馬拉松石油 (MRO) 2009 Q4 法說會逐字稿

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. Please go ahead, sir.

Thanks, Justin, and I, too, would like to welcome each of you to Marathon Oil Corporation's fourth quarter 2009 earnings webcast and teleconference. 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, Marathon Executive Vice President Downstream, Dave Roberts, Executive Vice President Upstream, and Gary Peiffer, Senior Vice President of Finance and Commercial Services Downstream. Slide two contains the forward-looking statement 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 Private Securities Litigation Reform Act of 1995, Marathon Oil Corporation has included in its annual report on form 10-K for the year ended December 31, 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 to slide three, during the fourth quarter, our 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. And while this is a number rarely, if ever, taken into account in analyst estimates, I would 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 noncash swing in deferred tax balances. And we expect to make a onetime election during the first half of 2010 to begin paying Canadian income tax in US 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 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 as a 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 FX 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 FX, 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 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 sales volumes 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 cost per BOE of 15%, excluding production taxes and DD&A, while we also reduced operating costs 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 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 for BOE increased $5.88 quarter over quarter, while the same period NYMEX prompt WTI increased $7.89 per barrel. And the bid week natural gas price increased $0.77 per million BTU. 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 volumes versus available for sale volume was the result of an overlift of approximately 900,000 BOE for the quarter. We ended the year with a two date underlift position of 3.3 million BOE consisting of 2.6 million BOE of gas storage in Alaska, an underlift position in EG of about 500,000 barrels, and approximately 200,000 barrels underlifted in Norway.

Slide nine shows the trend over the last eight quarters for field level controllable cost 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 and lower domestic DD&A. Excluding exploration expense and DD&A, total cost per BOE were relatively flat at $9.90. Turning to slide 11 and oil sands mining, fourth quarter segment income increased over 60% from the third quarter -- 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 12 and integrated gas, fourth quarter segment income almost tripled compared to the third quarter of -- on stronger LNG prices, while higher LNG volumes and methanol prices also contributed to the increase. As noted on slide 13 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 Bakken and almost -- an increase of almost 40% from the 2008 exit rate and we achieved first oil at Volund 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 a 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 14, 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'll compare our fourth quarter 2009 results against the same quarter of 2008. Our average wholesale price realization 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 approximately $10 per barrel.

Partially offsetting these negative effects are actual crude oil and other feedstock 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 contango. Also, manufacturing and other expenses were lower in the fourth quarter 2009 compared to the fourth quarter 2008, primarily due to lower energy and lower turnaround costs. Total refinery crude oil throughput 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 throughputs 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 the fourth quarter 2008.

The majority of this decrease was due to lower gasoline and distal margins, which decreased about $0.08 per gallon quarter to quarter. We did, however, achieve a 10% quarter to quarter increase in SFAs same store merchandise sales, while same store gasoline volumes decreased 2% quarter to quarter. We estimate demand in SSH primary market area also decreased by about 2% quarter to quarter. Slide 15 provides historical performance indicators for the downstream business and previously discussed LLS 6321 crack spread. Slide 16 provides a preliminary analysis of cash flows for 2009. Operating cash flow from 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 totaling $679 million and generated proceeds from assets disposed of in the amount of $865 million. And I'll 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 at year-end 2008 to just over $2 billion. Slide 17 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 2 percentage points from the third quarter and, as a reminder, this debt includes approximately $340 million serviced by US Steel. Slide 18 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 play 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 and about 22% of our Companywide $5.1 billion 2010 projection, includes progressing construction on the Detroit heavy oil upgrading facility, which is approximately 30% complete. After an extensive turnaround of the base Garyville refinery in the first quarter, we anticipate the combined 436,000 barrel per day refinery will turn to 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 19, you will find details of the derivative positions we've entered, which are designed to manage price risks 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 2010.

Additionally, positions taken for only the first half of 2010 relate to approximately 20% of full year crude sales in the US and in Norway. These derivative positions do not qualify for hedge accounting. We will now open the 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 reprompt for additional questions as time permits. With that, Justin, I'll turn it back to you.

(Operator Instructions). And the first question comes from Doug Leggate with Merrill Lynch.

Thank you. Good afternoon, everybody. Couple of things. I'll try and keep it to two. I guess the first one is on the exit rate on the Bakken, clearly a 40% increase year-over-year. But your target, of course, is 15,000 barrels a day by, I guess, 2013. Can you just help us reconcile the pace of growth in 2009 and why for such a high margin asset in terms of IRR you wouldn't get a little more aggressive given the cash flow, I guess, the cash flow you're going to see from Garyville and of course the proceeds from Angola. So a little more aggressive on the Bakken, why not is the question and then I have a follow-up.

Good afternoon. Clarence and I are out of the country so I hope you can hear us. Great question and not unexpected, but we did have a very good year in the Bakkens pushing 11,000 barrels a day. As you may be aware, we have gone from three to recently four rigs there. We have 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. We are going to probably pick up another couple of rigs throughout the year. But again, we're pretty consistent what our view you can do in terms of rate times well in that particular play. But I think you'll see us become a little bit more aggressive this year as we move forward.

Dave, thanks for that. Does that mean the 15,000 barrels a day number has some upside risk.

I'm not sure the term upside and risk go together. But we continue to be encouraged with what we see in the play. I think (audio difficulties) one of the things that we say being exposed to 350,000 plus acres, we do think that there's more upside in the play. But we're going to continue to do it --

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

Hopefully we haven't lost our --

He disconnected from the conference sir, actually.

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

I was just curious, it looks like the tax rate in the US was very low in the quarter and I was hoping you could give me some clarification and I'll leave it there before I get cut off or something.

We won't cut you off, Doug.

Ok, in the fourth quarter, as usual, we had a variety of the three 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 discreet items have a bigger impact on the overall affected tax rate. So, it really is nothing major. There was some returns to accruals from state income tax was the biggest item. And that was a positive. That was a benefit.

Got it. All right. Thanks, Janet.

Thanks, Doug.

And moving on, the next question will come from Jason Gammel with Macquarie.

Thank you. I want to stay on the same of the unconventional resource and the acreage position you established in Poland, can you talk a little bit about lease terms there. I really thinking more in terms of how long you would be able to hold the 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 on 2010 but in 2011 and 2012.

Jason, I think it is still very early days in Poland. We're very excited now to cross the 800,000 acre level in that play. Very early days for us. I think the easiest way to describe the lease terms 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 commitment and so that's part of it. But the initial phases, certainly the first year, it can be dedicated to study. I think our view is that we could potentially see well activity in 2011and I wouldn't expect us to field anymore than one possibly two rigs. Okay, that's useful

And then maybe as my second question, we're expecting Droshky 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 peak production and if you can put periods of months around that, that would be fantastic.

Yes, 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 ramp-up. So, we've 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 as quick as we can.

And moving on to Blake Fernandez with Howard Weil.

Afternoon, guys, 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 on-line. I believe the previous comment was second quarter that the base facility would be back on from turnaround, but I didn't know if you could provide any more color.

Blake, this is Gary. 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 say, we're right on schedule. So, you'll really see in the second quarter a full complement of the base and the new refinery on stream.

Ok, great, thanks. Then, the second question I had was on the Bakken. I believe it has 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 frac techniques or dual laterals or different targets that you may be going for out there.

Blake, we really haven't changed our view. We're still saying that these wells are going to give us between 300,000 and 350,000 barrels apiece. 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. I think the presentation that we gave in New York in the last year has a pretty fair tight curve representation of what we think these wells are going to do over time in the area that we work at. We continue to look at what's going on in the basin in terms of trends. We're doing a lot of well work in terms of when we're going to start to actually put some dual laterals down. But we still believe that we're on the cutting edge of a completion technology with the fracs that we're doing. And we are seeing some increase in the number of stages and we're keeping on 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.

And moving on to Faisel Khan with Citi.

Good afternoon. Hi, Faisel. Hi. First question on Angola, did you guys have any reserved bookings during the year from Angola at all?

Yes, we did.

Yes we did.

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 or material?

Well, I think you can go back to look at the end of 2008, we made the comment, Faisel, that there was something in the order of, and the number escapes me, but 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'll put out a press release with more detail on that.

Ok, great. Then on EG and the natural gas production and the LNG output, I think, clearly, I think the natural gas production and the LNG 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. I was trying to figure out is that something that will continue into this year where you'll see production and LNG volumes continue to move up year-over-year or is that -- did we kind of see the peak of that production in 2009?

I think last year is probably the limit that you'll see in terms of rate capacity and add some color to that, we had outstanding reliability across our facilities. Basically, the upstream portion was close to 100%. The LNG plant runs at about 95%. Both of those numbers are very good. So 2009 was a great year to get an indication on how well this field is going to perform. As we've said, we got a substantial period of time in terms of years, three, four, five years of seeing plateaus at these 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 MEGPL. We will basically have a facility down February, March for roughly 50% rate. So, you will see a declination in the first quarter, but we expect the overall year to see a return to performance that we had last year.

On that front, Faisel, you'll see in the back of the packet we have on the web today, that we give the year estimates for LNG at between 5500 and 6500 metric tons per day compared to the full year 2009 of just over 6600. So, there will be some decline, some reduction there because of what Dave talks about.

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

Hi, good afternoon, guys.

Hi, Evan.

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

Yes, it is the big driver. We have some declines, this and thats, but the big driver to our production decline is the turnaround in MEGPL.

Okay, that's great. A second question, Marathon hasn't historically hedged forward production. At least you picked up hedges in other acquisitions. Is there any discussion on the deployment of that strategy here? And any thoughts there?

Even, this is Clarence. I think we certainly took a view of the markets as we saw prices move well above $80 a barrel on the crude 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 crude hedges concentrated in the first half of the year. But it really was just to 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.

Is that something we should expect to see more in price strength or is it somewhat related to your 2010 CapEx relative to cash flow on a strip basis?

No, I think if you look back, this is a rarity for us. 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 concern about where they might be for the remainder of the year. I don't think it is something that you're going to see us do on a frequent basis.

And moving on to Paul Cheng with Barclays Capital.

Hi, good afternoon. Then maybe this is for Dave. Dave, for 2009, if I exclude the oil sand addition for the one-time catchup. We saw replacement rate so it is probably somewhere in the mid to high 40%. If I look at, of course that mean we should not look at just one year. But when we're looking at over the next two years, 2010, 2011, can you tell us that maybe share with us what kind of source of new reserve addition, where is the new reserver addition that you may be expecting? The second question I think is for Gary or maybe it is for Janet. The fourth quarter R&M tax benefit seems very high. You have an effective tax rate of 84%. Does that relate to the tax credit on the Garyville expansion, because I initially thought that is only for the cash tax but not for the reported tax. And if it is not relate to that, what else that is related to that large tax benefit. And also you have (inaudible) that we already received the cash around the tax benefit. Thank you.

Ok. Thanks, Paul. Glad you asked Janet that second question because that's way over my head. Yes, your math is very good. Excluding the oil sands, we make our reserve replacement at about 48%. I think importantly if you just look at the liquid hydrocarbon side, which is what we invested in this past year, that number is close to 95%. So we took a lot of lumps on the gas side, both in terms of price change revisions and really some of our operating philosophies in terms of not investing heavily in gas as we had 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 unconventionals, we believe we've reached a point where that is going to start to make some sense.

And you are going to see us exposing more dollars to that. And I do believe that what we have talked about is we have a lot of resource potential in the exposure that we have in the unconventionals. We're looking for that activity to drive our reserves, certainly, over the short-term, although we're still going to -- I will tell you, we are going to struggle over the sort-term until we start seeing some of the potential bigger adds from our exploration activity this year and next.

Thank you, Dave.

And, Paul, on the income tax, again as I said earlier, when you have relatively small numbers, you can have very small discreet items make a big shift in terms of percentage. And so, in fact, what happened in the fourth quarter in RM&T, there was a return to accrual for estate income taxes. And with regard to the bonus depreciation related to GME, you're absolutely right, that is just a cash effect. It does not affect our book taxes. And we were able to utilize that in 2009. So effectively, we've gotten the cash benefit of that.

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

Hi, 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 Marcellus and on the Haynesville and the potential in terms of activity you're going to focus on this year. Secondly, really around the oil sands in Canada. Some of the recent Shell comments seem to suggest that future expansions may be re-thought, may be pushed back a bit. Any clarity there would be great. And if you're willing to throw at a third one, on the timing of your Indonesian exploration would also would be fantastic for this year.

Ok, great. I guess I can handle all of those things. I think we probably covered the Bakkens quite a bit. One of the things that we had said in our presentation is we spudded a well in our Haynesville position. We believe our acreage in Haynesville there, while a small number, certainly is in the developing fairway in Shelby County and I think you'll see us do two, possibly three wells on that acreage. Again, we are going to be very judicious as we watch gas prices. We're a little bit concerned about that. We have got four wells down in the Marcellus. We'll drill probably a dozen more this year. We've got our first frac away and we're looking at well tests and I think you'll see us pursue that play very similar to how we did the Bakken 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 through geology, we like it.

We have 70,000 acres there and I think we'll continue to play against that. So, feel very good about where we are. I guess the third one that we've talked about is Anadarko Woodford or what's commonly being known as the Cana play, 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. It just completed a little bit over 10 million cubic feet a day, a well that we have a substantial interest in. So, that one, that play looks like it is going to continue to develop. So as we've 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 is consistent with the current market economics. Oil sands I think what we would say and certainly very respectful of Shell operator, what we would say is they're now verbalizing what we've been saying for some time about this play, that we're very happy with the position that we have in Athabasca.

There's very few fields that we're aware of that are certainly within the control of western isle seas that, as this one, could produce, pick a figure between 750,000 and 1million 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 the partnership between Marathon, 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 decisions we think is very consistent with what we said about let's utilize the existing capacity to its fullest, the microexpansion concept. Let's improve the reliability and let's drive the economics the way three world-class companies like ours should do. So we don't consider that to be out of the frame of what we have been talking about this partners at all. The last question Indonesia we'll drill two wells this year. The exploration rig that we contracted as part of consortium is soon to be delivered. We'll drill our first well probably in April and the second toward the latter part of the year.

Great, thanks.

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

Thanks, guys. Two quick things. First can you just give us a update on the asset sale in Angola?

We're close, very close.

Okay.

What we said is it is very close.

Okay, any sense of the timing on when the final stuff will be taken care of?

We're close, very close.

Okay. Okay, got it. And then on the three or four operated wells for the gulf that you mentioned you'll work on this year, can you give us a sense of some predrill resource estimates if you have any?

Pavel, I'd refer you to the analyst presentation that we did in New York, because I think we were pretty up-front on the wells that we're talking about, Flying Dutchman, Innsbrook, Monekia, and it's roughly typical myrcene targets between 75 and 150 million drill gross and we were very up-front about what our working interests are and how those things look. So, that would probably be the easiest way to answer your question. But everything we look at probably circa 180 barrels and then whatever our interest is.

Pavlov, the one we're drilling right now, as Dave talked, the Flying Dutchman. We're 63% working interest and on a gross basis the unrisk potential is 100 to 200. So it is towards the upper end of what Dave was talking about. The other ones are mostly in the 80 to 150 type of number.

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

You've kindly reiterated your comfort with the numbers you presented in the analyst meeting and I am assuming part of that is your comfort that the 4.9 million to 5.6 million per well drilling and facility cost is still applicable, particularly with the efficiency gains you've seen so far. But my question is more one of as you guys get more aggressive in the play and others do the same, at what point do you look a little longer term and lock in some long-term service and drilling contracts?

Well, Robert, it is 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 enthusiasm for this play. There's 90 rigs up in the Bakken 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 relationship with our drilling 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 the similar type of relationships for our pumping services. But we're comfortable that Marathon is not going to be caught out in a hyperinflation environment in that particular play.

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

You may have come on a little bit light.

Adding two more, I guess, but then moving to six and staying at six then and not moving beyond that. I just kind of -- if you're -- if other people already moving to grab a few more, isn't there a risk you're late if you're increasing the rig count?

I would say that that's certainly a possibility. I will also tell you that a lot of the vendors and particularly the service companies 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 and so it is not an uncomfortable place for us and we believe the industry has the capacity to satisfy our needs.

And we'll take a next question from Kate Lucas with Collins Stewart.

Hi, good afternoon. I have a question on your oil sands, actually two-part question. I understand from yesterday's CapEx release that you'll be changing the way that you disclose your production numbers for oil sands. I wanted to know if you could give us a sense as to what the 4Q production number would have been had you reported the bitumen after upgrading but excluding blend stocks and how would your realization 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.

Ok. I think in our release, we actually did report it in the way you suggested. Fourth quarter bitumen 26,000 barrels a day consistent with how we've done it in the past.

Basically, we reflect those figures and what we've said is the SCO figures for next year are going to be 22 to 28. I think the easiest way to look at that is it is roughly a 2% difference on the way that you calculate that. Clarence, you want to add something?

Yes, just I would add, Kate, we report today on production both the bitumen and the synthetic crude oil sales. In fact, on page six of our earnings release at the top of the page are the synthetic crude oil sales. So that is what you are looking for. I think the change you're talking about is when we report the Canadian oil sand reserves, we report them on a synthetic basis. And that's the change that we have.

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

Exactly and we report those. We report bitumen and synthetic sales.

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

Good afternoon, folks. Couple of things. There's reference in the release to your having attained 90,000 a day at Alvheim in the month of October. I'm curious whether you consider, Dave, it prudent and taking into consideration the additional capacity available at Volund to try to sustain that kind of level.

Well, pretty simply, Mark, again, I'm telling you the wells will tell you what you can do. We're facility constrained there and that 90,000 barrel number remember is a net. And so we're well above what the design capacity of the FPSO was. But we do not produce any of our fields to damage the reservoirs. We believe that we produce the wells in the fashion that maximizes the value to all of the stakeholders, including the stake there, but also maintains the ability of the reservoirs to produce (inaudible) useful life.

Dave, I'm not sure what you told me.

Look, Mark, I think what we do is -- we're not operating these wells in a way that is damaging the reservoir. And so, we believe that the rates that we're pulling are consistent with prudent operating practice.

And the next question comes from Jason Gammel with Macquarie.

I just wanted to follow up on the downstream, guys. Obviously, light heavy differential's been pretty compressed for quite awhile 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 light heavy differentials moving out again or is it purely a function of where you're at on the pipeline system and maybe some contract for costs actual coming down in the current environment?

Yes, Jason, first of all the light heavy differentials and you're very clear that they have been depressed for some time. And our numbers, we were just under $6 for 2009 looking at our whole basket of crudes versus twice that in 2008. And your question looking out, when do we think that they'll widen back out. Our belief is it is all depending on diesel demand. As diesel demand increases around the world is when you will see the (inaudible) sulfur diesel to resid spread widen out and with that, you'll 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. So we've had in the fourth quarter looking at the American Trucking Association, looking at some railroad loadings, you've started to see some pickup in diesel the last couple of weeks. Then it got a little bit soft. But it all depends on where you are, the regions of the country.

We do expect that as the economy starts to restock we expect that, to see that more than likely though in the second half of the year. But as I say, we believe we've hit the floor on the decline in diesel demand and are starting to see some improvement. As far as Detroit, again, you're right on target that we're looking at the Detroit project clearly as a lower feedstock cost into the plant. That's what's driving the economics. It is not an expansion of the refinery per se. We'll have a little bit of expansion, but it is 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 at somewhere 80,000 to 90,000 barrels per day. Following that, you'll have southern access with some line fill that's expected. And it is going to be a big call for the first half of this year on the Canadian oil either being conventional or nonconventional to fill up those pipelines.

That with some, as Dave just mentioned, the turnaround we have coming at AOSP, 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 would say starting the third quarter is when you're going to start to see that Canadian spread starting to widen back out, which is right in strategy with our Detroit project.

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

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

Thanks, guys, just two follow-ups. First, US gas production, I guess, has declined '08 into '09. I'm wondering if you could comment on whether you think your unconventional gas assets that you guys are drilling on right now can arrest that decline and stabilize production there.

The answer is yes, they can. And the issue will be how much we invest in that relative to the pricing that's in the marketplace. In the low 5s, we're still going to be pretty prudent. But we certainly believe that the acreage that we have should these plays continue to act the way they have for us, there is no question that they can make up for what we are losing.

Okay. And last question, given your guys' cash position and, I guess, a pending asset sale, what is your plan on what you want to do with the proceeds and what's your appetite for acquisition?

Well, I guess I'll start off and I think Clarence will probably want to jump in. Our priority is really unchanged in terms of cash. We want to reinvest in the business and value accretive projects and so we'll be continuing to look for opportunities to invest in the business. But given the financial instability that we've seen 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 the, of total shareholder 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.

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

(Operator Instructions). And the next question will come from Paul Cheng with Barclays Capital.

Hi and thank you. I think this must be for Dave. Dave, at the end of 2009, just inventory, from an inventory standpoint are you guys still overlift or just neutral?

As Howard mentioned, we have a substantial amount of inventory in gas in Alaska. We're in a similar position in Norway and slightly underlifted in AG.

So that is actually what Howard say is a year-end position.

That's correct.

Ok. And also, any update you can provide about Libya. The only thing you guys have talked too much over the last one or two years. Any development or progress in there in terms of development as well as exploration fund that would lead to higher production over the next one or two years or that this is still two or three years down the road before we're going to see any visible benefit.

We continue to be very encouraged by our Libya business and it's certainly a place that we are active in. We're expecting the fair gas project to be delivered in the beginning part of 2011. And as you know we're in the midst of pre-feed activities for two of the other substantial development projects in the country, the North Gealo and the NG98, NC98 recycle gas project. So, a lot of big projects opportunities. I think importantly, Marathon and its partners continue to build capability in the country and we believe and literally are in discussions 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 followed this story for as long as we've been over it for the last five years, it is going to come at a little more measured pace than we had previously predicted. But we do believe it is one of the few, again, one of the few places in the world where you can see multi-hundred thousand barrel increments possible from what our position is here. We're in a very good zip code.

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

Thanks, for Gary Heminger. Gary, can you give me an idea what kind of start-up costs there were on the Garyville expansion buried in the fourth quarter numbers?

Let me turn that one over to Gary Peiffer. He has a better handle on that than I.

Yes, Mark, this is Gary Peiffer. Incurred about $50 million or so pretax of depreciation and salary and burden and fixed and variable costs in the fourth quarter. So, after tax, probably about $30 million or so.

Ok. Gary Heminger, can you give me an idea 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?

I don't have that data right here close by. Do you by chance, Gary?

Yes. 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 purpose, but we've been a net seller and we would expect to be for the next year or so.

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

Sorry for the follow-up, folks, but I just wanted clarification on a couple of things if I may. Just looking at your guidance numbers, as the call 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 '09?

We're taking a 40-day turnaround that you should basically be able to think about as a 50% reduction in capacity MEGPL in late February, all of the month of March. That's the driver there.

Ok. But if I look at the guidance pretty much just running down the list of the regions that you've split out, pretty much everything is done sequentially, I'm assuming there's not maintenance in all of the assets. Is this underline decline we are looking at or again more clarity would be appreciated.

I don't think there's anything -- I guess we can disagree if the numbers looked 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 injection. So, that might be part of it. Normal declines in the Gulf of Mexico. But the big driver is the turnaround in NEG.

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

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

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