Seeking Alpha
We cover over 5K calls/quarter
Profile| Send Message|
( followers)  

Marathon Oil (NYSE:MRO)

Q4 2011 Earnings Call

February 01, 2012 2:00 pm ET

Executives

Howard J. Thill - Vice President of Investor Relations & Public Affairs

Clarence P. Cazalot - Chairman, Chief Executive officer, President and Member of Proxy Committee

David E. Roberts - Chief Operating officer and Executive Vice President

Janet F. Clark - Chief Financial Officer, Executive Vice President and Member of Proxy Committee

Analysts

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

Arjun N. Murti - Goldman Sachs Group Inc., Research Division

Edward Westlake - Crédit Suisse AG, Research Division

Paul Sankey - Deutsche Bank AG, Research Division

Evan Calio - Morgan Stanley, Research Division

Paul Y. Cheng - Barclays Capital, Research Division

Blake Fernandez - Howard Weil Incorporated, Research Division

Faisel Khan - Citigroup Inc, Research Division

John Malone - Global Hunter Securities, LLC, Research Division

Mark Gilman - The Benchmark Company, LLC, Research Division

Pavel Molchanov - Raymond James & Associates, Inc., Research Division

Katherine Lucas Minyard - JP Morgan Chase & Co, Research Division

Howard J. Thill

Welcome to Marathon Oil Corporation's Fourth Quarter 2011 Earnings Webcast and Teleconference.

The synchronized slides that accompany this call can be found on our website, marathonoil.com. On the call today are Clarence Cazalot, Chairman, President and CEO; Janet Clark, Executive Vice President and CFO; and Dave Roberts, Executive Vice President and COO.

Slide 2 contains the forward-looking statement and other information related to this presentation. Our remarks and answers to questions today will contain forward-looking statements subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied by such statements.

In accordance with Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995, Marathon Oil Corporation has included in its annual report on Form 10-K for the year ended December 31, 2010, as amended, and subsequent Forms 10-Q and 8-K cautionary language identifying important factors, but not necessarily all factors, that could cause future outcomes to differ materially from those set forth in the forward-looking statements.

Please note that in the appendix to this presentation, there is a reconciliation of quarterly net income to adjusted net income from continued operations for 2010 and 2011, preliminary balance sheet information and cash flow, first quarter and full year 2012 operating estimates and other data that you may find useful.

Moving to Slide 3, our fourth quarter 2011 adjusted income from continuing operations of $552 million was a 31% increase over the third quarter 2011, while earnings per share increased 32% over the same period as a result of the share buybacks in the third quarter.

As indicated on Slide 4, earnings before tax for the E&P segment increased $46 million. However, the Oil Sands Mining and Integrated Gas segments both decreased $42 million.

The $202 million decrease in the consolidated tax expense for the fourth quarter was largely a result of the third quarter's noncash tax charge of $227 million. This charge was related to the expectation that we will not be fully able to utilize foreign tax credits generated in 2011.

The corporate effective income tax rate was 55% for the fourth quarter. For 2012, we expect the overall effective income tax rate, excluding Libya, to be between 55% and 60%. Please remember, the actual rate can vary quarter-to-quarter based on the level of liftings and earnings by tax jurisdiction or what is commonly referred to as production mix.

As shown on Slide 5, the E&P segment's fourth quarter earnings increase of $228 million compared to the third quarter was largely driven by lower segment income tax expense for the same reason I just discussed and by an increase in sales volumes. These were slightly offset by higher DD&A and other expenses.

Slide 6 shows our historical E&P realizations and market indicators. As highlighted, the differential between WTI and Brent narrowed during the quarter with WTI strengthening by $4.52 per barrel and Brent declining by $3.94 per barrel. As our production is more highly leveraged to Brent, we saw a decrease of $0.72 per boe in our average realizations.

As shown on Slide 7, fourth quarter E&P production available for sale, including Libya, increased 10% primarily as a result of new wells coming online in Norway, the Eagle Ford and the Bakken and resumption of production in Libya. Also contributing was higher reliability in the U.K. Sales volumes in the fourth quarter increased approximately 5% from the third quarter. Overall, there was about a 16,000-boed swing in liftings with the third quarter being overlifted by 6,000 boed and the fourth quarter underlifted by about 10,000 boed. In the fourth quarter, Europe was underlifted by approximately 800,000 boe, while EG was overlifted by approximately 200,000 boe. There were no liftings in Libya, resulting in an underlift of about 350,000 barrels.

We ended the year approximately 4 million boe underlifted with 2.1 million boe in Alaska gas storage and approximate cumulative underlift positions of 300,000 boe in Europe, 400,000 boe in EG and 1.2 million boe in Libya.

Slide 8 shows the more than 18% growth in E&P production available for sale since the beginning of 2010, excluding Libya. The lower available-for-sale volumes in the second and third quarters of 2011 were largely driven by unplanned downtime and seasonality in the base business and declines in the Gulf of Mexico.

Reliability increased in our base business during the fourth quarter, and volumes increased as a result of our ramping up the rig count, particularly in the Eagle Ford, and better performance in the Bakken.

Slide 9 shows the projected growth in our Lower 48 onshore production from 75,000 boed in the third quarter 2011 to between 120,000 and 130,000 boed in the fourth quarter 2012. The growth from the third quarter to fourth quarter 2011 alone was over 20%, going from 75,000 boed to 91,000 boed.

Slide 10 shows Marathon's E&P cost structure by category with field level controllable costs remaining relatively stable over the year at around $5 per boe, while DD&A declined primarily as a result of lower Gulf of Mexico volumes.

Turning to Slide 11, the fourth quarter E&P income per boe increased 60% compared to the prior quarter. This increase was primarily a result of lower income taxes, while total operating cost per boe were relatively flat.

Slide 12 shows Oil Sands Mining fourth quarter segment income was $63 million compared to $92 million in the third quarter. This reflects lower volumes due to unplanned maintenance and higher costs due to changes in inventory levels, partially offset by higher realized prices and lower income taxes. Net synthetic crude sales for the quarter decreased 6,000 barrels per day to 44,000 barrels per day.

To finish out segment reporting, Slide 13 shows the Integrated Gas segment income was $20 million compared to the $55 million recorded in the third quarter 2011. The fourth quarter decline was primarily a result of lower Henry Hub-based LNG sales prices and a gain on the sale of the Kenai LNG facility in the third quarter.

Moving to Slide 14. Our proved reserves increased from 1.6 billion boe at the end of 2010 to 1.8 billion boe at year-end 2011, while the percent liquids increased to 75% and percent developed increased to 78%. We replaced 212% of our overall 2011 production with reserve life moving to 12.4 years at the end of 2011.

Slide 15 provides an analysis of preliminary cash flows for the fourth quarter 2011. Operating cash flow from operations before changes in working capital was $1.1 billion, while working capital changes from operations resulted in an $84 million use of cash. Cash capital expenditures for the quarter were $858 million and dividends paid totaled $105 million, while asset acquisitions totaled $4.5 billion. The 2011 year-end cash balance was approximately $500 million.

While Slide 16 provides an analysis of total company preliminary cash flows for the full year, for the sake of time I will not go through this line by line.

As shown on Slide 17, at the end of the fourth quarter 2011, our cash adjusted debt-to-total capital ratio was 20%. And as scheduled, the debt service by U.S. Steel was removed from our balance sheet at the end of 2011.

Now moving to Slide 18, I'll turn the call over to Clarence Cazalot for a look at Marathon's 2012 priorities.

Clarence P. Cazalot

Thank you, Howard. By any standard, the operating and financial results achieved in 2011 by Marathon Oil employees were outstanding. And we intend to continue that momentum and build upon our successes in 2012 and beyond.

Highlighted on this slide are our 2012 priority objectives: to deliver 5% growth in Upstream production available for sale over 2011, excluding Libya as well as dispositions; to spend within the announced capital and exploration expenditure budget of $4.8 billion, excluding acquisitions; to achieve Upstream reserve replacement of 150% or greater, excluding acquisitions and divestitures; to drill key exploration wells in the Gulf of Mexico, Kurdistan and Poland and, importantly, to achieve success; to continue to upgrade our portfolio through selective acquisitions in our core areas as well as dispositions of noncore assets; and enhance our overall cost competitiveness, both at the field level and above the field.

Successful execution against these priorities is our focus. And in doing so, we'll generate very strong results relative to our competitors.

And now I'll turn it back to Howard.

Howard J. Thill

Thanks, Clarence. We will now open the call to questions. And to accommodate all who want to ask questions, we ask that you limit yourself to 2 questions. You may re-prompt for additional questions as time permits. For the benefit of all listeners, we ask that you identify yourself and your affiliation. Thank you.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from Doug Leggate of BoA Merrill Lynch.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

My first question is on the production guidance. And I don't know which one of you wants to take this, but it looks to us 2 things are going on here. First of all, Norway seems to be running an awful lot better than you had suggested this time last year. And also, if you listened to what Hess on their call, it looks like Libya, net to them, is already doing 30,000 barrels a day, which would imply something like 26,000 net to you. So can you address those 2 things in terms of your production guidance? And then I have a follow-up on Eagle Ford, please.

David E. Roberts

Okay, Doug. This is Dave. I'll take that. You're obviously very excited to talk about Norway. It's a great example of the operating prowess of the Marathon folks that Clarence was talking about. One of the things that we can highlight there is we remind people when we brought that on, we had a facility capacity of 120,000 barrels a day. Through our efforts in just simple debottlenecking in terms of non or low-cost type activities, we've added about 25% capacity to the FPSO, and we're capable of pushing about 150,000 barrels a day equivalent through it. In addition to that, it's a great story of big fields getting bigger, and you'll hear about that when we talk about the Eagle Ford in a minute. So we continue to have great success drilling infill wells out there, continue to bring on very high-rate wells. And on top of that, we're having outstanding reliability again due to the operations capability we have out there. We've got a full slate of drilling activities online planned for Norway. And right now, things are going very well for us, and we expect to be able to continue to carry out the plateau, which is what our intent was through this year and we would expect to end of next year as well. We do have a shutdown coming in the summertime that will take the field down for a period of time. But other than that, it's a great new story for Marathon, and we're obviously very proud of the team in Norway. As far as Libya goes, we have purposely removed that from our guidance because I think you're going to see some variability out there. There -- it is true we've seen a couple more fields added to the queue. Our rates this week are running between 25,000 and 30,000 barrels net, so the numbers you talked about relative to our partners would seem correct to us. But a couple of things are going to come into play there in terms of are we just seeing flush production from the fields? We'll have to evaluate that as we get greater experience. And clearly, our abilities to perform maintenance, as was the norm before the difficulties in North Africa, could prove to be a challenge as the year goes on. So good news story in terms of their ability to restore production early, but we're going to watch it very carefully and that's the reason we've been a little bit hesitant to put numbers for guidance out there.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

My follow-up is hopefully a quick one. Your Eagle Ford, you said 17 rigs by the middle of the year, and now you're at 18 in the first quarter. As we look at your acreage, it looks very similar to EOG, and EOG, of course, has been reporting some, well, like some outstanding downspacing results. Can you just bring us up-to-date as to where your Eagle Ford position is? Whether you can accelerate the rig count even further, and whether or not you have had any downspacing pilots? And if so, what are the results of those?

David E. Roberts

Okay. Yes, Doug, that's a great second question as far as A, B and C, but we appreciate you giving us the opportunity to highlight some of the things that we're working on. First of all, I think we're going to stick to our view that we'll have 18 by the middle of the year. Obviously, we're -- we'll move as quickly as we can. And at 14 in January, we're clearly ahead of our pace in the field. The 18th rig, importantly, was the one that we added to our portfolio this year to do some of the downspace -- downspacing testing that we were looking at. And that's still part of our plan for 2012. I think the key for us is we do believe there may be an ability to accelerate some rigs into the play. We're looking at that carefully, particularly in light of some of the economic conditions across some of the other basins in the United States relative to natural gas, and we'll take a hard look at that. But importantly, we're moving down towards the -- what we would call the condensate window in our acreage, and we're very -- we've got 2 wells drilling right there as we speak. We spent most of our time -- to this point, the volatile window results continue to be very encouraging. The geology is holding up. This is going to be a great asset for us, and we're looking forward to the 200 wells that were going to get drilled this year in terms of a proving out concept, building rate and then also answering some of the questions about downspacing on a go-forward basis.

Operator

Our next question comes from Arjun Murti of Goldman Sachs.

Arjun N. Murti - Goldman Sachs Group Inc., Research Division

Just a question on some of the exploration areas. Think Exxon sounded a little less excited about pulling yesterday. I think you're still testing your wells. Any update there? Any update on the Niobrara? And then what should we be looking for in terms of the Gulf of Mexico exploration program this year?

David E. Roberts

Okay, Arjun. Yes, Poland, we -- we've essentially completed our first well. We took a full core and got a full suite of logs from it. The cores are in a lab in Texas. We'll be doing some whole core analyses there. They'll be further slabbed and then moved to our labs in Houston. And then we'll be doing some integrated analyses against the logs. So at this point, what we've seen is consistent with what we expected. It's -- we'll basically do 2 more wells like this in terms of taking a full data evaluation suite. We still expect to get 6 to 7 wells drilled this year. And so it's very early days in terms of us commenting on what one of our competitors said because we don't have any flow test data. But...

Arjun N. Murti - Goldman Sachs Group Inc., Research Division

And you're not planning to this year, flow test?

David E. Roberts

No, no. So we're going to do our science. We're going to do this right. We've done seismic. Not -- and let me back up there. I'm not saying Exxon didn't do it right, but we're -- we have our own program here, and we'll carry that out as far as it goes. In Niobrara, we've got 3 wells down frac-ed and completed. We're producing, either from a flowing state or a pumping state, between 100 and 200 barrels a day. Still very early. We're going to run the 2 rigs through the remainder of the year. It's a big basin, as you know, and we're basically testing 6 or 7 areas out there. So again, not discouraging, even though we do think that -- I'm glad that you classified the play as exploration because I think it's very frontier-ish compared to what we're doing elsewhere. The Gulf of Mexico, we're participating in 2 wells right now: Gunflint, an appraisal, which one of our partners is drilling; and the Kiltern [ph] exploration well, which Statoil is drilling, and we're a participant in that. We're going to get back on Innsbruck in July, August time frame, and we're hopeful as well to get that completed and then get started on our Key Largo prospect towards the end of the year. So it's an exciting year for us in the Gulf again.

Arjun N. Murti - Goldman Sachs Group Inc., Research Division

Maybe if I can ask just a follow-up to that. Clarence, you talked about selective acquisitions, divestitures. We've asked about the Gulf of Mexico in the past. How important is this year's exploration program to giving you confidence to continue to have interest in the area? If it meets with dry holes, which can happen in exploration, does that push you one way or the other?

Clarence P. Cazalot

Yes, I don't think, Arjun, it'd be fair to say that one year's results, particularly if it's 2 or 3 wells, is going to sway us completely off the Gulf of Mexico. But I think we're going to want to see at least a critical mass or representative set of prospects drilled out there before we make a go or no-go decision. But I certainly expect that with the portfolio we've got and drilling over the next couple of years, we're going to have the kind of success that we're looking for.

Operator

Our next question comes from Ed Westlake of Credit Suisse.

Edward Westlake - Crédit Suisse AG, Research Division

I guess you mentioned in your opening remarks or your answer to that, Dave, about some of the IP rates from the wells you're drilling in the Eagle Ford. You know I've seen numbers in the 400s, which obviously is a long way from the best wells that EOG has drilled, perhaps not the average. But can you explain why you think those IP rates came in a little low?

David E. Roberts

Well, I think it's -- and again, what we've said is the geology of the play is variable across the play because it's very large. And in the heart of the play, what we've talked about in the condensate window in our presentation is where we're -- where we expect to see this 1,500 to 1,650 boe per day IPs. In the volatile oils, you're going to see this 900 to 1,000 and in the black hole, you're going to see these numbers in the 400 range. And what we would say is as our program has developed and we have drilled wells primarily in the first -- in the latter 2 areas, our results are very consistent with those numbers. And we've got 2 wells going down into what we call the Sugarloaf, Sugarkane area, and we expect that will prove up the concept of the much higher IP wells that some of our competitors are claiming. But we're going to be consistent with our results. So as I said, the geology is holding up very well here. It's an outstanding play, big fields get bigger and we're very excited about getting our teeth into the heart of the play.

Edward Westlake - Crédit Suisse AG, Research Division

And just to follow up on the Woodford, the liquids-rich area. I mean, obviously that's been an area which some of your competitors are also talking highly of. Can you give us a rough range, say, your latest IP and well cost? 30-day IP, if you have it?

David E. Roberts

Yes, well, we're right now on the verge of just getting some of our wells in the heart of the play down, and we're still seeing well costs in excess of $10.5 million. So it's at just a little bit deeper area of the play. We recognize we're going to have to do better there. And we've got some tests that aren't of the 30-day vantage but just to give you an idea, we're seeing 4 million to 5 million cubic feet of gas, 90 barrels of condensate in the yield that you're seeing from this particular area. I think one of the things that we're concerned about here is those numbers sound very impressive, but obviously, gas wells don't do us any good. And as most of you all are aware, the NGL constituents in this part of Oklahoma is a little bit heavier in ethane you'd like. And so we're taking a hard look at this program not because we don't like it, we think the geology is great, but there may be other opportunities for us to invest that quantum of money somewhere else.

Edward Westlake - Crédit Suisse AG, Research Division

Good. And just to follow up on that last question in terms of other opportunities. I mean, the Eagle Ford's a great basin. What are your thoughts in terms of increasing your footprint across the U.S.?

David E. Roberts

Well, the Eagle Ford is the top basin we have in the world today, and I think we've been pretty consistent on that. We love the geology. We think that we're establishing a viable and effective operating presence consistent with what we do in other parts of the world. We'd like to have more of it, but it's going to have to be economic for us on a go-forward basis. And we'll certainly put as much capital work as we can down there.

Operator

Our next question comes from Paul Sankey of Deutsche Bank.

Paul Sankey - Deutsche Bank AG, Research Division

David, you just mentioned in the Eagle Ford that things are running ahead of schedule. I just wanted to slightly square the circle with, I think, an exit rate that you said would be 18,000 barrels a day in the Eagle Ford. You're falling just a bit short of that, and I just wanted to understand what, if anything, there was to be concerned about there. And as part of that same question, if you could also talk about the Bakken and, I believe, what's amounting to an acceleration of your activity there would be great.

David E. Roberts

Yes, I'd -- I'll start with the Bakken. It's obviously a very positive story in terms of leaving last year at 24,000. We've really been able to hold that rate through January. And we typically have some issues with weather up there because it can get pretty dodgy up there. I think one of the things that you'll see from us is we talk about having 6 rigs working, 1 that's doing recompletions and adding 1 more in the second quarter for a total of 8. And we're basically going to recast the rig that's doing re-fracs into straight-up drilling. So we're very excited about being able to continue the momentum in that play. And I would highlight one thing. As we've obviously gone to all 30-stage fracs, our early results are very good. We're very encouraged about it. The only thing that's -- that may hold us back a little bit in the Bakken is a lot of our effort is going to be directed towards the Diomedes area, which is basically on the fringes of the play. It's early days. We'll see if it holds up and is comparable to the other parts of the play. But I think I would look for continued good news out of the Bakken in terms of our ability to continue the momentum that we started towards the end of last year. Obviously, I'm never happy when we don't meet expectations because we don't make excuses here, and I'm not Pollyanna by any stretch of the imagination either. We ran into some issues that frankly were unanticipated in South Texas, and we talk about the engineering terms we used as we went to choke management philosophy. We cut a lot of wells back because we were very concerned about the longevity of the production in terms of recovery, because that's what we're about as an enterprise, and also the fact that we took over a lot of wells that weren't set up for long-term production. We just didn't have any tubes or so. And I'll be very clear here. Hilcorp did a great job with this asset base. They delivered us a top-class asset that was -- is built for speed, and we're going to do very well with it. But the heart of the matter is, is we just had some basic production work to go back and pick up. We're back on pace now in terms of seeing in the early part of the year 7 to 10 completions a month, and that's going to accelerate to somewhere on the order of 15 to 16 by the end of the year as we pick up additional frac crews and get our cycle times right on all the drilling rigs that we have. So it's not a positive, but what I would tell you is we're just thrilled to death to be in this basin, and we think we're going to be very successful and we're going to prove that to you quarter-over-quarter.

Paul Sankey - Deutsche Bank AG, Research Division

And David, I guess it's worth highlighting since we covered both the difference in crude pricing between the 2 basins. Can you just update us where your premiums and discounts lie right now?

David E. Roberts

Yes, as of this morning, the Eagle Ford is running basically $1.50, $2 positive to WTI. And that's something that we would kind of expect to hang in for the year. And the Bakken is still in the minus $7 to minus $10. It was minus $8 this morning up there, and that's really a question of distance to markets. We're seeing fewer disruptions this year in North Dakota than we did last year, but -- because the weather has been a little bit more agreeable. So I don't think those numbers are going to move around materially.

Paul Sankey - Deutsche Bank AG, Research Division

And Clarence, if I could ask you one. You've talked about 5% growth this year. There's clearly upside with Libya. And there are other things that were mentioned, generating free cash flow, which is in contrast to many of your competitors. I think I've got the sense that you're, and I think you've already said this, much more oriented towards disposals than acquisitions. Can you just confirm that that's the way -- because you mentioned both in your outlook? Just confirm that's basically the way you're thinking.

Clarence P. Cazalot

No, I think certainly, Paul, we're thinking in terms of both. And we've continued to say pretty consistently that we are looking at acquisitions in our core areas. Dave already mentioned to the extent that with good, solid economics, we could increase our position in the Eagle Ford. We look to do that. Same is true with the Bakken and other areas. And we stand by our earlier guidance of $1.5 billion to $3 billion of dispositions over the next 2 to 3 years, but that's frankly going to be driven by what we see as the opportunities to divest at the right price and, in fact, reinvest at good prices and good economics as well. So I wouldn't say that either is preferred at this point. It's a balance of how we go about high grading our portfolio.

Operator

Our next question comes from Evan Calio of Morgan Stanley.

Evan Calio - Morgan Stanley, Research Division

The Marathon family sure got us busy the last 12 months with restructurings. A lot of major questions really had been covered, but maybe a couple of follow-ups, one on Paul's question. I mean, on the Eagle Ford pricing, I know you've put it in reference to TI, but has the pricing structure shifted to an LSS (sic) [LLS] pricing dynamically the LLS is under 6 versus a TI correlation, for you? And then also, thanks for a lot of comments on the Eagle Ford. Any comments on kind of shortages you see in frac crew province? Or any other challenges that you're looking at kind of really managing here in your activity ramp?

David E. Roberts

Right, Evan. We saw that, as we talked about this last year in terms of the differentials, where we were seeing LLS minus or WTI plus. But as we see these differentials narrowing, I think that's the reason that you're going to see us continue to talk about it somewhere in between the 2. But ultimately, I think you're right. You're going to see this as an LLS marker because the -- most of this crude is going to go to the water, eventually. But it's materially changed this price point in terms of it roughly being $102 on today's price basis. So I think it's 6 of one, half dozen or another. The interesting thing about the second question is I'm not really sure that we're going to see any pricing improvement in terms of what's happening, particularly with pressure pumping, as some of the companies continue to say they're going to give up natural gas drilling. What we are going to see is the continued flow of more experienced crews into more active basins. And we've not seen any logistical issues like we saw last year in North Dakota with some sand deliveries. Everyone seems to be keeping up, both in South Texas and North Dakota, with capability. And we're thinking that the crews are going to get stronger, which ultimately will prove our efficiency and make us more money. So we may not see it on the cost side, although there's probably different opinions about that. But we're clearly looking to getting more experienced people flowing out of some of the gas-prone basins.

Evan Calio - Morgan Stanley, Research Division

That's great. And just a second question just on Angola just to confirm you're still on track for a 2Q start-up, and if you could give us color on the expected ramp. I know it's 14,000 plateau, but what does that ramp-up look like in 2012?

David E. Roberts

Yes, I think we're still on the view that you're going to see a Q2 start. And obviously, BP could give you more color on that. I think that's pretty consistent with what we expect. And we're going to play this fairly conservatively and say that we won't see 14,000 until '13. And so I would expect some sort of incremental ramp-up from the middle of this year into that rate in Q1 of next year.

Operator

The next question comes from Paul Cheng of Barclays Capital.

Paul Y. Cheng - Barclays Capital, Research Division

Janet, on the deferred tax item in your cash flow, we understand that for the total coverage, you'll probably get the cash flow benefit on that item from the -- in the U.S. due to the IDC deduction. And then you're probably spending some money or that you're paying some additional tax spend, the booked tax in the overseas. That's why for the first 9 months of the year, that, that item is a negative. Any rough estimate, based on the portfolio and your capital investment program, how 2012 is going to look? Are we going to see the IDC band that's actually showing up in the consolidated? Or is that going to get overwhelmed by the international?

Janet F. Clark

My guess is, of course, it depends upon the production mix as well as pricing, is that because the U.K., Brae and particularly Norway are in a position where actually our current tax, our cash taxes are higher than booked as the DD&A reversed, that, that will probably continue to outweigh or at least balance the deferred tax benefit that we did in the U.S. Starting January 1, of course we get to deduct 100% of our IDC in the year incurred, whereas as an integrated, we can only deduct 70% in that first year. And then, of course, it's just a timing difference, but we get amortized the balance -- 30% will get amortized over the remaining 9 years. So yes, we do get the IDC benefit in the year incurred in the U.S., but it does largely get offset, if not completely offset, by the international tax payment.

Paul Y. Cheng - Barclays Capital, Research Division

And maybe a little bit difficult. Janet, do you think by 2014 or so, that it will fit the other way or that you think that may last a little bit longer?

Janet F. Clark

Well, Paul, I don't like to predict anything. And certainly, going out 3 years on deferred versus current taxes and foreign jurisdictions is -- there's just way too many variables is the point. But way too many variables, I'm afraid. But our mix of production over time should be shifting to more U.S., and we'll -- you'd see U.K., Norway be a smaller percentage of production. So it can certainly happen.

Paul Y. Cheng - Barclays Capital, Research Division

Dave, the second question. Can you give us a quick update of the Oceania -- Ozona in the Gulf of Mexico? Has that start up yet? Or when is it going to start up? And also that if you can give us some well data for the last 2 months when it is under your control for Eagle Ford in terms of the 30-day IP and the well cost.

David E. Roberts

Okay, I'll go back to Eagle Ford. Basically, the well costs that we're seeing in Eagle Ford, drill complete and equip are still consistent with what we've said publicly, the $8.5 million range for these wells that we're working on. And we have added 7 wells over the last couple of weeks. And what I'll just point out because we don't have 30-day IPs on them yet, they are consistent with what we've said in our presentations in terms of black oil rates for 3 of them and volatile oil rates for 4 of them. So we expect the volatile oil wells to be in the 1,000-barrel a day equivalent IP when we get to those dates and the black oil ones to be somewhat less than that. So again, very consistent with what we predicted and we'll look forward to drilling some of the bigger wells as we move our program further south in our acreage. But then it did come on in the latter part of December last year, and it's had some issues with the host platform in terms of being up and down. It's clearly going to come in at the low end of our expectations. Currently it's producing, on a gross basis, about 4,000 barrels a day and 7 million cubic feet. We're going to continue to monitor it and see what it does. But again, I think importantly what I would say is this only marks the end of our legacy portfolio in the Gulf of Mexico that was too small, and we're moving into a different phase and focusing our efforts on bigger fields, both in the Gulf but more importantly in the Lower 48.

Paul Y. Cheng - Barclays Capital, Research Division

Dave, can I -- just quick one. Is Droshky still producing right now?

David E. Roberts

Yes, Droshky is running about 7,500 barrels a day, net.

Operator

Our next question comes from Blake Fernandez of Howard Weil.

Blake Fernandez - Howard Weil Incorporated, Research Division

I had a question on the production, I guess, guidance for the first quarter. If I'm not mistaken, it looked like fourth quarter actual production was about 378,000, yet first quarter guidance is 350,000 to 360,000. And I'm just trying to reconcile where the decline is coming. And then secondly, is it fair to think that first quarter is going to represent a trough in the production profile for the year?

David E. Roberts

Well, I think that the issue relative to the first quarter is worth noting I think we have before, is we've got a 30-day shutdown of EG coming that will begin the middle of March and then run until the middle of April. And so we've -- that facility will be completely shut down for that period of time as we go through an extensive turnaround, both of the LNG facility and a gas plant facility over there. And so that's that key driver in terms of what the production impact is going to be. Since we bridged it over the quarter, and we did that on purpose in order to create some balanced opportunity, we're clearly going to have issues across those quarters. But we expect resource plays to continue to grow rates, both in the Bakken and the Eagle Ford, throughout the year. So we should show inclining rates throughout the year.

Howard J. Thill

It's a minor point, Blake, but the 378,000 includes 3,000 of Libya. It's really 375,000 for the fourth quarter, excluding Libya. And the 350,000 to 360,000 that you spoke to excludes any Libyan production.

Blake Fernandez - Howard Weil Incorporated, Research Division

Yes, got it, Howard. The second question is on buybacks. I didn't really see much commentary in the release, unless I missed it, but it did look like the share count was reduced in the fourth quarter. And I'm just curious if you can comment on whether we could expect the buybacks to continue here in the first quarter.

Janet F. Clark

Blake, actually the buybacks all occurred in the third quarter, in the middle of the third quarter. So what you saw in the fourth quarter was the benefit of that share count reduction for the full quarter. And as you probably -- we get asked the question all the time: What is the priority use for our cash? Very clearly, the #1 priority as we go forward is reinvesting in the business in value-accretive projects. You will have noted that we increased our dividend last week. And share buybacks, as always, are on the table if, in fact, that is the best thing to do with the cash.

Operator

Our next question comes from Faisel Khan of Citigroup.

Faisel Khan - Citigroup Inc, Research Division

I just want to make sure on the CapEx plans for this year, $4.8 billion. I just want to make sure I have the components right. I mean, your -- in your previous sort of slides and guidance, you've said that the base business is $1.3 billion and Eagle Ford is $1.4 billion and Bakken is about $700 million. I just want to confirm if those numbers are still about right. And also, what's the balance of the CapEx being deployed towards?

Clarence P. Cazalot

Well, the numbers, Faisel, are about right and the balance was about $500 million in exploration, I think, that you didn't have in the numbers you just cited.

Faisel Khan - Citigroup Inc, Research Division

Okay. Anything else internationally that you guys might be spending money on outside of the base business?

David E. Roberts

We have an ongoing drilling program in Norway but in terms of the large quantums, I think you've hit it. It's Eagle Ford, Bakken, Woodford are the big drivers of our capital, and then the $500 million that Clarence talked about in exploration.

Clarence P. Cazalot

Yes, Faisel, we put out the -- one of the first times, I think, we've actually announced our final CapEx budget in December. We generally do it at the end of January, and we -- so it's early December, I want to say December 2, 3, we put out a press release outlining our 2012 budget that will give you all those details.

Faisel Khan - Citigroup Inc, Research Division

Okay, got you. It looks like going forward, if I look at the reserve replacement sort of numbers for the year, it came in around $19 per barrel equivalent for F&D costs, excluding the acquisition of the Eagle Ford. And then going forward, it looks like based on your projections for reserve replacement ratios, it looks like you're at about $22 going forward. Is that kind of -- I think that's that the right run rate to use going forward to use going forward for your kind of F&D costs.

David E. Roberts

Yes, I think we would have said $21, but that general range is probably a good way to look at the business. Obviously, it's -- I mean, we're clearly pursuing these unconventionals more heavily, and they tend to have a much more attractive F&D rate than that over time. But we -- I would support that as a number.

Operator

Our next question comes from John Malone of Global Hunter Securities.

John Malone - Global Hunter Securities, LLC, Research Division

Just a question on Kurdistan. You talked about some early production systems coming online this year. What's the status there just in terms of what you think production rate would be or timing? And have you spotted the second well, the second Swara Tika well?

David E. Roberts

Yes, we're drilling -- John, we're drilling that well right now. And so it's proceeding ahead. Tough drilling environment, as you know, but we're making good progress there. We're in the planning stages for what we would call either extended well tests or early production systems because sometimes our partners use different language. We'd expect to see that potentially on one or both of our outside-operated activities by the second half of the year. And I wouldn't want to speculate on the well rates. It's one of the reasons we're doing this, because it's a complex geologic area and we're going to want to see what these things do in terms of coming on and how long they stay that way. So if I can beg off on the rate, I would.

John Malone - Global Hunter Securities, LLC, Research Division

Okay, fair enough. And just one on international, on Equatorial Guinea. We hear the government talking periodically about expansion on their -- expansion of the LNG facility and proving up gas in neighboring countries. You guys have been pretty quiet on that. Any comment on that on the government's plans or what they want to do?

David E. Roberts

Well, obviously, we're participants in those discussions, and we've done very well with our LNG franchise in Equatorial Guinea. Clearly, we think there needs to be more work to develop gas resources in the country to support a future train. Our first priority has always been making sure that we keep Train 1 full because that's the most economically value-added opportunity not only for Marathon, but also for our partners and particularly the Government of Equatorial Guinea. I think they understand that. We're very interested in opportunities to create value in Equatorial Guinea. But there's -- as we've said in our responses, a lot of work to be done in terms of making sure that there's sufficient gas resources and that the commercial arrangements are in place to make sure that it's a fair return for the risk that we would take in that venture.

Operator

Our next question comes from Mark Gilman of The Benchmark Company.

Mark Gilman - The Benchmark Company, LLC, Research Division

I've got a couple of things, if I could. Janet, is there a potential tax on the buyback that MPC is -- has now authorized? And if so, is it either insignificant or are you comfortable in giving your approval to them that the indemnification is satisfactory?

Janet F. Clark

Yes, this is contemplated in the tax rate agreement that MPC obtained an unqualified tax opinion that the kind of stock repurchase program and the MLP prospectively would not disqualify in any way the tax-free status of the spin-off.

Mark Gilman - The Benchmark Company, LLC, Research Division

Dave, let me go back to this stricter choke management issue. I guess I'm little bit confused. You cut some of the industry wells back a little bit, yet the year-end forecast, the 30,000 a day, didn't seem to change. And I don't see a change in the activity level or indicated spend. Can you help me reconcile those?

David E. Roberts

Yes, I don't think that they're not reconcilable at all. I think that the key thing for this year in terms of building rate is we're going to put 200 wells down in this play, and the majority of them are going to be in very high-rate areas, that's what we would say, in addition to some of our leasehold activities. And so what we would say is we're very comfortable with the fact that we're at 15 instead of 18 in terms of being able to build the rates we need on a go-forward basis to deliver the results. Because as our teams have gotten into this play, they've clearly refocused a lot of the perspective activity that we had on some of the more highly prospective areas. So I think we're in pretty good shape. Basically, what we would say is just to go back and talk about flow management or choke management. A lot of this stuff was done at a very rapid pace because Hilcorp wanted to deliver us an asset that we could pick up and run with. And so we had to go back and do a lot of stuff that we would just call normal production engineering, making sure that the wells flow longer before you could get our initial lift installed. So it's -- this is nothing out of the ordinary, and we consider it kind of a minor bump in the road.

Clarence P. Cazalot

Hey, Mark, a way to think about it it's not a change in choke management from Marathon's standpoint, it's a difference in how we do it relative to what Hilcorp was doing at the time of the acquisition.

Mark Gilman - The Benchmark Company, LLC, Research Division

Okay, Clarence. Let me just sneak in one more. Earlier in '11, you folks indicated that you were potentially going to solicit a minority partner of unspecified size in terms of your Gulf of Mexico portfolio. Give me an update on where that effort stands. Has it been back burnered? Is it still alive?

Clarence P. Cazalot

No, we certainly looked at opportunities, Mark, to bring in a partner in our Gulf of Mexico portfolio in large part to not just share the risk on certain prospects, but really to participate across the full spectrum of our prospect inventory. And frankly, we didn't see any responses to that, that were acceptable to us. And so we have no intention of pursuing that anymore.

Operator

Our next question comes from Pavel Molchanov from Raymond James.

Pavel Molchanov - Raymond James & Associates, Inc., Research Division

Just 2 quick ones about Poland. Recognizing that you only drilled one well, can you share the drilling cost?

David E. Roberts

Yes, Pavel, that well will be about $12 million.

Pavel Molchanov - Raymond James & Associates, Inc., Research Division

$12 million. Okay, great. And then just a little bit more broadly. Are you seeing any budding opposition in Poland to frac-ing or shale drilling in general as one of your peers recently experienced in Bulgaria?

David E. Roberts

No. On the contrary, and we've actually spent a lot of time, including recently here in Houston, with senior Polish officials. And we've also spent some time familiarizing them directly with our operations in places like North Dakota so they would have a sense of what it is that needs to be done here. They appreciate that hydraulic fracturing will be required in order to develop these resources, should they prove to be prospective. And they're very interested in making sure that we do enough work together with them to make sure that popular opinion stays on the side of energy security versus making a choice of -- which we don't think is a correct choice of against the environment. Because consistently, we've said to them as we operate, we can protect the environment and still deliver our results. So far so good, but it's an area that we certainly keep a close eye on.

Operator

Our next question comes from Katherine Minyard of JPMorgan Chase.

Katherine Lucas Minyard - JP Morgan Chase & Co, Research Division

Dave, can I just go back to a comment that you mentioned about kind of testing some of the -- maybe some more noncore areas of the Bakken? Did I hear that correctly?

David E. Roberts

Well, I think if you look at our play fairway, we have all these unusual names, but in the heart of the play for us in Dunn County, we talk most prospectively about our Myrmidon area and the Hector areas. A little bit less so Ajax. But then off towards the Montana side of the play is an area that we call Diomedes. We took an acreage position out there some years ago, which we've got to go out there and do some lease drilling out there. It's early days. And as -- if you followed us, you know we're always pretty conservative in the Bakken. And so we're not overhyping that particular area. Obviously, we hope it's as prospective as what we've seen in Dunn County, but we'll get some drilling results and we'll see.

Katherine Lucas Minyard - JP Morgan Chase & Co, Research Division

Okay. And so can you talk about maybe what portion of the capital in the Bakken you're spending this year is committed to that type of activity and, maybe even more broadly, of the -- I think it's about $2.7 billion that you have in your 4 key North American resource plays? What portion of that is maybe committed to a similar type of activity that maybe isn't drilling in the core but might be testing some prospective areas?

David E. Roberts

Yes, we don't do a whole lot of that anymore. We really try to focus our efforts in -- and so basically, what I would tell you is the $1.4 billion we have directed to Eagle Ford is all along stuff that we consider prospective and economic. Obviously, there's a variability in the play, but it's all driven towards adding substantial value. In the Bakken, when we talk about that area, you're probably only talking about one rig here. So essentially, an 1/8 of the overall $700 million program. And then I would argue that the 2-rig program in the Niobrara would certainly fall into that type of an area. And so round numbers, I guess you'd be talking about between $200 million and $300 million of the total quantum that you referenced being directed towards things that -- it might not charm you by the end of the year.

Katherine Lucas Minyard - JP Morgan Chase & Co, Research Division

Okay. All right, great. And then can I just quickly clarify? On the 30-day turnaround or the shutdown at EG, can I confirm that that's just all your volumes in EG, not just the gas volume?

David E. Roberts

That's everything.

Operator

Our next question is a follow-up question from Ed Westlake of Credit Suisse.

Edward Westlake - Crédit Suisse AG, Research Division

Just a very small follow-up. Just on the depreciation, particularly in the U.S. Obviously, Droshky made that a little bit some more volatile in 2011. But $25 to $27.50, I mean, is there any sort of still sort of residual Droshky impact in that? And when do you think that would start dropping as you get your production up onstream.

Howard J. Thill

Hang on just a minute, Ed. We're pulling that up.

Clarence P. Cazalot

Yes, I think we made a prediction for DD&A in our forward estimates.

Edward Westlake - Crédit Suisse AG, Research Division

Yes, yes. The...

Clarence P. Cazalot

It's $25 to $27.

Edward Westlake - Crédit Suisse AG, Research Division

Yes. So I just wonder, that seemed a little high, I guess. I mean, I know you're spending on shale and there's always upfront costs. So I was just wondering if there's any Droshky in there or is that sort of a clean number we should use as a base.

David E. Roberts

Well, I think our expectation is -- and we've said -- pretty much said that the Droshky will likely decline out of the portfolio in the first half, and so you're going to have some effects from that in the first half of the year. But broadly, it's our activities in the unconventionals.

Operator

Our next question is a follow-up question from Doug Leggate of Merrill Lynch.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

Just a couple of clarification points, please, guys on the Eagle Ford. Dave, I understand the exit rate was done on the tubing issues. But can you tell us what the peak rate in the Eagle Ford was in Q4, where it is currently? And what you -- whether or not you've got the infrastructure in place to accommodate comfortably your planned ramp-up this year?

David E. Roberts

Yes, I think we would say that the peak rate in the Eagle Ford was on the order of between 14,000 and 15,000, which is where we are today. And what I would say is that our internal infrastructure is designed and being constructed to match our growth plans on a go-forward basis. Our ability to connect to the larger outlets and exit avenues, both for gas and for liquids, are in place. And so we do not expect there to be any infrastructure issues with our ability to grow our rate from 15,000 today to 100,000 in 5 years.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

Great stuff. And Dave, you also made comments about gas when you were -- in your earlier remarks, I think, in response to one question. Are you guys drilling any dry gas holes right now? And maybe you could help us with the rig allocation across your plays?

David E. Roberts

Yes, great. First of all, my drilling people are clamoring after me to make sure that the total well costs in Poland, with all the testing we did, was closer to 15. They're good, but not that good. So I want to correct that. You know, Doug, if I drill a gas -- a dry gas well, I'd get in trouble. And so we're not trying to do that. The closest thing we have is in the Woodford. And we were still seeing a lot of liquids plays. We're just not directing any money to gas wells. I don't think we have any lease expiries that we're chasing in terms of pure dry gas. So in terms of our rig deck right now, we've got 14 in the Eagle Ford and that number's obviously going to go to 18. We're running 6 in the Woodford and obviously monitoring that very closely. We've got 2 in the Niobrara, one or 2 more up in Wyoming doing some work for us up there, and essentially 7 in the Bakken right now and that will be going to 8. So as we see it, we've got 35 to 40 rigs on contract in the frame of reference for this year with obviously the ability to expand or contract that as we need to.

Operator

Our next question is a follow-up question from Paul Cheng of Barclays Capital.

Paul Y. Cheng - Barclays Capital, Research Division

Two quick questions. In Angola, I think at one point, you guys have been marketing your remaining interest as part of the FSS [ph] program. Wondering if that is still being actively pursued or that you have not seen satisfaction bid so that -- similar to the other area that you are not marketing on that one? And also, that -- can you tell us when the next project is going to finish and which project is going to be the next to go in your Block 31, 32 interest? The second question, on Eagle Ford. I think in your forecast by 2016, you expect about 20%, 25% of the production going to be coming from outside the Hilcorp asset. When you will you start testing the area outside the Hilcorp asset?

David E. Roberts

Paul, I think we're -- what we said is we think Hilcorp can deliver the rate that we've -- we talked about, and we're going to continue to look at areas outside of the core. But I think it's important for people that follow us and our investors to understand, we think the heart of this play, which is what we thought with Hilcorp, is where we should focus our activities and that's where we're going to drive the rate from. And so we may get some more granularity on what our plans are for some of these other areas, but my intention is to drive our activity in the Hilcorp acreage and deliver the numbers that we talked about from that.

Paul Y. Cheng - Barclays Capital, Research Division

Dave, can I just -- I want to make sure clear. That is why in your presentation, 2016, you're looking for 100,000 barrels per day and maybe over 100,000 barrels per day for Eagle Ford. Is that 100% coming from Hilcorp? Or is only 80,000 coming from Hilcorp? Because it seems like there's 2 different number that I recall.

David E. Roberts

From the acquisitions that we closed in the fourth quarter, that's where we're going to get that rate from. And so that all corresponds to the broader -- what we would call the broader Hilcorp footprint.

Paul Y. Cheng - Barclays Capital, Research Division

Okay, got you.

David E. Roberts

Right. So the Angola questions, first of all, I think you're reflecting on some speculation in the press relative to a commercial arrangement that we never talked about publicly, and we're clearly owners of both Block 31 and Block 32 on a 10% basis. And so I wouldn't comment on anything that might appear in the press relative to our intentions to the contrary. The other thing I would say is I'm also not going to speculate on what the next opportunity for development would be. And that's a better question to ask our partners, Total in Block 32 and BP in Block 31.

Paul Y. Cheng - Barclays Capital, Research Division

Can you give us a kind of time line that when you would expect you have something announced?

David E. Roberts

No.

Operator

Our next question is a follow-up question from Mark Gilman of The Benchmark Company.

Mark Gilman - The Benchmark Company, LLC, Research Division

Dave, a real quick one. As you tie in some of the smaller accumulations to Alvheim Vilje, my sense is that your working interest in the licenses that underlie some of these is a little bit less than what it was in the core area. Is that accurate? And what kind of progression do you expect in terms of working interest in the volumes coming off that platform?

David E. Roberts

Most of the work that we're doing now is consistent with the core Alvheim area. And so when we talk about the Kameleon play, it's -- you're talking about the difference between Alvheim being 60-ish percent and Vilje being in the high 40s. Most of this stuff is going to be consistently in the 60s that we're adding.

Mark Gilman - The Benchmark Company, LLC, Research Division

So it ought to stay at the current rates, at least for a while?

David E. Roberts

Yes, I hope so. And if the folks in Norway are listening, that's their charge for this year.

Operator

[Operator Instructions] We have a follow-up in queue from Ed Westlake of Credit Suisse.

Edward Westlake - Crédit Suisse AG, Research Division

Last one, I promise. I mean, just some color on Integrated Gas and Oil Sands Mining in the quarter. Obviously they were a little bit weak.

David E. Roberts

Yes, Ed, it's -- you got in under the bell. So it's a good question for the last one. Pretty clearly, the fourth quarter was a disappointment in Oil Sands in terms of reliability of the mine, particularly coming off what was a very solid third quarter after the Expansion 1 was delivered. All the partners are working very closely together to see if we can focus on improving the reliability and getting our production rate up because that's critical for the cost and the profitability of what was a very large investment program. We've had some difficulties at the beginning of the year with some cold weather, but pretty clear that the operators are going to respond to the challenges in terms of making that the asset that we all think it can be. Integrated Gas, pretty clearly, as Howard said, there was some noise relative to smoothing out of the Alaska asset. But there is no doubt that we're challenged in the sub-$3 Henry Hub environment, since that's what we're paid on an LNG basis. I'd remind people that the strength of the earnings and cash flow position of that asset is contained in our E&P business on the liquids side. But pretty clearly, we're going to be challenged in the Henry Hub environment on the Integrated Gas side because even though I would argue it's the best LNG facility in the world, no one can do very well sub-$3 in terms of producing LNG in this environment. So it's something we're going to have to watch very carefully. And let me assure you, we're engaged with the appropriate parties and counterparties in terms of what some possible solutions might be to our difficulty.

Edward Westlake - Crédit Suisse AG, Research Division

And I look forward to some Eagle Ford updates through the year.

Operator

We have no further questions at this time. I will now turn the call over to Howard Thill for closing remarks.

Howard J. Thill

Thank you, Monica. We apologize for running out of time. We appreciate all the questions and interest in Marathon Oil Corporation. We look forward to visiting with you in the near future. Thank you, and have a great evening.

Operator

Thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect.

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!

Source: Marathon Oil Management Discusses Q4 2011 Results - Earnings Call Transcript
This Transcript
All Transcripts