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Executives

Howard J. Thill - Vice President - Investor Relations and Public Affairs

Clarence P. Cazalot Jr. - President, Chief Executive Officer, Director

Gary R. Heminger - Executive Vice President Downstream

Gary Piper - Senior Vice President of Finance and Commercial Services Downstream

David E. Roberts Jr. - Executive Vice President Upstream

Janet F. Clark - Chief Financial Officer, Executive Vice President

Analysts

Doug Leggate - Merrill Lynch

Jason Gamel - McCorey (ph)

Blake Fernandez – Howard Weil

Faisal Khan – Citi

Evan Calio – Morgan Stanley

Paul Cheng – Barclays Capital

Neil McMahon – Sanford Bernstein

Pavel Molchanov – Raymond James

Robert Kessler – Simmons & Company International

Kate Lucas - Collins Stewart

Mark Gilman – Benchmark Company

Jason Gamel - McCorey (ph)

Faisel Khan – Citigroup

Paul Cheng - Barclays Capital

Mark Gilman - The Benchmark Company

Marathon Oil Corporation (MRO) Q4 2009 Earnings Call February 2, 2010 2:00 PM ET

Operator

Good day, and welcome to Marathon Oil's 2009 fourth quarter earnings call. Just 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.

Howard J. Thill

Thanks Jeff. I would like to welcome each of you to Marathon Oil Corporation's fourth quarter 2009 earnings web-cast and teleconference. The synchronized slides that accompany this call can be found on our website at 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, David Roberts Executive Vice President Upstream and Gary Piper, Senior Vice President of Finance and Commercial Services Downstream.

Slide two contains the forward looking statements and other information related to 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 Privacy and Securities Litigation Reform Act of 1995, Marathon Oil Corporation has included in its annual report on Form 10-K for the year ended December 31st 2008 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.

In the appendix of this presentation is a reconciliation of net income to adjusted net income by quarter for 2008 and 2009. Preliminary balance sheet information, first quarter and full year 2010 operating estimates and other data that you may find useful.

Moving onto slide three. During the fourth quarter out adjusted net income was weaker than the corresponding quarter in 2008. A significant contributor to this reduction was an almost $280 million swing in the foreign exchange on deferred income tax balances, largely in Canada. For the fourth quarter 2009, we incurred a $139 million loss while in the same quarter of 2008 we recorded a $138 million gain. While this is a number rarely if ever taken into account in analysts' estimates, I'd like to take this opportunity to point out that our adjusted net income would have been at the first call analyst average estimate if not for this non-cash swing in deferred tax balances. And we expect to make a one-time election during the first half of 2010 to begin paying Canadian income tax in U.S. dollars and thus eliminate the largest portion of these fluctuations.

Moving to slide four, and looking at key drivers to the year over year decrease in adjusted net income, we had a significant decrease in our RM&T segment income, driven by weaker refining and wholesale marketing margins as well as weaker retail margins, and lower earnings from our Oil Sands Mining segment.

These unfavorable effects were partially offset by an increase in E&P earnings and the result of a 3% increase in sales volumes and higher realized crude oil prices partially offset by lower natural gas prices during the quarter. While about half of the $570 million negative variance from income taxes was a result of the previously discussed affect impact, the other half of the variance was largely the result of adjustments made at the end of 2008 while the year end 2009 adjustments, other than affects were relatively small.

Moving to slide five, the key drivers to the year over year decrease in adjusted net income included significantly lower average realizations in our Upstream businesses and much lower refining and wholesale marketing gross margins in Downstream. On the positive side, we ran very well across all businesses posting significant increases in safety and reliability. This helped drive a top-tier increase in E&P production volume sales of 8% and a mechanical reliability of our refineries of 96.7% based on internal metrics.

Additionally our focus on cost controls resulted in a full year reduction in E&P operating costs per BOE of 15% excluding production taxes and DD&A. While we also reduced operating cost in the Downstream business, by approximately 9% excluding changes in crude and product purchases depreciation energy prices and certain other variable expenses.

As shown on slide six, E&P segment income for the fourth quarter decreased 10% compared to the third quarter of 2009, largely due to higher income taxes and higher geological and geophysical seismic expenses. The negative impacts were largely offset by quarter over quarter increases in both price realizations and sales volumes.

Slide seven shows the average E&P realizations as well as market indicators. Our average E&P realization per BOE increased $5.(inaudible) quarter over quarter while the same period nine mixed prompt wti (ph) increased $7.89 per barrel. In the bid week, natural gas prices increased $0.77 per million BTU's.

E&P production volumes are shown on slide eight. Fourth quarter compared to the third quarter production sold increased 13% to 413,000 BOE per day, while production available for sale increased 3% from the third quarter 2009 and 4% from the fourth quarter 2008. The higher sales volume versus available for sale volume was the result of an over-lift of approximately 900,000 BOE for the quarter. We ended the year with a to-date under-lift position of 3.3 million BOE consisting of 2.6 million BOE of gas storage in Alaska, an under-lift position in EG of about 500,000 barrels and approximately 200,000 under-lift in Norway.

Slide nine shows the trend over the last eight quarters for field level controllable costs and exploration expenses per BOE. While field level controllable costs were relatively flat on a per BOE basis for the fourth quarter as compared to the third quarter, exploration expense increased to $3.30 per BOE primarily as a result of geological and geophysical expenses incurred worldwide.

Turning to slide ten, compared to the prior quarter, fourth quarter E&P earnings per BOE decreased to $11.55 largely as a result of the higher exploration expense just discussed and higher international taxes partially offset by higher commodity prices that lowered domestic DD&A excluding exploration expense and DD&A, total cost BOE were relatively flat at $9.90.

Turning to slide eleven and Oil Sand Mining, fourth quarter segment income increased over 60% over the fourth quarter of – sorry from the third quarter to $41 million. The increase reflects positive price and volume gains partially offset by higher expenses. Production for the quarter was 26,000 barrels per day.

Turning to slide twelve and Integrated Gas, fourth quarter segment income almost tripled compared to the third quarter on stronger LNG prices, while higher LNG volumes and stronger methanol prices also contributed to the increase.

As noted on slide thirteen, and previously discussed 2009 was a strong operational year for the Upstream businesses. Production available for sale was up 9% for the year to 405,000 BOE per day. We exited the year with over 11,000 net BOE per day of production from the Bodkin (ph) and an increase of almost 40% from the 2008 exit rate and we achieved first oil at Boolin (ph) ahead of schedule.

We announced a number of discoveries in the Gulf of Mexico, Norway and Angola and added additional

licenses in Poland and Canada. The Upstream business also benefited from high operational reliability at the company operated facilities, and we completed a number of dispositions and announced the sale of 20% interest in Angola block 32, leaving us with a 10% interest in both blocks 31 and 32.

Moving to our Downstream business, as noted on slide fourteen RM&T's fourth quarter 2009 segment loss totaled $18 million compared to segment income of $325 million in the same quarter last year. Because of the seasonality of the Downstream business I will compare our fourth quarter 2009 results against the same quarter of 2008.

Our average wholesale price realizations increased substantially less than the increase in the market refined product prices used in the market based LLS 6321 crack spread calculation in the fourth quarter 2009 versus the same quarter in 2008. The primary reason for this lower increase was due to the fact that in the fourth quarter 2008 we benefited from the approximately $55 per barrel drop in the price of crude oil during that quarter, versus the fourth quarter of 2009 when crude oil prices increased by approximately $10 per barrel. Partially offsetting the negative effects, our actual crude oil and other (inaudible) cost increases were slightly lower than the change in the average price of LLS during the fourth quarter 2009 compared to the same quarter last year. The primary reason for this benefit was the fact that the market was in (inaudible).

Also manufacturing and other expenses were lower in the fourth quarter 2009 compared to the fourth quarter of 2008 primarily due to lower energy and lower turnaround costs. Total refinery crude oil through-put (ph) averaged 999,000 barrels per day in the fourth quarter 2009 compared to 952,000 barrels per day in the same quarter last year. Total through-puts were 1,191,000 barrels per day in the fourth quarter 2009 as compared to 1,177,000 barrels per day in the fourth quarter 2008.

Speedway SuperAmerica's refined product and merchandise gross margin was about $45 million lower in the fourth quarter 2009 compared to 2008. The majority of this decrease was due to lower gasoline and distill margins which decreased about $0.08 per gallon quarter to quarter. We did however achieve a 10% quarter to quarter increase in SSA's same store merchandise sales, while same store gasoline volume decreased 2% quarter to quarter. We estimate demand in SSA's primary market area also decreased by about 2% quarter to quarter.

Slide fifteen provides historical performance indicators for the downstream business and previously discussed LLS 6321 crack spread.

Slide sixteen provides preliminary analysis of cash flows for 2009. Operating cash flow for continuing operations before changes in working capital was $4.8 billion and our cash balance increased by $411 million as a result of working capital changes from continuing operations. Cash capital expenditures for 2009 were $6.2 billion and we issued $1.5 billion in debt and paid dividends total $679 million and generated proceeds from assets disposed of in the amount of $865 million, and I remind you that the previously discussed $1.3 billion Angola sale is expected to close in the near future and thus is not reflected in last year's cash flows.

Our year end 2009 cash balance increased by almost $800 million from the balance of year end 2008 to just over $2 billion. Slide seventeen provides a summary of select financial data. At the end of the fourth quarter 2009 our cash adjusted debt to total capital ratio was 23% a decrease of two percentage points from the third quarter and as a reminder this debt includes approximately 340 million serviced by U.S. Steel.

Slide eighteen sets out Marathon's priorities for the year 2010 and while I won't go through the entire list, I would note that we will focus on upstream growth through an increased resource placed footprint and increased exploration in the Gulf of Mexico and Indonesia, along with ramping up production in the Athabasca Oil Sands project.

Our RM&T program which is less than half of last year's capital spending for that segment had about 22% of our company wide $5.1 billion 2010 projection includes progressing construction on the Detroit Heavy Oil Upgrade facility which is approximately 30% complete. After extensive turnaround of the base Garyville refinery in the first quarter we anticipate the combined 436,000 barrel per day refinery will turn into a significant cash and earnings contributor starting in the second quarter.

We also will continue to focus on maintaining financial strength and will link capital spending with cash flow. In support of that position and turning to slide nineteen, you will find details of the derivative positions we've entered which are designed to manage price rift on anticipated liquid hydrocarbon, natural gas and synthetic crude sales in 2010. The derivative positions relate to approximately 40% of domestic natural gas sales in the lower 48 and nearly 80% of synthetic crude sales in Canada for the full year of 2010. Additionally positions taken for only the first half of 2010 relate to approximately 20% of full year crude sales in the U.S. and Norway. These derivative positions do not qualify for hedge accounting.

We will now open this call to questions. But please to accommodate all who want to ask questions we ask that you limit yourself to one question plus a follow up and you may re-prompt for additional questions if time permits. With that Jeff, I'll give it back to you.

Question and Answer Session

Operator

Thank you. (Operator's Instructions) The first question comes from Doug Leggate with Merrill Lynch.

Doug Leggate - Merrill Lynch

Thank you. Good afternoon everybody. Could of things, I’ll try and keep it to two. I guess the first one is on the exit rates on the back end. I mean, clearly a 40% increase year-over-year. But your target, of course, is 15,000 bottles of (inaudible), by I guess 2013. Can you just reconcile the pace of growth in 2009 and why for such a high margin assess in terms of IRO you wouldn’t get a little more aggressive given the cash flow you’re going to see from Garyville and of course, proceeds from Angola. So a little more aggressive in the backend and why not is a question. Then I have a follow up.

David E. Roberts Jr.

Clarence and I are out of the country so I hope you can hear us. But great question and not an effective (inaudible). We had a very good year on the back end. Pushing 11,000 barrels a day. As you may be aware we’ve gone from three to recently four rigs there. We’ve got about 50 wells completed. So very consistent with what we said about what we think these wells do rate wise. And so the expectations are very solid.

I will tell you that we are indeed going to pick up the pace a little bit in 2010. And we’re going to probably pick up another couple of rigs throughout the year. But again, we are pretty consistent with what our view you can do in terms of rates times well in that particular clay. But I think you’ll see us become a little bit more aggressive this year as we move forward.

Doug Leggate - Merrill Lynch

All right, Dave, thanks a lot. Does that mean the $15,000 is ideal number has some upside risk?

David E. Roberts Jr.

I’m not sure the term upside and risk go together. But we continue to be encouraged with what we see in the plans. (No audio) One of the things that we say being at close to 350,000 plus acres we do think that there’s more upside in play. But we’re going to continue to do it (no audio)

Operator

And there’s just a brief interruption in the conference. Please remain on the line.

David E. Roberts Jr.

Hopefully we haven’t lost our –

Operator

He disconnected from the conference, sir, actually.

David E. Roberts Jr.

Okay. Doug, if you want to follow up with your second question.

Doug Leggate - Merrill Lynch

Just curious on the look of the tax rate in the US was very low in the quarter and I was just hoping you could give me some clarification on that. I’ll leave it there before I get cut off or something.

David E. Roberts Jr.

We won’t cut you off, Doug.

Janet F. Clark

In the fourth quarter as usual, we have a variety of the trade items, none of which are very big. We didn’t have very big overall income in the US in the fourth quarter. So those smaller of the three items have a bigger impact on the overall effective tax rate. So it really is nothing major. There were some returns to approval from the State Income Tax, was the biggest item. And that was a positive. So it was a benefit.

Doug Leggate - Merrill Lynch

Got it. All right. Thank, Janet.

Operator

And moving on, the next question comes from Jason Gamel with McCorey (ph).

Jason Gamel - McCorey (ph)

Thank you. I want to stay on the theme of the unconventional resource and the acreage position established in Poland. Can you talk a little bit about lease (inaudible), really thinking more in terms of how long you would be able to hold leases before you establish first production? When you plan to drill the first wells there? How many rigs you would expect to employ? Let’s say, maybe not in 2010 but in 2011 and 2012?

David E. Roberts Jr.

Jason, it’s still very early days in Poland. We’re very excited now to cross the 800,000 acre level in that site. Very early days for us. I think the easiest way to start the lease tone would be is they’re very fair and flexible five year lease terms where you have at least the first half of the term before you actually have to commit to drilling a well. Leases do have a well commitments. So that’s part of it. But the initial phase is certainly the first year it can be dedicated to study.

I think our view if we could potentially see well activity in 2011, and I wouldn’t expect us to feel any more than one, possible two year.

Jason Gamel - McCorey (ph)

Okay. That’s useful. And maybe my second question, we’re expecting Droskey (ph) first production, middle of the year. Looks like you’re going to have a lot of the development wells predrilled. Should we expect a pretty quick ramp to take production and if you could put periods of months around that, that would be fantastic.

David E. Roberts Jr.

Yeah. I think one of the things, and you all know this as well as I do, particularly in the Gulf of Mexico, the wells tell you how quickly they can wrap up. So we got a fairly judicious ramp up through the second half of the year. But obviously, we’re expecting very good things from these wells. We’ll let them dictate the pace. And we’ll get the production as high as we can, a quick as we can.

Operator

And moving on to Blake Fernandez with Howard Weil.

Blake Fernandez – Howard Weil

Thanks for taking my question. My first question is on Garyville. I’m just trying to see if we can get an idea of specific timing of when the full facility should be online? I believe the previous comment was second quarter that the base facility would be back on for turn around. But I didn’t know if you could provide any more color?

Gary R. Heminger

We’re moving along very well in the turnaround. And we would expect late first quarter to be complete with our turnaround. And as I said, we’re right on scheduled. So you’ll really see in the second quarter a full complement of the base and the new refinery on stream.

Blake Fernandez – Howard Weil

Okay, great. Thanks. And then the second question I had was on the Boc (ph). I believe it’s been awhile since we’ve had an update on IP rates or EURs. And I didn’t know if you could comment on maybe what you’re seeing currently? And then in that regard as well, if you could just talk about any of the type of (inaudible) techniques or dual laterals or different targets that you may be going for out there?

David E. Roberts Jr.

Blake, we really haven’t changed our view. We’re still saying that these wells are going to give up between 300-50,000 barrels a piece. They’re starting to inch up against the top end of that range. And that probably has to do with completion. We’re still talking about 30 day IPs in that 300 barrel a day range. And I think the presentation that we gave in New York in the last year has a pretty fair pipe curve representation of what we think these wells are going to do over time in the areas that we work at.

We continue to look what’s going on in the basement in terms of trends. We’re doing a lot of well work in terms of when we’re going to start back (inaudible) but some dual laterals down. But we still believe that we’re on the cutting edge of completion technology with the fact that we’re doing – and we are seeing some increase in the number of stages. And we’re keeping an eye on that. But right now we’re pretty happy with what we’re doing and have been doing for the last couple of years.

Operator

And moving on to Faisal Khan with Citi.

Faisal Khan – Citi

Good afternoon. First question on Angola, did you guys have any reserve booking during the year from Angola at all?

Gary R. Heminger

Yes, we did.

Faisal Khan – Citi

Okay. I guess I’ll wait for when the full report comes out then to figure out exactly what the exact number was. But was it significant in material?

Gary R. Heminger

I think you can go back to look at the end of 2008 we made the comment Faisal, that there was something in order in the number, something around 40 million barrels that we would have booked had prices been higher. So I can’t tell you that that was the number. I don’t have the number in front of me, quite honestly. But the middle of this month we will put out press release with more detail on that.

Faisal Khan – Citi

Okay. Thanks. On EG and the natural gas production and the L&G output, I think clearly the natural gas production and the L&G output seem to be directly, kind of, moving together. And production in EG seems to have ramped up over the last year to some degree. Just trying to figure out, is that something that will continue into this year where you’ll see production and L&G volumes continue to move up year-over-year or is that – did we kind of see the peak of that production in 2009?

David E. Roberts Jr.

I think last year is probably the limit that you’ll see in terms of rate capacity. And I have some color with that. We had outstanding reliability across our facilities. Basically the Upstream portion was close to 100%. The L&G plant runs at about 95%. Both of those numbers are very good. So 2009 was a great year in delineation of how well the field is going to perform.

And as we’ve said, we got a substantial period of time in terms of years, three, four, five years, of seeing (inaudible) rates. This year, one of the things, and we’ve highlighted this in terms of some of our first quarter guidance. We are going to have a major turnaround in the month of March on the Upstream facility, what we call M&GPL (ph). And we will basically have a facility down February, March for roughly 50% rates. So you will see a declaration in the first quarter. But we expect the overall year to see a return to performance that we had last year.

Gary R. Heminger

On that front, Faisal, you’ll see in the back of the packet we had on the web today, that we give the year estimate for L&G between 5,500 and 6,500 metric tons per day, compared to the full year 2009 of just over 6,600. So there will be some reduction there because of what Dave talks about.

Operator

And moving on, next question comes from Evan Calio with Morgan Stanley.

Evan Calio – Morgan Stanley

Just a follow up on the last question. Is that entirely what accounts for the drop-off from 4Q to 1Q guided production, 400 to 360 at the midpoint?

David E. Roberts Jr.

It is the big driver. We have some of the (inaudible), this and that. But the big driver for our product decline is the turnaround image EPO.

Evan Calio – Morgan Stanley

Okay. That’s great. Second question, Marathon hasn’t historical hedge forward production. At least you picked up the hedges in other acquisitions. Is there a discussion on the deployment of that strategy here and any thoughts there?

Clarence P. Cazalot Jr.

I think we certainly took the view of the markets as we saw prices move well above $80 on a barrel on the (inaudible) side in earlier January. And from our standpoint we saw what we believe was near term weakness. And that’s why you’ll see a good part of our crew hedges concentrated the first half of the year.

It really was just a lock in what we felt were pretty solid prices relative to overall market weakness and particularly focusing on those areas that these prices would benefit.

Evan Calio – Morgan Stanley

I mean, is that something we should expect to see more in price strength? Is it someone related to your 2010 CAP Ex relative to cash flow on a strip basis?

Clarence P. Cazalot Jr.

I think if you look back, this is a rarity for it. We’ve not done this on a routine basis. I think this was a rather unique set of circumstances, more related I think to the volatility we saw in the crude oil markets and the natural gas markets. And concerned about where they might be for the remainder of the year.

I don’t think it’s something that you’re going to see us do on a frequent basis.

Operator

And moving on to Paul Cheng with Barclays Capital.

Paul Cheng – Barclays Capital

This for Dave. Dave, for 2009, if I exclude the oil sand addition for the one time catch up you – (inaudible) or there’s probably somewhere in the mid to high 40%. Of course, we should not look at just one year. But when we’re looking at also the next two year, 2010, 2011, can you tell us that, maybe share with us, what kind of source of reserve addition? Where is the new reserve addition that you may be expecting?

The second question I think is for Gary or maybe it’s for Janet. The first quarter (inaudible) tax benefit seems very high. You have an effective tax rate of 84%. Is that related to the tax credit on the Garyville expansion? Because I initially thought that that is only for the cash tax but not for the reported tax. And if it is not related, then what else that is related to that large tax benefit? And also if (inaudible) we already received the cash on the tax benefit. Thank you.

David E. Roberts Jr.

Thanks, Paul. I’m glad you asked Janet that second question. Because that is way over my head. Your math is very good. Excluding wall sands (ph) we may pose (inaudible) at about 48%. I think importantly if you just looked at the liquid hydro carbon side, which is what we invested in on this past year. That number is close to 95%. So we took a lot of lumps from the gas side, both in terms of price change revisions and really some of our operating costs in terms of not investing heavily in gases we have in the future.

I think what we’re looking at, Paul, is one of the reasons that we said that we’re going to start focusing on the unconventionally. We believe we’ve reached a point where that is going to make some sense. And you’re going to see us exposing more dollars to that. And I do believe that what we talked about is we have a lot of resource potential. And the exposure that we have in the unconventional. And we’re looking for that to be the driver reserves, certainly over the short term. Although we’re still going to – I’ll tell you, we’re going to start over the short terms until we start seeing some of the potential bigger ads from our exploration activity mission and that.

Paul Cheng – Barclays Capital

Thank you, Dave.

Janet F. Clark

And on the income tax, again, as I said earlier, when you have relatively small numbers you can have very small discrete items make a big shift in terms of percentage. And so in fact what happened in the fourth quarter in RMT there was a return to ecru for a state income taxes.

And with regards to the bonus depreciation related to G&E, you’re absolutely right, that is just a cash effect. It is not effect of (inaudible). And we were able to utilize that in 2009. So effectively we’ve gotten the cash benefit of that.

Operator

And the next question comes from Neil McMahon with Sanford Bernstein.

Neil McMahon – Sanford Bernstein

A few questions from me. First of all, just looking at your unconventional Shell position in the US, can you tell us what you’re seeing in the Marcel (inaudible) and the Haynesville and the potential in terms of activity you’re going to focus on this year. And secondly, really around the oil plants in Canada, some of the recent Shell comments seem to suggest that future expansions maybe soft, maybe pushed back a bit. Any clarity there would be great. And if you’re willing to sort third one on the claiming of your Indonesian exploration wells that would be fantastic for this year.

Clarence P. Cazalot Jr.

I guess I can handle all of these things. I think we’ve probably covered the (inaudible) quite a bit. One of the things that we had said in our presentation is we (inaudible) the well in our Haynesville position. We believe our efforts in the Haynesville there while a small number certainly, is in the developing fairway in Shelby County. And I think you’ll see us do two, possible three wells on that acreage. Again, we’re going to be very judicious as we watch gas price. Because we’re a little bit concerned about that

And we’ve got four wells down in the Marcel. We’ll drill probably a dozen more this year. We got our first crack away. And we’re looking at well casts. And I think you’ll see us pursue that play very similar to how we did the Bach, in terms of being measured, getting our technical data before we get serious about it.

But early indications are in terms of what we’ve seen from the jobs, we like it. We have 70,000 acres there and I think we’ll continue to play against that. So we feel very good about where we are.

I guess the third one that we talked about is Afadafa (ph) Woodford, or what’s commonly be known as the (inaudible) now in the western part of Oklahoma. We’ll drill again probably a dozen wells there during the course of this year. We’ve got our best well to date just completed a little bit over 10 million cubic feet a day. A well that we have substantial interest in. So that probably will look like it’s going to continue with that up.

So as we suggested, we think we have some pretty good exposure and believe that it may be time to move forward in a lot of these plays. But again, we’ll do it in a way that’s consistent with the current market economics.

Offhand, I think what we would say, and certainly very respectful of Shell (inaudible) what we would say is they’re not herbalizing (ph) what we’ve been saying for some time about this play. So we’re very happy with the position that we have in Afadafa. There’s very few fields that we’re aware of that are certainly within the control of western ICs that as this one could produce – pick a figure between 750,000 and a million barrels a day. But we believe that those future expansions have to be done in an efficient manner. And we also believe that one of the strengths of partnership between American and Shell and Chevron is the ability to apply technology there to further enhance the economics.

So the rhetoric out of Shell in terms of making sure that we’re making the right investment we’ve choice, we could do very consistent with what we said about let’s utilize the existing capacity to its fullest. The micro expansion concept. Let’s improve the reliability, let’s log the economics away, three world class companies like ours should be. We don’t consider that to be out of the frame of what we’ve been talking about. This is (inaudible) at all.

The last question Indonesia will drill two wells this year. The expiration rate that we contracted is product consortium is – soon to be delivered. We’ll drill our first well probably in April and the second towards the latter part of the year.

Neil McMahon – Sanford Bernstein

Great. Thanks.

Operator

And we’ll take the next question from Pavel Molchanov with Raymond James.

Pavel Molchanov – Raymond James

Two quick things, first if you could just give us an update on the asset sale in Angola?

Clarence P. Cazalot Jr.

We’re close. What we said it’s very close.

Pavel Molchanov – Raymond James

Okay. Any sense of the timing on when the final step will be taken care of?

Clarence P. Cazalot Jr.

We’re close, very close.

Pavel Molchanov – Raymond James

Okay. Got it. And then on the three or four operated wells for the goals that you mentioned you’ll work on this year. Can you give us a sense of some pre drilled resource estimate if you have any?

David E. Roberts Jr.

Yeah. Pavel, I’d refer you to the analyst presentation that we did in New York. I think we were pretty up front on the wells that we’re talking about, Flying Dutchman, Haynesbrook, Monikia (ph) and roughly typical (inaudible) targets between 75-150 million barrels gross. And we were very upfront about what our working interests are and how that’s going to flow. So that would probably be the easiest way to answer your question. But everything we look at is probably starts at 100 million barrels and then whatever our interest is.

Clarence P. Cazalot Jr.

And Pavel, the one we’re drilling right, as Dave talked about, the Flying Dutchman, we’re 63% working interest. And on a gross basis, the un-risk potential is 100-200. So it’s towards the upper end of what Dave was talking about. The other ones are mostly in the 80-150 type of number.

Operator

And the next question comes from Robert Kessler with Simmons & Company.

Robert Kessler – Simmons & Company International

You kindly reiterated your comfort with the numbers you presented in the analyst meeting. And I’m assuming part of that’s your comfort that the 4.9-5.6 million per well drilling and facility costs is still applicable, particularly with the efficient gain you’ve seen so far.

My question is more one of as you guys get more aggressive in the play and others do the same, at one point do you look a little longer term and lock in some long term service and drilling contracts?

David E. Roberts Jr.

Well, Robert, it’s a great question. We are very comfortable with where we find ourselves in terms of the drilling and completion costs that we’ve referenced in the past. And I think that’s one of the reasons that we’re very sensitive to not running away with ourselves in terms of details in the display. 90 rigs up in the Balkan as of today. And that’s getting pretty close to what we’ve seen as the functional limit in that basin. We have a very long term relationships with (inaudible) Partner and expect to have the capacity for rigs at what we think are going to be competitive prices for some time.

And we continue to look at similar type of relationships for our pumping services. So we’re comfortable with – Marathon is not going to be caught out in a hyperization environment in that particular play.

Robert Kessler – Simmons & Company International

Okay. And you’d stick with sort of four rigs then for the foreseeable future?

David E. Roberts Jr.

You may come out a little bit late –

Robert Kessler – Simmons & Company International

Oh, I’m sorry. Adding two more, I guess. But then moving to six and staying at six then and not moving beyond that. I guess, kind of, if other people already moving to grab a few more, isn’t there a risk to (inaudible) if you’re increasing the rig count?

David E. Roberts Jr.

I would say that that certainly a possibility. I will also tell you that a lot of the vendors, and particularly the service company that we work with, like doing business with us, and we may indeed increase – we’ll do what we have to in order to execute the play appropriately.

As you know we’ve run eight rigs up there before. So it’s not in uncomfortable place for us. And we believe the industry has the capacity to satisfy our needs.

Operator

And we’ll take the next question from Kate Lucas from Collins Stewart.

Kate Lucas - Collins Stewart

I have a question on your oil sand, actually two part question. I understand from yesterday’s CAP Ex release that you’ll be changing the way that you disclose your production numbers for oil sands. And I wanted to know if you could give a senses to what the 4Q production number would have been had your reported the bitumen, after upgrading but excluding (inaudible) stocks. And how would your realizations and also your cost numbers have been different. And if you could give the cost numbers on the as reported basis, that would be helpful too. Thank you.

David E. Roberts Jr.

I think in our release we actually did report it in the way you suggested. So fourth quarter bitumen 26,000 barrels a day consistent with how we’ve done it in the past. Basically, we reflect those figures. And we said is the FDA figures for next year are going to be 22-28. And I think the easiest way to look at that is it’s roughly a 2% difference on the way it’s been – as you calculate that.

Clarence, do you want to add?

Clarence P. Cazalot Jr.

I want to add the sleeve report today on production, both the bitumen and the synthetic crude oil sales, in fact, on Page 6 of our earnings release at the top of the page are the synthetic crude oil sales. So that’s what you’re looking for. I think the change you’re talking about is what we report the Canadian oil sand reserves we report them on a synthetic basis. And that’s the change that we have.

Kate Lucas - Collins Stewart

Okay. So the production number then remains consistent with what we’ve seen in prior quarters?

David E. Roberts Jr.

Yes. And we report those. We report bitumen and synthetic sales.

Operator

And the next question comes from Mark Gilman with the Benchmark Company.

Mark Gilman – Benchmark Company

Couple of things, there’s reference in the release to your having obtained 90,000 a day at all time, in the month of October. I’m curious whether you consider, Dave, it prudent and taking into consideration the additional capacity available at Volan (ph) to try to sustain that kind of level?

David E. Roberts Jr.

Pretty simply, Mark, again, I’m controlling the (inaudible) wells will tell you what you can do. We’re facility constrained. And that 90,000 barrels number remember is a net. And so we’re well above what we designed capacity of the FDFO was. But we do not produce any of our field to damage our reservoirs. We believe that we product the wells in the fashion that maximizes the value to all the stakeholders, including the (inaudible). But also maintains the ability the reservoirs produce through a useful line.

Mark Gilman – Benchmark Company

Dave, I’m not sure what you told me.

David E. Roberts Jr.

Well, Mark, I think what we do is – we’re not operating any gross in a way that’s damaging the reservoir. And so we believe that the rates that we’re pulling are consistent with prudent operating factors.

Operator

And the next question comes from Jason Gamel with McCorey (ph).

Jason Gamel - McCorey (ph)

I just wanted to follow up on the Downstream guys. Obviously wide heavy differentials have been pretty compressed for quite a while now. Could you talk about in general how you see the light heavy differential potentially expanding, when or if you expect it to expand? And then specifically, the decision before with the Detroit project, is that dependent upon (inaudible) differentials moving out again or is it purely a function of where you’re at on the pipeline system and maybe some contractor costs actually coming down in the current environment?

Gary R. Heminger

First of all, light heavy differentials and your very clear that they have been depressed for some time. And our numbers, we were just under $6 for 2009, looking at a whole basket of crudes versus twice that in 2008. And your question looking out when do we think that they will widen back out? Our belief is it’s all depending on diesel demand. As diesel demand increases around the world, is when you will see (inaudible) desalt to resist spread widen out. And with that you will have more medium to heavy crudes come back on the market. More competition for those crudes. And you should start to see the differential widen out.

We’ve had in the fourth quarter looking at the American Trucking Association, looking at some railroad loadings, you’re starting to see some pick up in diesel. Our last couple of weeks then it got a little bit soft. But it all depends on where you are in the regions of the country. We do expect that as the economy starts to restock we expect to see that more than likely in the second half of the year. But I say, we believe we’ve hit the allure on the client and diesel demand and are starting to see some improvement.

As far as Detroit, again, your right on target that we’re looking at the Detroit project clearly as a lower feedstock cost into the plants. That’s what’s driving economics. It’s not an expansion of the refinery, per say. We’ll have a little bit of expansion. But it’s really a drive in the cost.

And what you’re seeing right now across the whole Canadian corridor of crudes, is that you’re seeing the Keystone pipeline soon to be starting to have line fill going in somewhere 80,000-90,000 barrels to day.

Following that, you’ll have Southern Access, with some line fill that is expected. And it’s going to be a big haul for the first half of this year on the Canadian oil, either being conventional or none conventional to fill up those pipelines.

That’s what some – as Dave just mentioned, the turnaround we have coming at ALSB, some other producers in the marketplace that have had some difficulty and some operational issues. You’re seeing a pretty strong market for the oil sands, both bitumen and synthetic today.

We would expect though, as we get those pipelines filled, then is when you’re going to see the producers and those that have put the barrels into the pipeline looking for a home, looking for a refinery for those barrels.

Again, second half of the year. I’d say starting the third quarter is when you’re going to start to see that Canadian spread start to widen back out. Which is right in strategy with our Detroit project.

Jason Gamel - McCorey (ph)

That’s very helpful, Gary. Thank you very much.

Operator

And we’ll take the next question from Faisel Khan with Citi.

Faisel Khan – Citigroup

Just two follow ups. First, US gas production, I guess has declined ’08 into ’09. I was wondering if you could comment on whether you think your unconventional gas assets that you guys are drilling on right now could arrest that decline and stabilize production then.

David E. Roberts Jr.

The answer is yes, it can. And the issue will be how much we invest in that relative to the pricing up in the market place. In the low products we’re still going to be pretty prudent. But we certainly believe that the acreage that we have should replace continue to act the way they have for us. There is no question that they can make up for what we lose.

Faisel Khan – Citigroup

Okay. The last question, given your best cash position and I guess pending asset sale, what is your plan and what do you want to do with the proceeds and what’s your appetite for acquisitions?

Janet F. Clark

Well, I guess I’ll start off and probably Clarence will want to jump in. Our priority is really unchanged in terms of cash. We want to reinvest in the business and (inaudible) of projects. So we’ll be continuing to look for opportunities to invest in the business. But given the financial instability that we’re seeing over the last year in terms of the economy and in the financial markets, the credit market. I think that we’re going to maintain a very conservative balance sheet that will give us a lot of financial flexibility going forward.

But another component that is important to us is (skip in audio) return is of course is the dividend. And that’s something that we do look at quarterly with our board. And so it continues to be that same general sequence of priorities in terms of cash.

Clarence P. Cazalot Jr.

And as far as I would just say consistent with the priorities Janet’s just laid out, we continue to look very selectively at building bigger positions in some of the key plays and trends that Dave talked about earlier. But that’s really where our growth will come from, it’s certainly increasing our exposure to those areas where we have demonstrated operational and technological cost advantage.

Operator

(Operator's Instructions) And the next call comes from Paul Cheng with Barclays Capital.

Paul Cheng - Barclays Capital

Hi, thank you. I think this must be for Dave. At the end of 2009, from an inventory standpoint, are you still over (inaudible)?

David E. Roberts Jr.

As Howard mentioned, we have a substantial amount of inventory in gas in Alaska and a similar position in Norway and slightly under-lifted in EG.

Paul Cheng - Barclays Capital

Okay, so that is actually what Howard says is your year-end position.

David E. Roberts Jr.

That is correct.

Paul Cheng - Barclays Capital

Okay, and also, any update you can provide about (inaudible) I don't think you guys have talked too much over the last two years. Any development or progress in terms of development as well as exploration that will lead to a higher production over the next one or two years, or will it still be two or three years down the road before we are going to see any visible (inaudible)?

David E. Roberts Jr.

We continue to be very encouraged by our (inaudible) business and it is certainly a place that we are active in. We are expecting the fair gas project to be delivered in the beginning part of 2011 and as you know we are in the midst of pre-bid activities for two of the other substantial development projects in the country but Marchiallo and the other NG 98 recycle gas projects.

A lot of big project opportunities but I think importantly Marathon and its partners continue to build capability in the country and we believe in and literally are in discussion this week with the government about what we think the development potential is from existing production here. We're getting a very positive and receptive audience because of the performance that we've had over time. So we continue to be encouraged that Libya offers us a tremendous production growth platform. I think the only thing that I would say, and Paul you've followed this story for as long as we've been over it for the last five years. It's going to come at a little more of a measured pace than we had previously predicted but we do believe that is one of the few places in the world where you can see multi-hundred thousand barrel increments possible, from what our position is. We're in a very good (inaudible).

Operator

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

Mark Gilman - The Benchmark Company

For Gary Heminger. Gary can you give me an idea of what the start up costs were on the Garyville expansion buried in the fourth quarter numbers?

Gary Heminger

Let me turn that one over to Gary Piper, he has a better handle on that than I.

Gary Piper

we incurred about $50 million or so pretax of depreciation and salary burden and some variable costs in the fourth quarter, so after tax probably about $30 million or so.

Mark Gilman - The Benchmark Company

Okay. Gary Heminger can you give me an idea of what you did in 2009 in terms of whether you were a buyer or a seller of rims and to what dollar amount and how that might change in 2010?

Gary Heminger

Gary, do you – I don't have that data close by – do you by chance Gary?

Gary Piper

Yeah, specifically we've been in pretty good shape from a rims standpoint. We've been a seller of rims. We expect that we will be able to continue to meet our requirements for rims at least through 2011. So we've been selling rims, I guess at this point we haven't divulged how much for competitive purposes but we've been a met seller and we expect to be for the next year or so.

Operator

And the next question comes from Doug Leggate with Merrill Lynch.

Doug Leggate - Merrill Lynch

Sorry for the follow-up folks, but I just wanted clarification on a couple things if I may. Just looking at your guidance numbers as Nicole was going on here. Can you just explain again – I don't know if you touched on this – but why is the international gas production down so much sequentially Q1 versus Q4 for 2009?

Clarence P. Cazalot Jr.

We're taking a forty day turnaround that you should basically be able to think about as a 50% reduction in capacity in any GPL (ph) in late February and all of March. So that's the driver there.

Doug Leggate - Merrill Lynch

Okay but if I look at the guidance, you know, pretty much running down the list of the regions that you've split out. Pretty much everything is down sequentially. I'm assuming it's not maintenance and only assets. Is this underlying decline we're looking at? Again, more clarity would be appreciated.

Clarence P. Cazalot Jr.

I guess we can at least agree that the numbers look unusual. There are some sequential declines. We do normally in the United States towards the end of the quarter start to see some issues around Alaska in terms of sales versus injections, so that may be part of it. Normal decline in the Gulf of Mexico but the big driver is the turnaround in EG.

Operator

And that does conclude the question and answer session. I'll now turn the call back over to you.

Howard J. Thill

Thank you to all the investors and analysts listening to us, and we look forward to visiting with you in the coming quarter out on the road and in our offices. Until next quarter, take care.

Operator

That does conclude today's conference. Thank you for your participation today.

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Source: Marathon Oil Q4 2009 Earnings Call Transcript
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