Howard Thill – VP, IR and Public Affairs Clarence Cazalot – Chairman, President and CEO Janet Clark – EVP and CFO

Doug Leggate – Bank of America Paul Sankey – Deutsche Bank Evan Calio – Morgan Stanley Arjun Murti – Goldman Sachs Guy Baber – Simmons & Company Blake Fernandez – Howard Weil Scott Willis – Credit Suisse Paul Cheng – Barclays Faisel Khan – Citigroup Kate Minyard – JP Morgan John Malone – Global Hunter Securities Amir Arif – Stifel Nicolaus Eliot Javanmardi – Capital One Pavel Molchanov – Raymond James John Herrlin – Societe Generale

Good afternoon and welcome to Marathon Oil Corporation’s Fourth Quarter 2012 Earnings Webcast and Conference Call. The synchronized slides that accompany this call can be found on our website at marathonoil.com.

On the call today are Clarence Cazalot, Chairman, President and CEO and Janet Clark, Executive Vice President and CFO. Slide two contains a discussion of forward-looking statements and other information included in this presentation.

Our remarks and answers to questions today will contain forward-looking statements subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied by such statements. In accordance with Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995, Marathon Oil Corporation has included in its Annual Report on Form 10-K for the year ended December 31, 2011 and subsequent forms 10-Q and 8-K cautionary language identifying important factors, but not necessarily all factors that could cause future outcomes to differ materially from those set forth in the forward-looking statements.

Please note in the appendix to this presentation, there is a reconciliation of quarterly net income to adjusted net income for 2011 and 2012 first quarter and full year 2013 operating estimates and other data that you may find useful. We’ll now move to slide three, and I’ll turn the call over to Clarence Cazalot to review 2012 operational results.

Thank you, Howard and good afternoon. 2012 was a very successful year for Marathon, characterized by strong operating results that met and in several cases exceeded our targets.

As shown on slide three since the beginning of 2010, our quarterly E&T production available for sale has grown approximately 32%. This growth excludes Libya because of the civil unrest there in 2011.

You’ll specially note the growth over the past two quarters which was driven by our lower 48 onshore production. Slide four demonstrates the more than doubling of our lower 48 onshore production from the third quarter 2011 to the fourth quarter of 2012.

The 2012 third to fourth quarter growth alone was 17%. Importantly, liquids volumes increased from 55% to 70% of total volumes from the third quarter of 2011 to the fourth quarter of 2012 with a preference to oil and condensate.

We estimate reaching between 165,000 and 175,000 barrels of oil equivalent per day in the first quarter 2013 and we’ve again set a forward target with fourth quarter production expected to be between a 185,000 and 205,000 barrels of oil equivalent per day. Slide five shows that our liquid hydrocarbon sales volumes for E&P and oil sands mining excluding Libya increased 6% from 297,000 barrels per day in the third quarter to 313,000 barrels per day in the fourth quarter.

Again, this increase was driven by the U.S. resource plays, particularly the Eagle Ford as well as higher sales volumes in the UK offset by lower EG volumes.

You will note that U.S. sales volumes have increased from 37% of the total in the third quarter of 2012 to 42% in the fourth quarter of 2012.

Slide six shows the same comparison for actual fourth quarter 2012 to estimated first quarter 2013 sales volumes and the U.S. sales volumes are expected to continue to grow as a percentage of the total.

You’ll also note that we expect to take our first listings from Angola in the first quarter. Slide seven shows our international E&P cost structure per BOE by category over the past eight quarters.

Our operated international production in Norway, Equatorial Guinea and the UK have maintained excellent reliability and this effort is not only reflected in our production levels, but also in maintaining our cost structure over the last two quarters. Slide eight, which excludes Libya, shows that as we enter 2013, we anticipate increases to the international cost structure.

This is a combination of the projected decline in our Norway production as I just mentioned the start of production from the non-operated Angola block 31 PSVM development. While we’re seeing some increase here, I would point out that our overall international cost per BOE are still quite low.

As shown on slide nine, total U.S. E&P cost per BOE increased quarter-over-quarter primarily because of higher DD&A rates in the growing Eagle Ford and higher exploration expenses in the Gulf of Mexico.

Slide 10 compares the actual 2012 and estimated 2013 operating cost per BOE per U.S. E&P in the Eagle Ford.

Importantly, you will note that our cash cost field level controllable and other are decreasing on a BOE basis reflecting our growing domestic production. However, U.S.

TD&A levels are increasing on a per BOE basis, largely as a result of a higher DD&A rate for Eagle Ford barrels, which are increasing from about 18% of our U.S. production in 2012 to about 40% in 2013.

In the Eagle Ford, as in most developing growth place, DD&A rates in the early years were higher, because initial reserve bookings do not reflect full life EURs and these rates come down as performance justifies additional reserve bookings. Moving to slide 11, I’ll take just a moment to comment on our execution in our three key resource place.

Beginning with Eagle Ford where we have 230,000 net acres in the core part of that play. As you know, we exited 2012 with over 65,000 net BOE per day, which is in line with what we had committed and we’ve averaged 70,000 BOE per day in January.

We’ve increased our 2013 target from 70,000 net BOE per day to 85,000 net BOE per day. We’re currently running 18 rigs and five frac crews in the Eagle Ford, and we continue to improve our spud-to-spud times an averaged 19 days in January.

We’ll continue to see those spud-to-spud times decline particularly as we execute about 70% of our drilling in the Eagle Ford in 2013 on multi-well pads. We believe this may allow us to decrease ultimately to 16 rigs and still drill to roughly 290 plus wells that we planned for 2013.

And we have our nine pilots underway and as we’ve said previously we’ll be commenting on the results of those pilots and certainly the impacts on our forward plans in the second half of the year. As we turn to the Bakken where we have 410,000 net acres that we’re currently producing about 33,000 net BOE per day.

We have five rigs and two frac crews active and we’ll drill 65 to 70 net wells in 2013. Importantly, you’ll recall that we increased our 2013 target from about 30,000 net BOE per day to 33,000 and now with the strong performance we’ve seen in the fourth quarter and in January.

We’re looking to increase our target for 2013 to greater than 35,000 net BOE per day. And turning to Oklahoma, our resource basins there, where we have about 220,000 net acres, we are currently producing about 12,000 net BOE per day from the Anadarko Woodford.

We have two rigs operating in the Knox area of the Woodford and we will have those two rigs active throughout 2013. And as we have discussed before we have a very significant resource base that will act upon in this areas we see improvement in both NGO and natural gas prices.

And with that I will turn it back to Howard for the financial remarks.

Thanks Clarence. Slide 12 provides an analysis of 2012 cash flows.

Operating cash flow before changes in working capital was $4.5 billion, compared to $4.9 in 2011. Working capital changes resulted in a $437 million use of cash in an operating cash flow of $4 billion for 2012 compared to $5.4 billion in 2011.

The decrease in operating cash flow year-over-year was primarily the result of working capital changes related to the 2012 ramp up of operations in the Eagle Ford Shale in Libya, and the timing of the tax payments. I won’t step through each of the other cash flow items, but this point out we ended the year with $684 million in cash total debt of $6.9 billion and a net debt to total capital ratio of 25%, the same as at the end of the third quarter.

Moving to slide 13, our fourth quarter 2012 adjusted net income of $398 million for the 15% decrease over the third quarter of 2012. Our international E&P fourth quarter pre-tax earnings increased $119 million, while Oil Sands mining, U.S.

E&P and integrated gas saw offsetting decreases, because of the higher percentage of international pre-tax earnings, we also saw an increase in income taxes. As shown on slide 14, the E&P segment’s fourth quarter earnings increased slightly to $501 million.

The increase was primarily driven by higher liquid hydrocarbon sales volumes and higher natural gas realizations, mostly offset by higher DD&A and operating costs associated with those additional volumes and higher exploration expenses. Slide 15 shows the changes driving our fourth quarter U.S.

E&P earnings. Large volume increases in the Eagle Ford and Bakken were partially offset by higher DD&A, operating costs and production taxes attributable to the new wells brought to sales.

The increased exploration expense was associated with the unsuccessful Innsbruck well in the Gulf of Mexico. Slide 16 shows the impact on international E&P earnings from the higher liquid hydrocarbon sales volumes, price realization, and lower DD&A, partially offset by higher other costs and income taxes.

During the fourth quarter, we over-lifted in Libya, which has a favorable DD&A rate per BOE compared to the volumes we lifted in the third quarter, but it’s also reflected in the higher income taxes shown on the slide. As shown on slide 17, quarter-over-quarter, our E&P segment production available for sale was essentially flat, while our U.S.

resource plays continued to ramp up significantly. There was an offsetting decrease quarter-over-quarter in Libya.

As you may recall, we signed a gas sales contracts during the third quarter in Libya and recorded all previous volumes available for sale in that quarter. Excluding Libya, our production available for sale increased 7% quarter-over-quarter.

Sales volumes increased approximately 8% as a result of over-lifting volumes in Libya and in the UK. At the end of the fourth quarter, we were underlifted by approximately $4.7 million BOE of which approximately 4.1 million BOE was natural gas, 2.4 million in Libya and 1.7 million in Alaska gas storage.

On the liquid side, we were underlifted, 160,000 barrels in Angola, where we had first production from our PSPM development in block 31 during the fourth quarter as Clarence previously mentioned. We were also underlifted 180,000 barrels in Europe, 145,000 barrels in EG and 100,000 barrels in Libya.

During the fourth quarter, we significantly reduced our liquids underlift in Libya by a 1.9 million barrel overlift in the fourth quarter. Slide 18 shows our Oil Sands mining segment income decreased $46 million sequentially.

This was the result of unplanned downtime at the upgrader in the fourth quarter 2012 resulting in lower production volumes and lower price realizations. Net synthetic crude oil sales decreased 9% from 53,000 barrels per day in the third quarter to 48,000 barrels per day in the fourth quarter Moving to slide 19, integrated gas segment income decreased $4 million quarter over quarter to $35 million.

This was primarily a result of lower LNG sales volumes with 14 liftings in the fourth quarter compared to 16 in the third quarter. Higher methanol sales partially offset the lower LNG income.

We will now move to slide 20 and I’ll turn the call back to Clarence.

Thank you, Howard. Further to Howard’s explanation of cash flows, I want to reiterate our commitment to living within our cash flows, while we grow our net production at a compound average rate of 5% to 7% from 2010 through 2017.

In 2013 alone we promise growth of 6% to 8%, excluding Libya and asset divestures. And as some of you have noted already, our production guidance for 2013 puts that range at 6% to 13%.

That represents a stretched target and I’ll simply reiterate our commitment is 6% to 8% growth and this is backed up by drilling inventory that we have great confidence in as I discussed earlier. Moving to slide 21, the strong growth profile is underpinned by growing reserve base.

About this time last year, we promised greater than 150% reserve replacement for 2012. And I’m very pleased that our team has exceeded that expectation, delivering 185% reserve replacement, excluding acquisitions and divestitures at preliminary F&D cost estimated to be $17 per BOE, including acquisitions, which strengthened our Eagle Ford position.

We replaced 226% of our 2012 production again at an F&D projected to be approximately $17 per BOE. Over three year period, which we’ve stressed as a more representative measure, our average reserve replacement has been 173% and we’ve done this at a preliminary F&D rate of $23 per BOE.

This has led to the highest level of proved reserve for Marathon Oil in 40 years and we’re not finished. We have a portfolio that includes significant untapped resource, and through continued execution of our strategy, we plan to continue growing significant shareholder value.

Slide 22 summarizes many of the points I’ve just made. So I’ll just touch on a couple of additional key priorities for 2013.

First is drilling a high graded exploration program that we believe provides significant upside to our shareholders. Second, our drive to continue to enhance our value through portfolio management and an increased focus on enhancing margins and overall cost competitiveness.

And with that, we will open the call to questions.

To accommodate all of those who want to ask questions we ask you to limit yourself to two questions. And you can re-prompt for additional questions if time permits.

Christine with that, I’ll turn it over you to get people in the queue.

Thanks. Good afternoon everybody.

I understand the operating cost guidance Clarence, thanks for that. But I guess my question is really on the as you shift your production goals towards the U.S.

can you help us understand what the cash tax impact is in terms of how we should think about the deferred tax is going forward and I have a follow-up, please.

Let me let Doug, I have Janet touch on that.

Yeah, I think because of our very high capital program in the U.S. the domestic spending is such that we would not expect to see cash taxes paid in the U.S.

in the coming year. As you know our international taxes are largely all cash, and in fact deferred tax is reversing on and is incremental cash.

Okay. The reason I asked the question, Clarence, if I may based on your current capital program based on given your production outlook it seems to us you are going to be throwing off a fair amount of cash, and update perhaps possibly on how your sales process in Canada is going as well.

But when you take that together, it looks like you’re going have a fair amount of cash this year. I am just curious as to what’s your priority for using that cash and I’ll leave you there?

Thanks.

Well, Doug, I guess first of all, I would say that the amount of cash we drove off obviously is going to be dependent upon the commodity price environment that we face. But there is no question that certainly the growth in our U.S.

production is going to drive strong cash flows from those resource plays, but at the same time you would recognize we are seeing declines in some of our legacy assets that have also been historically very strong cash flow providers like Norway. As you know, we will see about a 20,000 BOE a day decline in Norway this year from about 90,000 BOE a day to 70,000 BOE a day, as well as the Gulf of Mexico.

So again obviously we do expect to continue to grow. Our cash flows, both on an absolute and a per-share basis, but I think you just have to look at all of the elements that come to bear on that.

With respect to, you mentioned Canada I would simply say that as you know and many others know, we did indicate that there had been discussions around the potential sale of a portion of our interest there. And I think what I would say to everyone is when and if that is no longer relevant or correct, we will say something.

So you’ll hear something either way, either in terms that we have come to a mutually acceptable transaction at some point in time or indeed – if indeed those discussions should breakdown, we would still advice of that as well. The other sales, again, we – outside of Canada, we have said $1.5 billion to $3 billion of transactions between 2011 and the end of 2013, we continue to make progress on that and you’d have noted in our earnings release today that we did announce the sale of our 34% interest in Neptune gas plant for $170 million.

So we continue to make progress towards our overall goal by the end of this year.

To really kind of get to the use of cash clearance as opposed to the sources of cash. I guess you get the punch line, are you happy with the portfolio or do you feel you have enough debts or should we expect additions of portfolio as we go forward?

No, I think coming back, Doug, we have said first of all we’re going to spend within our cash flows and certainly the $5.2 billion CapEx program we’ve outlined for 2013, we think it fits with that. It is straight down the fairway of the guidance we’ve given of $5 billion to $5.5 billion of spending going forward.

With respect to additional cash that may come in from asset sales, certainly we’ll look at that, I think we’ve indicated in the past that for the most part, we believe that the bolt-on acquisition programs that we’ve been doing, particularly in the Eagle Ford, have largely reached their end. We believe, we’re pretty much with may be one exception exhausted that opportunity set.

Having spent quite a bit on acquiring and building the resource base we have, we will now set about to spend our money developing that and additional cash we would look to either as we said potentially a share buyback, strengthening our balance sheet and increasing the dividend, and no one should read into that necessarily, that’s a priority. We’ll assess that at the time, but clearly returning value back to our shareholders is a key driver for us and certainly that’s what we’d look to do at that time.

Great. Thanks very much.

Hi, everyone. You outperformed again in the Eagle Ford.

Could you talk a little bit more about how far – where do you want to driving that performance and particularly we’re looking at the drilling days is exceeded our expectations in terms of how low you’re going. How much further can you go with that plant.

Could you talk a little bit more about how much pad drilling you’re doing – just fill us more on just what’s driving your success there?

Well, it’s really easy answer, Paul. Let’s say it’s extraordinary people – the team we have is doing an outstanding job across the company.

But, certainly in the Eagle Ford as we drill that may wells and continued to incrementally improve what we do, it all cumulatively adds up to very significant savings in spud-to-spud times. And of course, as I indicated in my remarks, we’ll be aided in that in 2013 by the fact that we’re moving to about 70% of our wells being drilled on multi well pads versus very few pad wells in 2012.

And as we’ve indicated in the past, pad drilling significantly accelerates the spud-to-spud times and it’s not necessarily representative of everything we’ve been able to do, but we’ve had occasions where three wells of one pad took us a total of 39 days, so roughly 13 days a well. So again, as you see more pad drilling, we’re going to bring that – that the average in January of 19 down to a much lower level.

And so, as we’ve talked about driving down our overall cost in the Eagle Ford, it’s a combination of savings on rig time as well as savings that we’re realizing in our completion cost that’s allowing us to drive our overall drilling and completion cost down below the $8 million level that we’ve talked about. So, I think it’s all of those factors quite frankly Paul, that continue to enhance our overall performance.

Great. Thanks.

And I know you’ll encourage only one follow-up. So, if I could jump across on the subject to people, there was an abrupt resignation in the past quarter that surprised us Clarence, what is your public statements on what happened there?

Thank you.

Yeah. Paul, and look I know it came as a surprise and I know what you’re referring to is Dave’s resignation for the company, and I think as the release said it was to pursue other interest and obviously we wish Dave well and whatever he elect to pursue.

The message I would have for investors is that we have a very strong team here at Marathon. As I was just talking about the results in the Eagle Ford, we could say the same across the rest of our business.

We have a very talented, experienced leadership team and I believe the company is in the very, very good hands, and I would simply say that the development of our leadership team, of our executives and succession plans are at a very high priority at Marathon for the management team and for the board as well. And so, again I would reinsure investors that the company is in very good hands.

Thanks, Clarence. If I could just confirm that Marathon has a mandatory 65-year-old retirement age, which without wanting to embarrass you, I think is going to fairly shortly affect you?

Yeah, actually, I’m 62, Paul, but I feel 52 on some days. But to your point and it’s what I was referring to just a moment ago, succession planning is a critical priority in this company and it is something that particularly with respect to CEO succession and the board spends a great deal of time and effort on.

And I again will assure you is as all the shareholders that when it’s time for me to step aside, this company will be in very good hands and will be able to led into the future. So, again I would simply say there is nothing for investors to worry about at that point.

Thanks very much in deed sir.

Hi. Good afternoon, guys.

The question on Eagle Ford I think you guys plan to drill 275 to 320 operated wells. I know you bringing as much sales as you drill in 2012, which is as expected, but how should we think about the backlog for 2013, kind of building falling same ratios as it affect production.

And then secondly I appreciate your color in increase pad drilling, can you update me kind of where you on oil cost today versus your 2013 target. Thanks.

Yeah, I think Evan I’m not exactly sure, which backlog you’re talking about. We and you cited the range we’ve given.

I think the most specific number is about 290 to 295 wells that we plan to drill this year and we’ve talked about the fact that while we’re at 18 rigs currently, we may able to go to 16 rigs and still achieve that program. Again, we feel pretty confident about that.

We’ve been asked, why don’t you keep those 18 rigs and drill more wells and I think it goes exactly to your question. We are drilling at a pace and growing our production at a pace that aligns with the midstream development and the takeaway capacity.

So we avoid just that kind of backlog that you’re talking about, and continue to be able to hookup our wells with in a very short time of when we got them fracked, so that we don’t have a great deal of production shut in. It has helped a great deal as you know that we have invested significantly in the midstream, last year was around $350 million, this year it’s about $190 million at central batteries and gathering lines that has allowed us to move off of trucks with about 60% of our barrels now on pipe that gives us again greater optionality and lowers our costs.

There obviously is a CSR advantage as well in the region in terms of traffic. And we intend to move that closer to 70% by the end of the year.

So continue to move our barrels on pipe. So I would simply say, we don’t have a significant backlog, we typically try to keep in terms of our fracs, about 25 wells that are out and front, so we never have our frac crews waiting on a drilling break.

So if that was what you were concerned about the frontend, we’ve got inventory built there and then on the backend, in terms of keeping our barrels moving, we’re in good shape there. Again I would say in terms of the overall drilling and completion costs, we’ve been running about $8.5 million, we will take that down as I said just a moment ago to just below $8 million drilling completion, and then we’ll have some additional facilities cost on that that will bring that up for about $8.1 million.

I would simply indicate that as we look at our opportunities, keep driving cost down in the Eagle Ford. We do indeed see some opportunity particularly on the stimulation side, the frac cost side to continue to driving – drive some of our cost down there on the drilling rig side.

The greatest savings is going from 18 rigs to 16 rigs and being able to drill the same number of wells. So that’s what’s impacting our cost.

That’s very helpful. Second question just on corporate expenses, they were up from 3Q, and maybe I missed it, I don’t know if there were any kind of a onetime charges in there.

Should we expect this to revert lower in 2013 and closer to 3Q or any guidance would be helpful? Thanks.

Sure, I think if you look at allocated G&A was up from 83 and 134 and interest expense was up from 53 to 61 quarter-over-quarter. And there is about $25 million of comps and comps related expenses that are really of an unusual nature, and we not expect to see them recurring.

We had about actually $10 million of IT expense in the quarter. Our IT spend did not exceed our budget, our plan for the year, but it was very much backend weighted.

And so that’s not a run rate that you should expect to see continuing. In addition we have a tax sharing agreement with MPC and relatively small amount quarter in and quarter out, over time they will be income neutral.

But in the fourth quarter showing up in that unallocated G&A was about at a $11 million expense associated with the MPC, tax sharing agreement which will be offset, again that will be income neutral. So, don’t think of that is recurring either.

When you look at interest expense quarter-over-quarter, it was up about $8 million and as you know, we issued the debt $2 billion of debt in the fourth quarter and while it was a very, very attractive interest rate. It felt was more expensive than the CP that is replaced.

So, interest expenses going to be up marginally quarter over, that will be ongoing. And then as always a little bit of noise in the G&A and interest numbers, a lots of other miscellaneous things.

But I think that if you look at the third quarter and allocated G&A, it is probably closer to a reasonable run arte. Although with ramp up in activity levels, we’re going to see some natural inflation in there, but I think Clarence eluded to the fact we are looking at ways that we can more efficiently operate so that we can produce greater value for the shareholders.

Great. Great color.

Thank you.

Clarence, just a couple international questions. I think you mentioned in the release the Kurdistan, Declaration of Commerciality.

Could you just talk about next steps there? What kind of capital order of magnitude, we may be looking at.

And then just on the Gabon subsalt well that I think spuds later this quarter. Is that one where the state of the block is depending on this first well or their multiple prospects?

Thank you.

Yeah. I guess, Arjun, I don’t recall making a comment on Declaration of Commerciality in Kurdistan.

We have had the very successful second well drilled at Atrush.

Yeah.

And perhaps, may be…

I apologize, it’s been filed, I think according to your release.

Okay.

So, maybe, nothing to clear, apologies.

Okay. And of course, earlier this week, I think one of the partners in that projects disclosed some independent reserve reports that they had done on the asset.

But at this point, obviously we’ll continue to participate there. We’re very anxious to see the commerciality of how these barrels will be brought to market given some of the difficulties that are ongoing there today, particularly because the relationships between Bagdad and Rubiel.

In terms of our spending there this year, it’s the Harir well that we’ve indicated that first well was a dry hole. We have two wells drilling today on the Mangesh and Gara wells that are on the Sarsang block, and we’ll have another well, the Mawawa well drilled later this year.

And then, we’ll be following up with two of our operated wells, one at Safen and one at Mawawa, which is on the same block as Harir well. I don’t know that we’ve given necessarily the full investment there, I would simply say that we have formed down, as you know, 35% interest in our two operated blocks origin and we have mitigated further I would simply say our financial exposure to the drilling.

And so, we’re going to get a very cost efficient evaluation of these prospects in 2013.

Thank you. Then just on the Gabon presalt and one done or some more prospects there?

Well, I’m a former exploration partner, so you never want to say when done, it is going to be a great important test because it is on a very large structure. These structures all defined by 3D seismic, there is a question mark of course is the presence of reservoir, the quality of the reservoir out there in the deep water as well as the access to source, we see the salt seal above these structures.

So I’d never say that one well in that larger block can completely make or break the block, but it’s going to have a very significant impact certainly in our view of it. And so it’s a promising well, and we look forward to it and I think the spud was originally mid-February and now it looks like it’s going to slip into March, so we watch that with great anticipation.

That’s great, Thank you so much.

Yeah.

Hi, thanks for taking my question. You guys touched on this briefly earlier, but I was hoping you could comment on recent North Sea production trends, but I believe about a year ago, you were expecting a 2012 production at Alpine to average about 80 a day.

And it looks like it actually came in around 90. So you’ve outperformed there, can you just talk about what all you’ve done to improve the production there and may be give us your latest thoughts on extending that plateau and what declines could look like in 2013, 2014.

So do you see some upside to that 70,000 barrels a day in 2013 that you mentioned earlier in light of some of the recent performance.

I wish I could answer that affirmatively, but I would say that the extraordinary work that our team has done in the past not just in raising 2012 production about what we said, but if you look back historically at what our 2008, 2009 plans said, we have really outperformed for several years here. And to your point extended the plateau and raised the plateau to a higher level of 90,000 barrels a day, in 2012 and that was a combination of additional tie-backs to Alpine, but again pretty extraordinary reservoir work and operating reliability on that asset and that’s allowed us to achieve some really top quartile performance.

There is no getting away from the decline we see in the 2013. It is about a 20,000 barrel a day decline to average around the 70,000 BOE per day.

We continue to advance projects like – that we’ll be able to tie back to Alpine and that will help flatten the decline in the future when that project comes on I believe at the end of the 2014, but the decline will still be there. We certainly continue to look for new opportunities to tie back within the acceptable radius, but I think we’ve pretty much exhausted that opportunity set.

We will continue to operate the asset on – as lower costs and reliable basis as we can, because as I’ve said before despite the fact that Norway is a high tax rate country, these barrels get a very premium price, obviously the lower prices and at low cost. So, it is a – still a strong margin, highly profitable though.

Okay. Great.

And then also you raised the Bakken guidance, but one could argue that it’s still conservative in light of some of the recent performance. So my question is how conservative Mike that guidance be and what type of activity levels does it imply for you all through year?

Sorry if I missed that earlier. And also, what might cause you to accelerate activity there, certainly realizations have improved, prices have been strong, I assume you’ve gotten some service cost release, just wanting to get a sense of what you might need to see get more active there?

Yeah, I think, first of all with the guidance or the activity levels, it will remain at five rigs. This year we do have two frac crews active.

We may indeed be able to scale that back to one frac crew and that is to drill about 65 operated wells and to your point on the guidance, I’ve recognized that in the fourth quarter we – we hit an essence what is our – was our guidance for – higher than our guidance for 2013. So, we’re certainly simply looking at that.

But I would tell you that we have to be careful because it is winter time up there. You’ve noted that our January production is below, where we were in the fourth quarter and weather can have a very significant impact on that.

But again our team continues to perform extremely well. What we look at additional activity, we will.

And to your point that we’ve seen improvements in Bakken pricing as rail has opened up additional outlets eliminating some of the bottlenecks. We too have increased our use of rail.

If you go back to January of 2012, we only railed about 5% of our barrels. Now, we’re up to 40%.

We’ll continue to look at that as a good opportunity certainly in 2013 when we think the differentials will support that kind of activity. But we don’t want to lock into long-term activity until we get a better sense of how overall infrastructure and builds out and differentials are impacted.

So, we certainly will look at that possibility of ramping up if we see the right conditions.

Very helpful. Thanks.

Folks, good afternoon. Thanks for taking the question.

I had a question on divestitures maybe two specific assets if I could. One the Marcellus was noticeably absent from commentary.

I was just curious if you’re planning to move forward there or potentially exit? And I guess the similar question on Libya, obviously the production is ramp back pretty aggressively here.

I’ve read recent press report that suggests there could be upside production potential in the area which could potentially garner some interest from some of your larger peers. And I am just curious if that could potentially be an asset you would look to divest and help maybe neutralize this erratic tax rate that we’ve been seeing?

Thanks.

Yes, Blake, I guess on the first piece, it is our intent if we are able to secure the right value to exit the Marcellus I think we’ve been pretty well upfront about the fact that is not an area that is quarter less and so that certainly is something we’re looking at. With respect to Libya as sale candidate, as I have said before, Blake, we don’t comment on specific assets that we haven’t announced for sale, simply because we believe that weakens our hand if indeed we ever do elect to monetize an asset.

And so at this point I simply would say you’re right that this asset has great upside. We’ve said in the past and most recently the NOC has said in the past that it’s an asset capable of producing upwards of 600,000 barrels a day from the current 320,000.

The key to realizing that is going to be to develop some major projects that have already been discovered and we’re in the planning process. So we see strong value in this asset going forward despite its high tax rate.

And I recognize it has a high tax rate, but the nature of that contract is that no matter what the oil price is, Libya will always generate positive earnings and as well as likely positive cash. It is a very favorable contract in that regard and it’s a high return asset.

So, we will continue to move forward with it.

Okay, great. My second question Clarence if you don’t mind just addressing quickly the another discussion of potential MLP in the Eagle Ford with regard to the midstream takeaway capacity I didn’t know if you had any updates there on where you stood?

No, it’s really way to early at this point Blake for us to begin exploring that. I think we certainly see that as a possibility in the future, when we finally reach a stage that we have built out the infrastructure and are convinced that we are able to capture the value of our production, which is the highest priority here.

We do need to maintain control over that infrastructure to move our barrels to where we see the best value, but we still got more work to do there. And as you heard me say before we are going to have to determine ultimately what is the plateau level of production if we want to get to in the Eagle Ford.

As I have said before we are not going to run to a peak and then decline. We want to reach the plateau that we can maintain for several years, so we can build out the infrastructure to meet those needs and not end up with over capacity very shortly after reaching a peak production.

So, I think for now we are going to continue to move forward building out what we need. I want to all set and done.

We got some operating history in that asset. We can look at whether or not at MLP allows us to capture incremental value from it, but that’s not a near-term priority.

Got it. Thank you very much.

Hi, this is Scott Willis on for Ed. I sort of quick one on the Eagle Ford, so I mean it looks like your production is ramping pretty nicely and the proved well economics are attractive as well.

I was just wondering what your expectation is for when Eagle Ford may begin to contribute to the free cash flow of Marathon as a whole and I just have one follow up.

Yeah, we’ve said consistently I think and the time we did the Hilcorp acquisition that we saw the Eagle Ford turning cash flow positive in 2014 and that is still the case.

Okay, great. And then just on the Eagle Ford infrastructure, it looks like you’re spending about $190 million this year.

I was just wondering, how you’re spending may look going forward in relation to that over the next few years.

Yeah, I think this year is going to be about a half where we were last year, a little more than that and I think we would expect 2014 to be half again at that point and I probably don’t want to comment much beyond that in part that’s going to determine at what level again do we want to focus in on a plateau type of production that we would build out to.

Okay, great. And then just last one on the Bakken well, do you have a pre-drill or resource expectation there.

I believe we did have that in our presentation and I want to say, it’s we’ve said 250 million to 800 million barrels of growth resource potential above range.

All right. Thank you.

Hey, guys. Good afternoon.

Janet, I just wanted to follow up with the earlier question, I just want to make sure I understood. On the deferred tax as a company as a whole, not just in the U.S.

as a company as a whole, should we assume that in this year as we turn into a positive cash flow item.

Next year, yeah, and well – yeah, this year 2013, yes.

Right.

Already turning to a positive cash flow item.

Okay. And Clarence, it’d great that you provide some data on Eagle Ford on the unit cost structure.

Do you have a similar data that you may be able to share on Bakken?

I don’t think we’re prepared to show that. The Bakken has grown at a more modest and measured pace, and it has not had the kind of impact on our overall U.S.

aggregation that we’ve seen in Eagle Ford. We’re trying to not get into a place, Paul, where we end up giving detailed numbers on all of our major assets.

But Eagle Ford we felt we needed to do it because at the rate that it’s growing and the impact that it’s having not just on our U.S. business but the corporation as a whole, we felt we needed to give investors’ guidance on that asset because it’s fairly unique in our portfolio at this point.

Clarence, in the Eagle Ford, the wells that you’re going to drill in 2013, are they – what’s the percentage going to be in the closing window and comparing that to 2012?

Yeah, I think Paul, it’s about, let me check, I want to say about 75% or 75% to 80% of our wells are in the high GOR trend, but the bulk of the rest are in the condensate window. And I think that’s – we’ll confirm that, but…

Do you have that number for 2012, so I just wanted to see that how that is being shift?

It was actually about the same, Paul, in 2012. So even though we have said we’re going to focus as much as we can in the high-GOR window this year because of the lower NGO and gas prices.

Last year with trying to hold leases and meet our obligations as it turns out, we’ll have about the same proportion in the high GOR window in 2013 as we did in 2012. Had we embarked on our original plan before we saw the collapse in NGO prices.

We have a much percent in the condensate window. That was part of our plan originally was to accelerate our drilling there, but again with what’s happened with NGO prices and we redirected that to the high GOR area.

Thank you.

Thanks. Good afternoon.

I think got the well is of the Eagle Ford at about $8.5 million per well, where you guys are at right now. Well, how much of your wells coming in at the Bakken?

Probably $8.5 to $8.8 million.

Okay.

We still think, Faisel, that’s best-in-class up there.

Okay. Fair enough.

Any more potential improvement on that number going forward to the year or is that pretty much as kind of…

Little bit we were in 2013, most of our wells are going to be on pad drilling, but we don’t see as much savings on pads in the Bakken because to a certain extent we are doing at the Bakken for access to locations topography issues and we actually end up drilling longer laterals from some of the pads that offsets some of the cost savings you get in less movement, less move days. So, we don’t see a lot of improvement at this point Khan, but we continue to believe our costs are going to be the best in class.

Okay. Fair enough.

And then just on the per unit profitability in the U.S. E&P.

You’ve certainly have ramped up the production in a pretty high clip in the Eagle Ford and the Bakken. And just want to understand, when do we see that sort of bottom line results from all that production ramp, because when you look at the 2012 per unit cost, per unit profitability came down versus 2011.

So, just want to understand how you guys are thinking about per unit profitability of this sort of assets going forward over the next couple of years?

Yeah. I think, certainly the cash – the unit cash margins are going to – going to be strong because as we’ve shown here, our cash cost whether fuel level controllables or the other costs are coming down and driven a large part by the higher volumes.

The earnings contribution is going to be a bit more muted and again it comes back to the impact that Eagle Ford has on the overall DD&A rate. So, when you look at 2012 actual and the 2013 guidance, we’ve given you the 2013 DD&A rate is going up pretty significantly and that is largely due to the Eagle Ford barrels now being a larger component of our U.S.

production. So, as we see that Eagle Ford DD&A rate come down in subsequent years as we book both performance reserves as well as the higher and hopefully initial bookings as our confidence in the reservoir performance growth.

We’re going to see that DD&A rate come down, but in the mean time, it is going to have that impact on earnings margins while cash margins, I think are going to in a continued improve. With RF force, as I mentioned before seeing declines in our Gulf of Mexico barrels which had been very strong cash flow providers in the past.

Fair enough. And then, last question from me.

On – it seems like if I read your numbers correctly on the infrastructure that you guys have spent in the Eagle Ford and what’s you plan spending in the Eagle Ford that you’ll have over $1 billion sort of invested capital in sort of midstream and infrastructure assets in the Eagle Ford. In the long run, I know there was a question on the MLP, but do these assets get sold eventually, when you reached sort of that peak production level or do they have to remain part of the upstream portfolio and what’s your opinion on and I believe these assets have to remain with the company or not?

Well, again, I’m not sure that we get quite to a $1 billion. My math that didn’t get me there.

But it is does become a very significant investment nonetheless and I think obviously the number one priority for us in terms of that infrastructure is flow assurance and the ability to move to where we see the best realizations. So, if we can achieve that, that’s why I come back to this question around MLPs.

That’s not our primary interest today. Ultimately it’s an MLP or it’s a flat out sale of the assets someone else, who will own them and operate them and we’ll pay a tariff or throughput the.

We’ll certainly look at that. But again, you don’t want to have whatever ultimate production is out here well over 100,000 barrels a day held hostage to midstream assets.

You want to be able to control that. So, you can control again the ultimate commercial – commerciality and marketing of your barrels.

Great. Thanks for the time.

I appreciate it.

Hi, good afternoon. Thanks very much.

I just wanted to ask a couple of questions on – kind of reconciling the DD&A costs especially in the U.S. and the Eagle Ford on a go forward basis for 2013 to the F&D costs.

Given that you talked about preliminary F&D being about 17 per BOE, but attributed the lot of the bookings to the Eagle Ford and Bakken and Oklahoma. Just trying to look at how the F&D kind of reconciles with the DD&A expected in U.S.

E&P and further there is some infrastructure costs that are loaded into the DD&A, but maybe wouldn’t be reflected in the F&D costs, and then I’ve got a follow-up.

Well it’s not a simple calculation, Kate I think there is a component of midstream in the DD&A rate, but it’s not a big component. In the DD&A rate obviously are the acquisition costs that we’ve incurred in the Eagle Ford, so that is the substantial component of it.

The other thing is when you calculate DD&A rates, it’s largely on the P1s of approved developed reserves whereas when you look at our F&D costs, it’s proved develop and proved undeveloped. So you’ve got a larger reserve – proved reserve figure in the F&D cost than you would have in the DD&A rate.

And I think those are primary reasons.

Okay, and then my related follow-up is whether the idea that you are not able to book the whole well EURs initially whether we could then expect to see maybe a catch up or a sudden sort of influx of significantly more efficiently added reserves, maybe in 2013 or in 2014 as you’ve kind of proved performance in the place and whether that would then turned lower F&D costs in future years. Thanks.

Yeah, it’s certainly – it goes to future reserve bookings and that goes to F&D costs and they are going to go to DD&A rate and two things happen. One is as you begin to produce the well in a current year you will book as I’ve said a portion of the EORs then you will book the rest over subsequent years as you see performance and as our reserve auditors get the comfort that it’s more likely than not that these reserves are going to be – are going to be recovered and so you got incremental reserve bookings strong performance.

You also potentially as you go through the future years and the confidence in the EOR grows your initial reserve booking. At the time you bring that well on production will rise as well.

So, all of that contributes obviously to F&D cost as well as it does to lowering the DD&A rate over time. The way DD&A rate works if you look at just the life of a project, when you start out in the early days of production, the DD&A rate is way too high.

And when the last barrel is produced the DD&A rate is way too low, somewhere in between there it really is the average. It is the right number.

But that’s kind of the nature of these emerging plays, where there isn’t a lot of long production history that can give us a certainty to book the full reserves upfront.

Okay, great. Thanks for the clarification.

Yeah good afternoon. Clarence it sounds like you want to withhold comment on the Eagle Ford pilot programs until Q2.

Can you speak it also I think the five distinct projects you are running that’s still the numbers I think falling off and also are there any open choke well as you think is going to run some of the broad object I can prove your point it does?

Okay. John we have nine pilot projects underway and we’re withholding – we’re not withholding comment because we’re trying to hide anything.

It’s just as you recognized. It’s not until you get meaningful production performance out of these pilot projects that you can begin to draw some conclusions and as it has been suggested to me by my people where even to do so, to draw conclusions by the middle of this year, we’re pressing it a bit.

But nevertheless what we’re looking at is pilots to test the lateral displacement of the wells, the horizontal displacement of wells within the reservoir as well as different stimulation methods including to your point, some of the wells looking at larger choke sizes. So, we’re on a course to learn as much as we can, as rapidly as we can in the Eagle Ford, so that we can then make that part of our standard operating practice and as we drill 300 or so wells a year, do so in the way that gives us the highest value.

Okay, thanks. And then just unrelated, in Kazakhstan, anything you could say as you’ve learned from the Europe well and how it in France, what they’re going to do in the next wells there in South?

It’s – we saw very good reservoir in the well that is encouraging. There appears to be perhaps a bit more structural complexity in the – at least on the harrier prospect than we may have thought the seismic quality there is not very good, so being able to image the sub-surfaces as well as we like is a bit challenging.

But I would say that at this stage, the prospects we see, the other prospect on the same block and the prospect on the other block are rather unique and I think we still hold out high hope for those and we’ll have those drilled pretty quickly here.

Okay. Thanks.

Thanks, good afternoon. In the Eagle Ford, if you keep with a 300 rig program roughly, at what point does production start to flatten out or level out, can you give us a sense of that.

I’m sorry, did you say with the 300 well program?

Yeah.

Again, I think that’s the question we are going to try to resolve in the second half of this year when we have the results of the pilot program. So, I’ll give you an example.

We have previously I think at the time of the Hilcorp acquisition talked about peak production of 125,000 BOE a day. As you can see from the numbers we’ve given for guidance for 2013, we should exit 2013 at about 100,000 barrels of oil equivalent per day.

Depending upon the overall size of the resource base we have here, which again is going to be determined in large part by the pilot results. We could have a decade of drilling out here at current drilling levels.

And so, exceeding 125,000 barrels a day I think is a very likely outcome, but I think as I indicated before, we don’t want to build up to some peak of say – let’s just say for purpose is 150,000 barrels a day only to see that decline within a year or two. Our preference would be to go to a lower level that we can sustain for a longer period of time again and so we can optimize our mid stream investment and not overbuild capacity that’s going to be underutilized.

So, I can’t give you a number. I think at this time, I think we see tremendous upside for this play.

We’re going to be in this play for a long period of time and as we get, get the full data set from our station pilots, we’ll be able to give better guidance on where we see this has set ultimately getting to.

I appreciate the color. And then, just in terms of the second question.

You got a very active exploration portfolio going on. Which one prospect you’d see the most excited in terms of the resources upside that you’re testing here in the first half.

Would it be that the Gabon well?

If I do that, I’m going to put the Gregory on it. I hate to do that.

That’s bad luck. They are all good prospects.

Okay. Thank you.

Hey, guys. Good afternoon.

Just a quick question. First, I wanted to make sure, I heard clearly the 6% to 13% stretch target for production.

Could you clarify the timeline on that and what that includes just as that totally we’re looking at excluding Libya?

It’s…

Yeah go ahead Howard.

That’s total upstream production excluding Libya out of both 2012 and 2013 and excluding the Alaska asset at both 2012 and 2013. So the way we casted early last year was, we were going to grow at 6% to 8% excluding Libya and dispositions.

And so Alaska was disposed, so we’ve taken that out of both years and Libya as well. So that’s where you get to the 6% to 12% to 13% excluding those.

But, the target we set last year was 6% to 8%. That’s the target we’re living by.

Sure. Absolutely, absolutely.

And just a short follow up then – or even a separate question, excuse, if you have it in front of you, what is comprised of other U.S. production at this point in time.

How much of that is Gulf of Mexico and what else is out there?

Gulf of Mexico, we’ll give you that number here. Rocky Mountain, some non-operated Permian, some Oklahoma, East Texas, conventional plays, those are the majority of the other U.S….

Okay.

Gulf of Mexico is 18 in 2013.

Well, Gulf of Mexico.

Gulf of Mexico is 18, I’m sorry?

Yes.

Okay. Thank you very much.

Hi, guys. Thanks for taking the question.

Apologize if you mentioned this already, but did you have any negative natural gas reserve revisions last year?

We did do to prices, but very minimal, not large parties.

Okay. It’s immaterial basically?

Yeah.

Okay. And then just a quick one on going back to the, what you mentioned about the Canadian potential sale, as you know there has been a lot of political debate in Canada over allowing foreign acquisitions particularly in the Oil Sands.

Do you see that as a hurdle to potentially monetizing a portion of that asset.

No. I would only say that I think that the recent Canadian announcements around foreign engagement in their assets is actually been a help because if we were to do a sale of a portion of our interest in AOSP.

It would be a non-operated interest in a joint venture and that is something that they’ve actually given a greater certainty around, greater confidence in being approved. So, it’s actually removed an uncertainty I would say that was out there previously.

Well, I appreciated it guys.

Okay.

Yeah, hi. Just a quick one on reserve bookings.

I guess philosophic. You guys, are being more conservative than your peers and as you’re getting into more on conventional exposure.

Why don’t you have comparable 5% interest. Many of your peers are in the 30s or higher.

John, I think well actually this year is pretty close to 30% then if you back out the oil sands which of course is essentially – and actually are more than that. I don’t have all the numbers in front of me, but I don’t – we’ll think of ourselves is conservative in fact we try to go straight up the middle of the fair way following the SEC guidelines, which as you know are inherently conservative.

Yes, right.

What we think, if it is ultimate EUR is actually prove was probably because the definition of prove was first probable is as likely as not – is this likely is not that you will outperform as underperformed?

Okay, Janet. Most of your larger peers are in the 40s, and I don’t think you were quite that high even though just to get out, but thanks.

There is a quick one for Janet. Any new hedges you put on beyond and ones you put on back in August?

No.

Thank you.

Thank you, Christine. And we appreciate the interest in all of those callers and those who listened to the call today.

If you have any additional questions, please don’t hesitate to give Chris or myself a call. Have a great evening.

Thank you and good bye.