 billion. And finally, debt was reduced by $625 million. As shown on Slide 15, at the end of the second quarter of 2010, our cash adjusted debt to total capital ratio was 20%. And as a reminder, the net debt to total capital ratio includes about $239 million of debt serviced by US Steel.

Before we open the call to questions, we remind you that to accommodate all who wish to ask questions, you please limit yourself to one question, plus a follow-up. You may reprompt for additional questions as time permits. Nancy, with that, we will now open the call to questions.

Thank you, sir. (Operator instructions). We'll go first to Arjun Murti with Goldman Sachs.

Thanks. Just a question on how you all are thinking about your Gulf of Mexico business in light of the Macondo oil spill. I realize there's a lot of uncertainties in terms of how the regulations and such things will play out. But if smaller or other companies are less interested, is this an area you'd be willing or looking to grow in? Is it an area you want to maintain your presence and your focus elsewhere because risks might be higher? Can you just provide any comments on how you're thinking about your Gulf of Mexico exposure going forward? Thank you.

Yes, Arjun -- this is Dave, and I think you put your finger on the problem that we've got, is right now, the playing field has not settled down. So until we understand where the regulations are going to go, it's very difficult for us to predict what our response to our own business is going to be.

Now, we've said consistently this is one of the most valuable provinces in the world because of the fact that it represents one of the most stable and attractive fiscal regimes. And if that changes, then our outlook relative to that basin will also have to change, because obviously we want to protect our shareholders. That being said, we think -- we continue to believe that this is an incredibly important province for the United States in terms of its energy security. We expect whatever ultimately happens out of the Government to be reasonable, and our expectation is that we will continue to be interested in doing business in the Gulf of Mexico. And I wouldn't speculate on what other operators are going to do and what our appetite might be for those opportunities.

Dave, that's really helpful. Just a related follow-up. There's this big question on this sense of a liability cap, and I know you probably don't want to speculate on whether there will be one or what it may be. But in the case of BP, there is effectively no liability cap. They're a large, prominent company. You all may not be as large as BP, but people know who you are. You've got a large downstream presence. Does a liability cap make any difference to how you think about the Gulf of Mexico, whether we have one or not?

Well, I think it definitely does, Arjen. I think one of the things that we've said is we have always understood that for clean-up costs that there is an unlimited liability today, and so I think that's one of the things that all oil companies understand very clearly. The issue is, it's the attached liabilities, should there be some sort of mechanism to limit a company's exposure there, unless they are indeed found negligent; in which case, again, the cap doesn't apply.

So we are going to watch that very carefully, and I think one of the things that we have been involved in directly with our peers is trying to set up mechanisms whereby the industry can come together to not only work on some of the concerns that the Government has in terms of prevention and response in the future, but also making sure that this basin and area remains open to a large number of companies through some sort of shared risk mechanism. We think that's very important, because we think not only do the supermajors and the majors like Marathon have a lot to offer in this basin, but obviously some of the independents do as well.

And we'll move to the next question from Doug Leggate from Merrill Lynch.

Thanks. Good afternoon, everybody. I have, I guess, a follow-up on the upstream, and then I guess I have a second upstream question. If exploration activity in the Gulf is obviously being slowed down -- and you guys had a bunch of prospects that you were planning to drill this year -- how are you reallocating the capital, and can you maybe frame how the Bakken activity levels might feature in terms of how you might reallocate some of your expenditure? Then I've got a follow-up, please.

Yes, Doug. Great question. I think first of all, I would say that -- I want to point out that our primary activities in the Gulf of Mexico are not slowing down. Droshky came online in July and we expect Ozona to be on track for next year as well. So in terms of the realtime activities that are going to be immediately value-added to our shareholders, it's full speed ahead for us. We obviously -- we'll be watching and we'll register the appropriate concerns as we see how this moratorium and potential further extensions of it might apply. But clearly from an exploration discovery to development perspective, you were talking about a 5 to 7 year period anyway, and so that's certainly something that we can be slightly more sanguine about than if these events were interfering in production activities. We had said previously that we were ramping up, and Bakken had nothing to do with the potential reallocation from the Gulf of Mexico. We've added some acreage this year. We're going to six rigs. We've added the fifth, and we'll see the sixth here in the next quarter. We are looking at other opportunities as much as other people are, but that's really a part of our business; but clearly we are focused on lower 48 liquid activities.

Great stuff. My follow-up, Dave, is actually -- is also an upstream question that's more project specific. Can you confirm if Ozona has its subsea work completed? Can you give us the current production at Droshky? And finally, we are hearing that the subsea trees or potentially a second development in Angola have already been put out to bid, if you could give us some idea as to how you see the next development in Angola after PDSM, that would be great. Thanks.

Doug, that sounds like three questions to me, but me being kind, we will answer them.

Well, I will answer the first two for sure. Right now, we are in the middle of flow back in Droshky. We are repairing a surface separator on the Bullwinkel platform that's interrupted our flow back tests. I can tell you that the first well, we saw rates about 20,000 barrels a day. The second well, we saw 22,000 barrels a day -- these are gross numbers. And we've got one more well that we are going to run through the test before we see what we expect will be continuous production by the end of the month. So production there is kind of up and down on a day-to-day basis. The Ozona is a well that basically is drilled and temporarily abandoned.

So all we have to go back to do now is set the subsea tree, which we expect to have delivery on in the next quarter, and then go back in and actually do the completion work. So there's nothing spectacular that's going to have to happen there. The long delay before it comes on until what we are projecting in the third quarter really has to do with some timing issues of rig deliveries, and also some of the surface modifications that the host operator has to make on the auger platform. With respect to Angola, PSBM, we think, is on schedule for 2012, and I think we would ask you to direct any questions about future activities there to the operator, BP.

And we'll take the next question from Doug Terreson from ISI Group.

Good afternoon, everybody.

Hi, Doug.

To turn back to Dave's initial point on Speedway activity, there have been a variety of divestitures by your peers in recent months; and on this point, when you consider the improvement in your financial flexibility over the last couple of quarters, do recent valuations encourage you to consider more sales than might have been the case a few quarters ago, or has the view really not changed very much?

Well, Doug, I think what we've said consistently is we continue to look at our portfolio and adjust it. So -- and we think that we made some strong sales into a strong market, and I don't see this as particularly a rising tide event where we would --

Okay.

seek anything else out the door.

Okay. And also, I had a question for Gary. Obviously, refining and marketing did very well, partially due to the expansion at Garyville, and it appears that your light products yield may be running a little bit higher than expected. And so my first question is whether or not yields and performance in general have exceeded expectations? And whether they were or not, have there been any surprises, either positive or negative, as the expansion has streamed over the last couple of months?

Hey, Doug. Let's say on Garyville, the refinery has operated -- the new part of the plant has operated very, very well and has exceeded our expectations in all of the operating components. And when you look at the first quarter and you look at yields versus demand, really, against all the plants, it's very hard to really glean from the information that's out there the yields by plant, and it really comes down to the asphalt and the [resid] markets. All of our plants ran very, very well; but as you can expect, there are some markets where maybe the asphalt yields were cut back a little bit, just because of the economics, versus some other plants where we may have run asphalt a little bit harder. But all in all, I would say Garyville has run exceptionally well. All the plants are in good shape. But just based on certain markets, we have trimmed back some of our yield components.

Okay. Great. Thanks a lot.

Thanks, Doug.

And we'll go next to Evan Calio from Morgan Stanley.

Thanks for taking my call. I had one question, which is a bit of a follow-up from the last question where you addressed potential asset sales. But I know that Marathon has also been historically a pretty astute buyer. Do you see opportunity as a buyer, given the large number of asset packages in the market, as well as some regulatory changes or operational changes in the Gulf of Mexico? Any comments there?

Yes, Evan. I think similar to the comment I made to Arjun, we'll wait and see. I think, from my perspective, I don't want to wish any ill luck on anybody about being forced out of, say, the Gulf of Mexico; but we would certainly be open to those opportunities because we are clearly have the skill set to both explore and develop there. And there's a lot of activity in the asset market -- there has been before the recent activities from the company in England. So I think we continue to look at activities to see how they fit with what our core strategies are, and as we see opportunities that work for us, we certainly wouldn't hesitate to execute against them.

With a -- what you mentioned earlier with the North American liquids focused, is that -- I mean, was that explicitly where you are focusing versus potentially any unconventional assets?

Well, I think when we talk about North America, but primarily our opportunities around the world, the vast majority of them are unconventional. And so it's one of the reasons we are very happy with the learning curve that we've gotten on in the Bakken, because we feel like we can be competitive in any of those basins anywhere in the world.

And next we'll go to Edward Westlake from Credit Suisse.

Yes, good afternoon, everyone. Great results in the downstream. I guess the net debt to cap is now sort of 20%. You've got an $800 million asset sale, hopefully closing towards the end of the year. You obviously did raise your dividend at Q1. Can you talk a little bit about as debt comes down, assuming that some of the macro conditions continue, that your discussions around raising the dividend versus buybacks, versus perhaps additional reinvestment?

I guess I'll answer that. That this is Janet. Really, our philosophy around use of cash has not changed. First and foremost, we will reinvest our cash in the business to create shareholder value. Obviously, you only create value if the projects in which you are investing in yield a rate of return that will accept your cost of capital. So that's number one in terms of the best use of our cash.

But to the extent that we have excess cash beyond that, we want to keep a strong balance sheet; but the dividend, we've always said, is a high priority for us. We've got a dividend deal in excess of 3%, and it's something that our Board revisits every quarter. I don't foresee the stock buybacks coming back on the table any time soon.

Thank you. And then just a small follow-up, on the -- this is more an earnings-specific question, but the $51 million of other costs in E&P, Q-on-Q, what's the main thing behind that? Or is it just a number of different things?

It was a bunch of different things.

Yes. Oh, the 51 million in other?

Yes.

Ed I will have to get back to you. I don't have the specifics in front of me. But I'll give you a call back.

And moving next to Paul Cheng from Barclays Capital.

Thank you. Hey, guys. Two different questions. One is downstream. One is upstream. On downstream, Gary, can you tell us that excluding the inventory, what's the Minnesota sales actual? How much is that? And also then why it take to long until the year-end? And from that standpoint, with the Minnesota office sales and also one of your competitors -- smaller competitors -- exiting refining, have you guys revisited the separation of O&M from the rest of the Company, or that -- the opinion, (inaudible), has it not been changed over the last several months?

Gary, why don't you go first on the refinery and I will touch the last one?

Sure. Paul, as you understand, we are still working through all of the transactions and working through all the due diligence and we have not been able, nor yet are we prepared, to separate out how much is working capital and how much are assets. Certainly expect us, as we proceed on late third quarter, early fourth quarter, that we should be able to finalize this transaction and then be able to share that with you.

Okay. Thank you.

And, Paul, this is Clarence. No change from what we've said before, Paul, that back in February '09, we said we were going forward as an integrated Company and that's the way we are managing the business today. So no change.

Can I sneak in the second question? For upstream, Dave, for Droshky, can you tell us once it reach the peak, how long they will be able to sustain at the peak and what will be the expected decline rate subsequent that when they start declining in the first 12 to 18 months?

Yes, well, I wish I knew. We'll see as the wells come on, Paul. But I think the view for us is that we will probably get to a peak rate in the next 30 to 90 days. I wish I could narrow it down. But, again, as I've said in these calls before, the wells tell you how you can get there, and I think what we are expecting is that will be able to have a peak probably for the better part of two quarters, and then I would expect to see a pretty normal Gulf of Mexico decline in excess of 10% from there.

And we'll take the next question from Blake Fernandez from Howard Weil.

Hi, good afternoon, guys. I had a question for you on the downstream. The throughputs and utilization on the R&M segment seemed very strong, obviously benefiting from Garyville. Just curious now that that's online if the strategy going forward is changing at all with regard to potentially running that system all out and that it's more competitive to essentially let some of the more marginal players kind of bear the brunt of any potential future run cuts on the second half of this year?

Yes. This is Gary. The -- every day we have run our economics per plant to determine what the economics are versus our alternative, and you are right, in the second quarter here we did run very well, about 101% or so of utilization. So had a strong quarter. As I've mentioned earlier -- I believe it was on Doug Terreson's question -- of course, we look each and every day and week at the yields of different products to determine what will give us the best economic return. But that's how we have run historically, and that's certainly how we plan to run in the future.

Okay. And Gary, just, I guess a follow-up on St. Paul. Can you just talk about the divestiture, the rationale behind it and how it fit into the portfolio?

Sure. St. Paul along with about a -- almost an 80,000-barrel per day plant, 166 convenience store operating units and a pipeline -- a crude pipeline that supports the refinery, we have always looked at this as a very strong niche asset, but not a strategic asset. When you look at -- I mentioned several times, how we operate our facilities, we really operate the other six refineries as one unit. And because of our very strong logistics systems, we can move crude, feedstocks, refined product into the refineries, out to the terminals into our pipelines using our marine facilities and then into our retail network.

When we made the decision on investing to run heavier crude in the Midwest, we made that decision to upgrade Detroit. So that is our long-term strategic decision, because that refinery being the only refinery in the state of Michigan really compliments all of our operations across the rest of Marathon's downstream. So we made that decision, as I said, to invest in Detroit and then that left us to look at our strategy, and decided to move forward and sell the St. Paul assets.

And we'll go next to Faisel Khan from Citi.

Good afternoon. I think I got the details on the benefit to the refining margin and the sweet/sour, and I think Garyville you said was $0.013 in terms of the benefit to gross margin. Could you also give us an idea of what the benefit was from blending of ethanol?

Faisel, we did not ever release our benefit from ethanol down to that level. So I'm sorry, I can't share that with you.

Okay, understood. And then my second question on the upstream side is, I guess your sequential production growth in the Bakken went from roughly 11,000 to almost 13,000 a day. Is that a linear sort of trajectory? And as you bring a rig online, should we expect that sort of to ramp up at the same pace into next year?

Well, I think what we said, Faisel, is that we're going to get to 21,000, 22,000 barrels a day in 2013, and I think you would expect to see that continuing on that normal pace. We've got 175 wells that we've drilled. We can do 50 or 60 a year, the high end side of that, with the six rig. And so I think -- I'm not saying it's exactly linear, but it's not going to be too choppy in getting to the 22,000.

And we'll take the next question from Mark Gilman from Benchmark Company.

Good afternoon, folks. Two questions for Dave, if I could -- call one of them a follow-up, if you like. Dave, now that Volund is essentially fully on, how long will the plateau at Volund be sustained, and what kind of all-time Volund combined decline rates are you looking at?

Okay, Mark. I think the -- you know, first of all, we are producing on a gross basis between 130,000 and 140,000 barrels a day, and so -- but I would like to answer your question in terms of where we see it relative to the 120,000. We're going to continue at the current rate that's 130ish through this year and the majority of next year and we will be over the capacity of the FPSO, 2010, 2011, dropping just below that in 2012. So it looks to me to be about a 5% to 8% decline rate, dropping pretty substantially in 2013. So we've got three good years ahead of us.

Okay. And Dave, my follow-up, on Droshky, what type of initial DD&A rate are you going to book?

Right now, we are expecting you could look at about $25 a barrel.

And we'll move next to Pavel Molchanov from Raymond James.

Thanks for taking my question. I think you said last quarter that you're doing some seismic in your Polish shale play with -- or I guess planning that for 2011 and currently looking for partners. Can you just give us an update on how the partnership process is going?

Yes, we basically have put together what amounts to a data room, and we'll start entertaining people to look at our assets there within the next month. And so it's early days there. Obviously, we're anxious to see the results of some of the offset activity there. Not in a rush, because we believe that our position, obviously, is quite attractive. But don't have a timing for when we might expect to announce or even select a partner.

Then as a follow-up, more of a macro question. So we have seen, along with you guys, of course, many other companies putting pretty large refining asset packages for sale in the last six months. Do you think there is demand out there for all of those assets, or are we still in kind of the bottom of that down cycle?

This is Gary. I would say we're still at the bottom of the down cycle. As it's been seen in the press recently, a couple of plants have struggled to find buyers, and we're very pleased with a very high quality plant and the high quality retail assets with our St. Paul Park plant. We're very pleased with that transaction as it's proceeding forward; but I would say, it still appears to be kind of a bottom of the market.

And we'll take the next question from John [Hurland] from Societe Generale.

Yes, hi. Some upstream questions for me. Within the niche of how long will you take to TD the well, and could you describe the prospect a little bit more?

Yes, I would refer you to some of our presentations around passing value. The one we'll drill first is Bravo. It's a fairly large closed structure that we think is a billion barrel unrisk of potential. But there's multiple play types on the acreage because it is a multimillion acre block. And so the Romeo prospect that we drill a little bit later is of a different geological quality. It's not related to the offset exploration activities that have been conducted in the area, which were basically carbonate pinnacles. So it's a very different play type. The rig is on shale to the Bravo prospect right now. We will probably be spudding in, I would guess, in the next seven to ten days. Anticipate this to be a two-month well, and so we'll probably have something to say about it a little bit later this quarter.

Okay. So you're implying it's a clastic rather than a carbonate?

Well, yes, I think I can say that. I didn't imply it, yes.

Okay. Next one. Any issues regarding processing or transport of Bakken oil? Any problems getting it out of the basin?

No, we -- again, because of our very solid downstream business, we have great relationships, and our people in the basin do a great job of being able to handle our crude largely in the basin, and we continue to have a very favorable impact in terms of getting our crude out and processed at lesser costs than our competitors.

(Operator instructions). And we'll go to a follow-up from Paul Cheng.

Hi. Gary, in the refining, on the margin realization, can you share with us, what is the potential benefit and also the price finalization related to the (Inaudible) contract benefit for this quarter?

This is Garry Peiffer. On the Contango, the benefit in the quarter was really pretty minimal. Last year second quarter, the Contango was about $2 on average. This year, it's about $1, or was about $1.50. So there was a little bit of a volumetric quarter to quarter, so really was pretty immaterial. And with the change in how one of our foreign crudes were priced -- effective last year, the Saudis changed their price mechanism -- we really don't have any in-transit, effects to speak of at the moment, so both are immaterial -- or non-existent -- in the case of the foreign in-transit.

Okay, a follow-up -- actually, a second question is that, you have an impairment charge related to the (inaudible) receivable. What is the nature of that? Does that mean the guy who bought it could not pay, or what's the nature?

No, Paul. When we did that sale, we structured it to have a contingent payment based on when natural gas would actually be produced there. And what we're saying is we think that we are going to realize the end date before production actually occurs. So it has nothing to do with the quality of the buyer, it's really how we structured the sale -- and that is detailed heavily in our filing.

And we'll take another follow-up from Doug Leggate.

Howard yelling at me again, so I'll (inaudible).

I'm not going to yell at you, Doug.

Contribution from refining. I just wanted to get some clarity here. You were kind enough to give us $0.013 was the contribution, if I heard you correctly.

In excess of $0.013.

That's out of the 13, Howard?

Out of the $0.1337, in excess of $0.013 of that was GME.

Okay. So my question is, if I do the math right on the gross margin, does that mean that Garyville expansion contributed about 25% of the gross margin total in terms of absolute millions of dollars? Is that about right?

No.

No.

Can you quantify the contribution? I'm looking at your chart on -- I believe it's slide 11. Is that the volumetrics -- ?

It's 6.2 billion gallons, Doug, with a $0.013 -- we said in excess of $0.013 margin. So --

So that's the --

That's a pretax number. That's the pretax contribution that we said it would -- we expect Garyville -- it's not an exact science, because it is tied in with the existing facility. But we think it's in excess of $0.013 that it contributed on the 6.2 billion gallons of sales for the quarter.

All right, I'll take that offline. But I guess, what was at the guts of my question was, can you tell me how you have changed your crude slate with the Garyville expansion online, given where light/heavy differentials or sweet/sour differentials have gone and how that's likely to continue, let's say, through the third quarter? And guidance on the crystallite would be great.

Sure, Doug. This is Gary. In fact, it's probably a little bit contra to what you would expect. The -- and it's just because of the yield of the products. Once you fill up the coker, then you switch to a different slate. If the asphalt markets are not returning good enough economics for you to run heavier crudes. So, as I say, when you look at on a -- and this is on a total basis -- but we ended up running 56.4% sour crudes in Q2 versus almost 54% Q2 of '09. So our sour crude throughputs were up a little bit, but that's going to be offset by running more LLS than -- historically we had run very little LLS at Garyville. But, again, just the yield pattern and the demand patterns gave us better economics to run more LLS than it would be to run heavier crudes once you've filled up the coker.

And we'll take one final follow-up from Mark Gillman.

Yes, one more, if I could, for Dave. When you talk about the plateau rates at Droshky, is that net of both the basic royalty, as well as the override that's in place, I believe, there?

We talk about 50 \KBD. That is our true net.

After the override, Dave?

Net/net.

Net/net. When we say net, we mean net.

Okay. Per your third quarter production guidance, which I assume takes Droshky into consideration, is the gas piece of that delayed, or is that going to come later on? How is that working?

No, it's a single stream of production. I think the only thing that -- we are expecting a pretty significant contribution from Droshky. I think for the quarter, we are just saying that the load up of it from the flow back could be 30 days. It could be 60 days. And so that's why you are seeing the variance in the guidance, but there is no difference between gas and oil here. It's a single stream.

Since I've got the last follow-up, I will just throw one for Gary. I want to go back to the GME yield question that was addressed earlier on. Gary, how close do you think one can get the actual 2Q yields at GME to the 211 that you had been talking about?

You're saying how close do they correlate to the 211?

Yes, how close did they actually correlate with the 211?

I think they were very, very close in Q2.

Okay, Gary, thanks very much.

Okay.

And that does conclude today's question-and-answer session. At this time, I would like to turn the conference back over to our speakers for any additional or closing remarks.

Thank you, Nancy. We just appreciate everyone's interest in Marathon Oil, and talk to you soon.

That concludes today's presentation. Thank you for your participation.