Howard Thill – VP, IR & Public Affairs Clarence Cazalot – President & CEO Gary Heminger – EVP, Downstream Dave Roberts – EVP, Upstream Janet Clark – EVP & CFO

Robert Kessler – Simmons & Company Paul Sankey – Deutsche Bank Erik Mielke – Merrill Lynch Paul Cheng – Barclays Capital Neil McMahon – Sanford Bernstein Doug Leggate – Howard Weil Mark Gilman – Benchmark Company Faisel Khan – Citigroup

Thank you, Karina and welcome to Marathon Oil Corporation's fourth quarter 2008 earning webcast and teleconference. The synchronized slides that accompany this call can be found on our Web site, 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 and President of our Refining, Marketing, and Transportation Organization; Dave Roberts, Executive Vice President, Upstream; and Gary Peiffer, Senior Vice President of Finance and Commercial Services, Downstream. Slide #2 contains the forward-looking statements and other information related to this presentation.

Our remarks and answers today to questions 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 and the Private Securities Litigation Reform Act of 1995, Marathon Oil Corporation has incorporated in the annual report on Form 10-K for the year ended December 31st, 2007 and subsequent Forms 10-Q and 8-K cautionary language identifying the important factors but not necessarily all factors that could cause future outcomes to differ materially from those set forth in the forward-looking statements.

Please also note that in the appendix of this presentation is a reconciliation of net income to adjusted net income by quarter for 2007 and 2008, preliminary balance sheet information, first quarter and full year 2009 operating estimates and other data that you may find useful. Moving to Slide #3, during the fourth quarter we had strong growth in E&P volumes and improved year-over-year downstream margins.

However, primarily as a result of the $1.4 billion non-cash after-tax impairment of goodwill in our Oil Sands Mining segment, we had a net loss for the period of $41 million or $0.06 per share. Excluding the impact of the goodwill impairment, gain on asset sales, and other special items, adjusted net income was more than double that of the fourth quarter 2007 and just over $1 billion or $1.44 per diluted share while segment income was up 59% over the same period.

Moving to Slide #4, key drivers to the year-over-year increase in adjusted net income included a significant increase in downstream segment earnings, driven by strong refining and wholesale marketing margins as well as strong retail margin and a higher earnings from our Oil Sands Mining segment which reflected a full quarter of earnings in 2008, including derivative gains due to the rapid decline in crude oil prices during the quarter. Corporate and other unallocated items amounted to a positive $300 million for the fourth quarter 2008 compared to a positive $45 million during the fourth quarter 2007.

This includes such items as net interest expense and unallocated G&A as well as items related to taxes that we do not allocate to segments. In the fourth quarter, this included a tax benefit for currency remeasurement on foreign deferred tax liabilities and a tax benefit due to fully recognizing the effect of unutilized Norwegian net operating losses.

Together, these two items totaled approximately $270 million for the fourth quarter 2008. These favorable effects were partially offset by a significant decline in E&P earnings, largely a result of the steep decline in crude oil and natural gas prices during the quarter.

Turning to Slide #5, Marathon reported its second best adjusted net income of $4.6 billion in 2008, less than $25 million off our record 2006 adjusted net income. 2008 adjusted net income per diluted share of $6.47 did set a Marathon record, exceeding the previous record of $6.42 set in 2006.

2008 benefited from the share repurchase program which commenced January 1, 2006. Adjusted net income per share for 2008 increased 19% over 2007.

Moving to Slide #6, key drivers to the year-over-year increase in adjusted net income included record earnings in E&P segment due to higher average realization and a more than 8% increase in production, sales volumes, a full year of earnings from our Oil Sands Mining assets, acquired October 18th of last year, and increased earnings in the segment gas – I'm sorry, in the integrated gas segment as a result of the first full year of operations at the EG LNG facility. These favorable effects were partially offset by a significant decline in downstream earnings, primarily as a result of the decline in the refining and wholesale marketing gross margin and lower refined product demand.

As shown on Slide #7, E&P segment income for the fourth quarter decreased 43% year-over-year to $264 million. The segment was negatively impacted by year-over-year decrease in average realization of $15.43 per BOE.

Slide #8 shows the production sold in the fourth quarter, was up 18% year-over-year to 417,000 BOE per day, benefiting from an overlift of approximately 1.4 million BOE. Production available for sale in the quarter was 402,000 BOE per day, a 14% year-over-year increase from the fourth quarter 2007.

The fourth quarter 2008 production reflects reductions due to the sale of the Heimdal assets in Norway as well as continued hurricane related downtime in the Gulf of Mexico. In addition, December production was negatively impacted by several days of unplanned downtime in EG and Norway, but both have since returned to full capacity.

During the first half of January, production available for sale averaged 425,000 BOE per day. Turning to Slide #9 compared to the same quarter last year, fourth quarter E&P earnings per BOE decreased 52% to $6.86, largely a result of the decline in the commodity prices.

The 31% year-over-year increase in expenses including exploration expense was largely attributable to increased DD&A, reflecting the startup of the Alvheim, Vilje, and Neptune projects in mid year 2008 and the ramp up in Bakken production. In addition, fourth quarter expenses reflected penalty payments of over $30 million for rig cancellations in the Piceance Basin in Texas.

As noted on Slide #10, 2008 was a strong year for the E&P segment. Sales volumes were up over 8% for the year to 381,000 BOE per day.

This sales growth plus the significant growth in average realized prices, contributed to a 44% increase in income per BOE for the year. Expenses, excluding exploration expense, were up $3.84 per BOE for the year, due in part to increased operating expenses and taxes as well as the previously mentioned increase in DD&A.

Turning to Slide #11 and Oil Sands Mining, fourth quarter segment income was $100 million. This reflects a $128 million after-tax gain on derivative activity and a $9 million after-tax royalty refund for overpayment in previous quarters.

Production for the quarter was 25,000 barrels per day. Moving to our downstream business as noted on Slide #12, fourth quarter 2008 segment income was $325 million compared to near breakeven in the same quarter last year.

This increase reflects an improvement of almost $0.08 per gallon in the refining and marketing gross margin, largely due to the substantial drop in crude oil prices during the quarter. The increase in gross margin was achieved despite the 36% decline in the LLS 6321 crack spread on a two-third Chicago and one-third U.S.

Gulf Coast Basin. The improved margin reflects in part the strong wholesale margins for the quarter, including significantly improved asphalt margins.

In addition, manufacturing and other expenses were lower quarter-over-quarter, due primarily to lower turnaround and other maintenance activities at our refineries. Total refinery throughputs for quarter of 1.177 million barrels per day were approximately equal to the fourth quarter 2007 throughputs.

The refining and wholesale marketing gross margin for the fourth quarter included a pretax derivative gain of $64 million compared to a loss of $427 million in the fourth quarter 2007. While we no longer use derivatives to mitigate domestic crude oil acquisition price risk, we do selectively continue to use the derivatives to protect the carrying value of seasonal inventories, margins on fixed price sales contracts, and long haul foreign crude oil spot purchases.

The downstream segment also benefited from strong retail margins during the quarter. Our ethanol blending volumes increased 52% over the fourth quarter 2007 while our ethanol blending profitability was lower due to lower margin between gasoline and ethanol during the fourth quarter 2008.

Slide #13 provides historical performance indicators for the downstream business and previously discussed LLS 6321 crack spread. Turning to Slide #14 and integrated gas, fourth quarter segment income was $36 million, down from $49 million in the year ago period.

The decrease was attributable in part to a higher segment tax rate relative to the fourth quarter 2007. In addition, pretax earnings from our 45% interest in Atlantic Methanol Production Company, LLC declined to $5 million in the fourth quarter compared to $32 million in the year ago period due to lower volume and a decline in realized prices.

These adverse effects were partially offset by increased sales from the EG LNG facility relative to the fourth quarter 2007. Slide #5 provides a summary of select financial data and at the end of the fourth quarter 2008, our cash adjusted debt to total capital ratio was 22%, a 100 basis point reduction from the third quarter.

As a reminder, this includes almost $500 million of debt service by U.S. Steel.

The effective tax rate for the full year 2008 was 49% compared to a rate of 42% in 2007. Excluding the impact of the fourth quarter goodwill impairment which does not have a related tax effect, the effective tax rate for the full year 2008 would have been 41%.

At the bottom of this slide is a summary of certain preliminary metrics related to cash flows and uses of cash for the full year 2008. Operating cash flow for 2008 was $6.8 billion, while total capital investment and exploration spending during the period was $7.6 billion.

$681 million was expended on dividends and $402 million on share repurchases. Clarence Cazalot will now provide a summary and comments on the outlook for the first quarter and beyond.

Thank you, Howard. Good afternoon, everyone.

If you turn to Slide #16, I would like to briefly comment on our priorities for 2009. We had an outstanding safety and environmental performance in 2008, but we are not satisfied with that and intend to improve on that performance this year.

And in this challenging environment, we are going to focus on cash generation and enhancing our financial strength. We will do that by executing on the non-core asset sales.

And as you know, we have announced over $1 billion of sales thus far and our plan is to announce an additional $1 billion to $3 billion by the middle of 2009. We intend to achieve high reliability and utilization of our major assets.

That certainly means all seven refineries and our major assets in the Gulf of Mexico, the North Sea, EG, Canada, and others. We intend to control our expenses and we are working closely with our business partners across the globe to significantly reduce our overall cost of doing business.

We intend to reduce to the extent possible our working capital and inventories. We are going to manage the capital spend – as you know we announced $5.7 billion capital and exploration spend this morning, but we will manage that based on the commodity prices and the margin environment we see throughout 2009.

We intend to progress our major projects on time, on budgets, with startup of the Garyville major expansion, and Vilje, our project in Norway, for the fourth quarter of this year. And lastly, as indicated in this morning's earnings release, we have concluded our evaluation of a potential separation into two companies and the decision has been made to remain a fully integrated company.

The dramatic and rapid changes we have all witnessed over the last several months and a very uncertain outlook for 2009 and perhaps beyond clearly illustrate the value of being a larger, more financially diverse, and strong company. Our focus will be on execution of our business plans and creating and delivering value to our shareholders.

I will turn it back to Howard for Q&A.

Thanks, Clarence. And before I turn it back to you, Karina, I would like to – and open it up for questions.

I would like to remind everyone that to accommodate everyone's questions that we would ask you to limit yourself to one question and a related or unrelated follow-up question, and you may re-prompt for additional questions as time permits. So with that, if you would ask for prompts, Karina, we will take questions.

Good afternoon. One question and an unrelated follow-up.

Spending an extra $300 million on the Detroit project to defer the startup by a couple of years on the surface doesn't sound like a stellar deal. I imagine there is more in the scope change than what was discussed at a very high level in the release.

I'd be curious for any elaboration there and then unrelated to that, curious what you're seeing for Bakken oil realizations at the moment and in the fourth quarter versus the third quarter?

Okay. First of all on the – Robert, this is Gary.

First of all, on the Detroit project, as we are stretching this out, this project out now approximately two years, we've about $180 million related to really stretching the project team out and the deferral for two years. Secondly, it's about $100 million related to incremental scope changes where we said we are changing the metallurgy to be able to run very high tan and acidic crudes.

So that is another big piece along with about $20 million or so increment to the pipeline project. But still, all in all, as we look at the differentials to Detroit and differentials within the crude slate, we still think it is a very solid project.

Now what we are spending in '09, the $330 million we said we're spending in '09, is not incremental to the project. That's finishing up the engineering and just a little bit of the civil work that we had already started.

So I don't want you to think '09 is incremental to the project.

Okay. Thanks for that, Gary.

And Robert, this is Dave Roberts. Just to give you a picture about the Bakken crude, it's priced at Guernsey sweet [ph], and right now it's running about $2.75 discount to WTI.

The easiest way to think about it though is consider the differential between WTI and what we get for Bakken oil at about $8 to $9 when you include all the transportation gallon differentials in that as well. And that's been a pretty consistent number.

And that's wider I would assume than it was, say, the third quarter of 2008?

No.

It's not. Okay.

Thank you.

Good afternoon, everyone. Clarence, if I listened carefully, it sounds to me that you're saying the decision not to split was related to essentially credit markets and the issue of credit quality.

I know that the rating agencies made some comments after your December announcements on the delay to the decision that a split company might have a lower rating, but the single one would not. I was wondering, firstly, would it be fair to say now that you will be prioritizing credit quality over CapEx if the environment remains tough?

And secondly, I wondered if you are going to succeed which I assume you will in your disposal program, would it be natural to assume that the company will become more downstream weighted, that the disposals in this environment much more likely to be upstream? I will count that as my two, Clarence.

Thanks.

That's a good try, but you got about four in there I think. I think the first part – I don't want to speculate or not speculate but comment on the reasons for the decision, but I think as I said in my remarks, no question, the dramatic changes we have seen in the last six months or seven months certainly had an impact on that decision.

And I think looking forward, it is very clear that the market values more highly those companies that are larger, more financially diverse and for the most part able to fund their capital and other requirements from internally generated cash flows. That's all that went into certainly the decision process.

I think with respect to managing the capital, yes, we certainly are going to be very focused on our financial strength, on our balance sheet. And while we have I think brought our CapEx down to a very prudent level basis, what we announced this morning, we do have additional flexibility.

And as I said to the extent that we see a higher or lower commodity and margin price environment in 2009 we want to retain the flexibility to either act on new opportunities or indeed pull in if we are not seeing the cash flows that we expect from the business. And the last thing is I think certainly our long-term intent is not to grow the downstream relative to the upstream.

Our intent is really just the opposite to grow the upstream relative to the size of our downstream business. We've got a very substantial investment program in the downstream in 2009, 2010 and beyond that for the most part other than Dahoe [ph].

It will largely be maintenance levels of investment whereas our intent to grow the upstream business is pretty clear from everything I have said and Dave said. So I wouldn't judge what we do in terms of asset sales with our strategic intent around the business.

Okay. That's great.

Thanks, Clarence.

My question – first question is on the Oil Sands business, if you can give us an update on how you view that business in light of the write-downs and the low returns that we have seen and the quite significant capital commitment that you continue to have. What is the current view on growth from that business?

And how much have you included in your 2011 production forecast from the Oil Sands?

Well, let me comment from an overall standpoint and then Gary can augment that as needed. But I think aside from the write-down of the goodwill, this is a business that we see great value in for the mid and long-term.

Appreciate what we are doing today, we are investing in Expansion 1. And when this is completed in 2010, what we have is in essence a long life legacy type asset that we believe in an 80 type – $80 a barrel type environment easily generates $0.5 billion or more of net after tax cash flow to the company, again without a decline curve in it.

So this is a very important part of our long-term view of the business and we are working very hard with our partners today to overcome some of the near-term issues we've seen in terms of the reliability both at the mine and at the upgrader to lower the operating expenses of the business as well as reducing the capital intensity of Expansion 1 and then the ongoing maintenance of the business. So lot of improvement to be made and we are focused – completely aligned with our partners on that.

But this is going to be a very valuable, long life asset for Marathon for a long, long period in time.

Alright.

Clarence, I will add to that. And your question is spot on, Eric.

We have a short term, medium term and long term focus. Short term we really need to improve on the reliability of the business.

And medium term, as Clarence was suggesting is to reduce our operating expense and that's by improving the reliability and de-bottlenecking of the upgrader and some of the mine operations today. But the long-term – and I really look at this asset like the refinery, and that is the base upgrader and the new upgrader we're building.

I am confident it's going to be able to handle more throughput than it certainly was built for. So another value adder on top is how can we get more mine production and be able to get this mine production up ratably to be able to always fill up the upgrader and that gives us our best returns.

So those are the three things we are going to work on. And lastly, we expect Expansion 1 here to be complete going early into 2010, so you ask how much incremental production do we have in 2011.

We would be 20% of the new 100,000 barrel per day incremental. So it be probably going to be in the 45,000 barrel per day to 50,000 barrel per day total range as we go into 2011.

Thank you. If I can ask a follow up question, just on the Stones project in the Gulf of Mexico, there was a – in the CapEx announcement, a general reference to Gulf of Mexico projects, can you let us know where you are with that project in terms of appraisal and what might be a realistic timeline for thinking about FID?

Eric, this is Dave. I don't want to disappoint you, but we did have what we thought was a very encouraging side track to the well that we announced toward the end of last year.

Together with our partner, the operator Shell, we are studying this and we are expecting them to take the lead in terms of announcing when this might actually show up on a production forecast.

And any sense in timing of that?

Well, I think, as we said previously, the lower Tertiary is very complicated. We think Stones is a very large discovery given its aerial extent.

But given some of the current price challenges about operating in that water depth with the number of wells we are anticipating in order to make a program here, we expect Shell to be very judicious. And I would expect they will spend a considerable amount of time in 2009 studying this before they make any further announcements.

Thank you.

Hey, guys.

Hey, Paul.

If I could have, two questions. Clarence, you mentioned that you expect stability.

Let's say if we entered a worst case scenario and you really have to cut to the bone, how much money that you can get cut out in this year program. And also from a sustainable not this year but on a future year on a sustainable basis, what is that capital level maybe?

That's the first question. And maybe then if I can pull in is that with the Oil Sands you have a – real nice hedging gain, is there, does it make sense that given the market condition for us to close out the respect position and just log in the gain take the cash to fund your capital spending?

And if I could, one last question here, I can have a second question on this exploration program. It is all related, right?

The second question is the exploration program with Angola is winding down and with Phil Behrman is no longer here, is there any change in your overall strategy in the exploration program in what may be a new area of focus, rephasing [ph] Angola? Thank you.

Paul, let me take the first one. I can't give you a number, Paul because it all depends upon the circumstances we see.

And it's – depending upon how dire things get, you might be willing to take some penalties or forego opportunities that you otherwise wouldn't do. But suffice it to say we've got flexibility, because we've still got some projects in the budget that are longer term, things that we could, that we operate that we can back away from or perhaps go non-consent.

But I can't give you a precise number because it all depends upon –

Can you give us a range, saying that under the worst case scenario, you said the possibility is to the tune of $0.5 billion to $1 billion, above $1 billion or less than $0.5 billion?

I would say, Paul – and again I'll just give you a minimum range, I think in the range of $400 million at a minimum. But again depending upon how difficult things get, I think we've got flexibility beyond that as well.

Okay.

Not things that you would want to do and prefer not to do, but to your dire circumstances case, that we have flexibility to adjust our capital spend. Obviously, the longer you go in the year the more difficult that becomes, but early on we've got lot more flexibility.

I will let Janet talk about monetization of the Canadian hedge.

Hey, Paul, I think that probably the market value of that hedge is somewhere around $45 million to $50 million pretax. And that's just one of the items that we're looking at in terms of where could we get enhanced liquidity if in fact we need it.

But working capital management, particularly our downstream business provides a lot of opportunities that we might be foregoing some incremental income, but would be able to generate additional cash. So, I can assure you that liquidity is something that we're very focused upon and we are identifying all areas where we can access cash as the year goes by.

Great.

Paul, this is Dave. Just to give you an idea.

I don't think our exploration philosophy has changed at all. It's still designed to deliver both near and longer term impact opportunities for the company.

So I think you are absolutely correct that the Angola program certainly will be phasing out as we see some of those things come on production. I think what we look for in the future in terms of near term opportunities is the exploration teams involvement and the expansion of some of the resource plays in the United States, you saw the announcement we've made on Woodford Shale discovery that we made late last year.

We'll have some early drilling this year in terms of our Marcellus position. But importantly, I think you will see some short to medium term impact from what we think is a very robust Gulf of Mexico program that we'll largely start to feature in 2010 with three to four impact wells that we will drill in that year.

And of course we will see two wells drilled in our Indonesia program at Pasangkayu. That clearly is very ranked and it's also a very long term, but I think it gives you a sense of the balance that we have in our exploration portfolio.

Thank you.

Hi, just really a first question and then as everybody else, completely unrelated other one. The first question is really around the U.S.

E&P operations. To be honest, if you look at the current oil price, one might think that you could be running at a loss today in terms of your U.S.

E&P operations. What is there that could give us some hope – maybe it is canceling some drilling contracts or new production coming or post-hurricane production coming back from the Gulf of Mexico that may give you a positive number for the first quarter 2009?

Maybe you can just walk through your outlook on the U.S. E&P

Neil I do think that the quarter was a tough one, but as I think Howard mentioned, one of the things that we need to focus in on was that a big item in the quarter was $38 million in pretax charges that we took relative to laying down rigs in the Piceance Basin and some charges that we had relative to our less than successful exposure to the Barnett Shale, which really dates to some time ago. So I think those things certainly play to that and also the increase in DD&A due to the addition of Neptune to our portfolio which is substantially different when you think about a mix issue in terms of the Neptune barrels that came on versus some of the Gulf of Mexico barrels we didn't have on as you mentioned due to the hurricane.

Certainly, all of those barrels except a very few of outside operated ones are now back on production. I think one of the things we have talked about is we are going to have minimal drilling programs in some of our higher cost, lower value areas, specifically, the Piceance Basin, and we are focused in on just the very core activities around Bakken shale.

So we have a very clear view of this in terms of making sure that this works. But I do think that the – some of the issues that were relative to the end of last year are not repeatable.

Just, Dave, just maybe just going over the fact that we are in a lower oil price environment so far this year relative to last, relative to the fourth quarter. So do you envisage if we sustained at this oil price level for the first quarter we would see some profit in the U.S.

E&P business?

I expect that, yes.

Just add one unrelated follow-up related to the split in the company. Just thinking going forward, what is – maybe a question for Clarence, what is the position of the management team to try and get investors back focused on this company as an integrated company versus a refiner?

Because it's all well and good to say there is no split anymore. But it's not much use if investors' mindset are still focused on the company as a particular type of company rather than an integrated company.

I was just wondering how you were thinking of maybe giving some good PR as to what the company is looking like going forward.

I think, Neil, if you are talking about PR being better communication, that certainly one element of it. But people still reflect back to 2006 when 58% of our earnings came from the downstream, 2007, I think it was 54%.

If you look at it this year, less than 30% I believe of our segment income comes from our downstream business. So you are beginning to see the reflection of the production growth and the assets that we're bringing onstream in the upstream, and now certainly when Garyville expansion comes on at the end of 2009, that's going to have a major impact to the downstream business.

But I think, Neil, part of the conversation has got to be around the fact and I think it's something I said to you in the past. I would hope investors really focus on the fact that you generate sustainable cash flows.

Whether those cash flows come from a refinery or an offshore platform really isn't the issue. In fact, if they're coming from a refinery, they're non-depleting.

So what we've got to get people to focus on is the aggregation of our businesses and the growth that we have inherent in our plan, generates again on a flat price basis sustainable level of value growth and cash flows from those aggregation of businesses which we think frankly is an advantage over some of our singularly focused peers and we just need to do a better job, Neil, frankly of communicating the assets, the opportunities, and the value growth that we are pursuing.

Just following up with that, were there any chance if the refining markets, the equity market looked better in a year or two, Clarence, if it hadn't reestablished itself with a better multiple that you would reconsider the split at that point?

Neil, I think if anything, all of this should point up the fact that Marathon's management and board continually assess all the options to enhance shareholder value, but I am not going to speculate today on any future actions we might take in that regard.

Great. Thanks.

Hi, good afternoon, folks. Can you hear me okay?

Yes, Doug.

Great. Dave said in the meeting a couple of weeks ago – I hope you are feeling a little better, Dave, but I am still going to try my production question with you.

You dropped your guidance by 3% CAGR over the next three years or four years. I guess my question is where is the – what has dropped out of the program?

Because you've always said that 70% of your developments pretty much walked in, the visibility of the major projects hasn't changed. So what's leading to that 3% drop in the production guidance over the next three years or four years?

I think, Doug, you want me to talk about the '08 guidance for 2011 versus what we're saying now?

Yes.

Just at a high level, I think one of the things we've talked about is from the previous guidance we've given, Oil Sands is off probably 10,000 barrels a day to 11,000 barrels a day. There is some timing issues that are involved in this.

Some of our Libya programs are moving out in time and Droshky is moving up into 2010. So you are seeing some of that leveling off in 2011 and that drops us another 17,000 barrels a day.

The biggest issue relates to some of the rephasing of capital that we're doing. The impact in this year from '08 to '09 is about 12,000 barrels a day, but right now, we're looking at potentially a 35,000 barrel to 40,000 barrel difference in terms of rephasing our capital out of the three years that you are talking about there.

And then of course the disposition, the only one that really impacts is Norway, which because Ireland obviously would have depleted in this period of time, which is another 4,000. Offsetting that some performance adds in new business.

And so that's where you're getting to this difference of we think 55,000 barrels a day to 65,000 barrels a day. Now, one of the things I would say is that I have been a little bit disappointed in some of the chatter over the internet today that 7% is not a substantial growth rate.

Because that is – we think that's still going to be very solid, particularly given the industry environment we're in and the fact that we are still funding both our short, medium, and long term programs to make sure this company is sustainable in the future.

I guess it's an unrelated follow up, but you mentioned Norway, so I'm going to jump on that. The tax rate is again been all over the place this quarter.

And I guess my question is when you look at the guidance – or you haven't given as any guidance, but could you give us some guidance for 2009 assuming that the commodity environment stays pretty much where it is? And could you bring into the input that the increase – substantial increase in mix from Norway and the associated end wells will have in perhaps depressing that tax charge?

Doug, you started out your question noting that there was a lot of noise in the numbers because of tax and there always is and there probably always will be. And that why we haven't given specific guidance with regard to 2009.

Obviously it's affected by changes in foreign exchange, it's affected by business mix, and even the price of oil makes a big difference. So it's pretty difficult to give you any specific guidance, but other than that, if we have similar – it's – we are going to be in the high 40s if you have a normal year and you don't have any unusual adjustments during the year.

With regards to – ?

I was going to say, what's left on the NOL, Janet, and how long do you think you stop paying cash taxes in Norway?

In the 12/31/08, NOL in Norway was $560 million for the regular Norwegian tax that's 28%. And it's $1 billion for the special tax, that's 50%.

So what that means is the first $560 million of pretax income generated in Norway, there will be zero Norway cash taxes paid. For the next, say, $440 million, there will only be a 28% cash tax paid.

However, because we are bringing all the cash back into the U.S., we will be paying 35% cash taxes in the U.S. When we are in that $560 million phase, once we are paying 28% in Norway, we only have to pay an incremental 7% in the U.S.

Any idea, Janet, how long these NOLs – I guess this oil price they can last quite a while.

It depends on what oil price you want to pick.

Right. Got it.

That's it. Thank you.

Folks, good afternoon. A couple of things.

First on the reserve replacement. I wonder if you could provide just a little bit of detail on the $110 million of the adds, and then offer a comment regarding the statement that there'd be an additional $27 million in adds if you can use the average price relating primarily to Gulf of Mexico, I guess, Droshky and Ozona and Block 31.

That latter statement has some rather concerning implications regarding the economics in those two areas, suggesting the reason they weren't booked despite sanction was in fact economics at year-end prices. Could you talk about those items, please?

Sure. It's a good question.

I will start with the last bit because I think that's the easiest to clear up. One of the things we said is that we would have been able to book 28 million additional barrels, and you hit the main culprits there, Ozona, the 4 million barrels didn't meet the economic test, Angola at 15 million barrels and the Bakken some P2s there of about 8 million barrels to 9 million barrels rounding out that number.

And basically what we saw is the Bakken needed about probably $45 WTI to pass the test and so the year end price was about $44. And so those 8 million barrels were very close and we obviously expect to be able to recover those.

And it doesn't impact the majority of our existing production. I think we've been pretty clear and we were clear when we announced the sanction of Angola and Ozona that we believe those deep water projects need to exist in a world where oil price is about $65.

Now the real issue for us is what do you believe oil price is going to be in 2011 when Ozona comes on, and in 2012 when an Angola comes on. We believe in investing through the cycle.

And obviously our decisions and we would expect our partners' decisions to those projects change over time in the event that we saw a sustainable lower oil price. Beyond that, our adds were across the board.

We had good additions from all of our projects teams, Powder River, the Bakken, and the Piceance, all had reserves in the United States, as did our mid-continent gas program, where we had a number of successful wells. So we continued our benefit there.

The U.S. had a very strong add year.

Less so internationally, where we did have an increase in EG due to price specs at PSC and also we saw increases due to performance at Alvheim and (inaudible). So we think a very strong year in terms of reserve adds, but we're obviously would have liked to book the other 28 million barrels.

But keeping our minds on what the cost profile needs to be in order to make those bookings.

Dave, thank you. My related follow-up deals with the budgeted outlays in U.S.

exploration and exploitation for '09 versus '08. I guess I have a little bit of trouble reconciling some of the qualitative comments, Dave and Clarence, to a year-over-year reduction that something like 75%.

Can you talk about how we get from $1.090 billion in the preliminary 2008 spending for U.S. exploration exploitation to the $340 million budgeted for 2009?

What's taking the hit?

One big element that's in the $1.090 billion, Mark, that's not in the '09 budget, are the resales in the Gulf of Mexico. And that total, Dave, was what, $250 million.

So you got the lease sales in there, but as the other thing is we simply have scaled back that activity, both our deepwater exploration as well as our exploitation work in particularly in the Lower 48. Lot of that was gas driven and at current gas prices simply doesn't make sense.

So I think people should be surprised if they don't see, wouldn't see a significant reduction in those numbers in 2009.

But the Bakken's not being scaled back, Clarence?

No. Mark, we had run seven rigs last year.

We're at five today. We'll be at four in the next couple of weeks, and that's going to be our program.

So we are focusing down in the Bakken as well. That's one of the things – we are an international company upstreamwise.

Over 70% of our production and revenue comes from international business. We're building U.S.

position. But one of the things we like about the U.S.

business is it provides us a fly wheel to turn up and turn down as conditions warrant. And we're going to protect our leases in these plays, do our due diligence in terms of technical work that we need to do to prove lot of these areas up.

And when and if the conditions approve we will be in a position to expand our activities again should we choose to do that.

One of the things, Mark, in the Bakken that you need to understand is, as Dave said, we are coming out from seven rigs to four rigs, but in part, that's the fact that we're drilling the best-in-class wells up there. And so we can actually drill the required number of wells with fewer rigs and at a lower cost than what we had originally planned for.

Dave, could you tell me the PSC component of EG reserve adds that you mentioned before?

It's roughly, we – 80% of the $12 million that we added.

Thanks very much.

Hi, good afternoon. I have a question with regard to your growth rate for '09 in production between 5% and 10%.

I guess what has to happen to get you guys to the higher end of that range of 10% versus the lower end of the range of 5%? Is it the oil price has to be at a high enough level or is it capital has to be tooled up to a certain level or what are the major variables in getting to the higher number?

Okay, this is Dave. I guess the critical issue will be – among the critical issues is obviously a full year performance at Norway is going to be critically important to making the range, and depending on how that asset performs through the year, because right now we are in a very good position in terms of how it's performing.

I think this past week we set a record gross production to the facility of about 136,000 barrels a day, and I think that corresponds to well over 80,000 net for Marathon. So if we can have continued performance like that without using the full well stock because we are not currently – we don't have currently all the wells hooked up, then that would be upside potential.

Obviously, we are expecting continued good performance from our resource plays and we will have to see how those plays continue to help us out and obviously reliability in our big facility in Equatorial Guinea are things that can drive us to the top end of the range. The other thing I would mention is we do have deferral of production relative to Libya due to OPEC curtailments and obviously that would be something that would also help us to exceed the ranges that we get.

Got you. Related to Equatorial Guinea, group of European firms signed an agreement on commercialized gas reserves in EG, and I guess I wasn't sure if that commercialization would somehow involve you guys in any potential in Neptune [ph] and EG.

Is there something going on there that you can elaborate on?

We've been made aware and obviously are in discussions with the government about the consortium that they formed with some of our European peers, and that relates to a gas gathering corporation or consortium in order to gather gas. One of the things we are very clear on is that Marathon has the sole legal rights to produce LNG on Bioko Island, which is the natural home for all of the gas that is going to be potentially collected by the consortium.

So I can tell you that we will definitely be involved and one of the things we are interested in is what kind of arrangement we can reach with that gas gathering company. And certainly we hope they're successful in term of capturing gas that would allow us to potentially invest in future LNG facilities.

Great. Thanks a lot for the time.

Appreciate it.

Hey, guys, I think this is for Janet. Maybe I missed it.

Janet, can you help me understand in the fourth quarter, the comp rate [ph] on a locate [ph] tax is a gain of $211 million. Is that related to the Norwegian tax benefit or is there something else?

And also do you have a net interest income for the quarter, which was a little bit surprising for me? Is it just a year end adjustment or that is something more than we should be aware?

Along the line can you tell us what may be the minimum cash balance you have to carry on your book to run the day-to-day operation? Thank you.

Okay. Paul, I think you started out asking about the taxes booked in the fourth quarter.

Yes, I mean if I look at the comp rate on the located, there's a big positive of $211 million. I think they say is comp rate on the located tax.

So trying to understand what that is related?

Okay. Well, I can tell you I am not sure the $211 million that you are referring to.

But I can tell you that –

That is on your supplement.

In the fourth quarter.

You are seeing your supplement.

I am sorry. I missed, I didn't hear you correctly.

$211 million.

$211 million.

No, $411 million, sorry.

Okay. I'm with you now.

That's got a whole lot of things in it, but I think probably what you would be most interested in is about $140 million is related to the foreign exchange adjustment for deferred tax liability. About $130 million is related to Norway, where we had to release the valuation allowance.

There was another maybe $90 million for FIN 18 year end tax true up. In other words we had been booking too much tax during the course of the year.

So those are – there are a number of other smaller items in there, but those are the tax related items. Then you have the usual G&A and DD&A on corporate assets and other than income tax.

Janet, the Norwegian one, is that repeatable or that is one off adjustment in here?

That actually, Paul, the amount that we had expected to recognize during the course of the year, but with declining prices we did not utilize it all.

I see. Okay.

How about the net interest income?

Okay. The capitalized interest was about $100 million.

So that was a higher than – $30 million I think higher than the third quarter.

Okay. So mainly is your capitalized interest is much higher.

Yes.

And so should we assume that will carry on into the first quarter?

Yes, the capitalized interest, there is a big chunk of that is, Garyville, and while it's still under construction, you're going to see some pretty significant numbers there.

Okay. How about in terms of the minimum cash balance?

That's going to vary from one time to the next. I think for planning purposes we look at maybe $300 million, but it's going to depend on where that cash is.

Thank you.

I guess that's the end of it, Karina. We appreciate everybody's participation and look forward to the next conference call.