馬拉松石油 (MRO) 2011 Q4 法說會逐字稿

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

In accordance with Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995, Marathon Oil Corporation has included in its annual report on Form 10K 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 continuing 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 non-cash 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 UK.

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 over lifted by 6,000 BOED and the fourth quarter under lifted by about 10,000 BOED. In the fourth quarter, Europe was under lifted by approximately 800,000 BOE while EG was over lifted by approximately 200,000 BOE. There were no liftings in Libya resulting in an under lift of about 350,000-barrels. We ended the year approximately 4 million BOE under lifted with 2.1 million BOE in Alaska gas storage and approximate cumulative under lift 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 down time and seasonality in the base business and declines in the Gulf of Mexico, where liability 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 BOED 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 the result of lower Henry Hub-based LNG sales prices and a gain on the sale of Kenai LNG facilities 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 serviced by US 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.

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 expiration 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 non-core 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.

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

(Operator Instructions)

Doug Leggate, Bank of America Merrill Lynch.

My first question is on the production guidance, and I don't know which one of you wants to take this. It looks to us that two things are going on here. First of all, Norway seems to be running an awful lot better than you had suggested at this time last year. If you listen to what Hess said on their call it was like Libya net to them is already doing 13,000 barrels a day, which would imply something like 26 net to you. Can you address those two things in terms of your production guidance?

We are 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 simple de-bottlenecking 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. We've continued 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 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 into next year as well. We do have a shut down coming in the summer time that will take the field down for a period of time, but other than that, it's a great new store 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. 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. A couple 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 ability to perform maintenance as was the norm before the difficulties of 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.

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 what looked like some outstanding downspacing results. Can you 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 any downspacing pilots and if so what the results were and I'll leave it there, thanks.

That's a great second question, A, B, and C, but we appreciate that because it will give us an opportunity to highlight some of the things we're working on. First of all, we are going to stick to a view that we'll have 18 by the middle of the year. 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 downspacing testing that we were looking at and that's still part of our plan for 2012.

The key 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. Importantly, we're moving down towards what we would call the condensate window in our acreage and we've got two wells drilling right there as we speak.

We spent most of our time to this point in the volatile window and results continue to be very encouraging. The geology is holding up. This will be a great asset for us and we're looking forward to the 200 wells that we're going to get drilled this year in terms of proving out the concept building rate and then also answering some of the questions about downspacing on a go-forward basis.

Arjun Murti, Goldman Sachs.

Just a question on some of the exploration areas. I think Exxon sounded a little less excited about Poland 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?

Poland, we 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 analysis there, they will be further slabbed and then moved to our labs in Houston. Then we'll be doing some integrated analysis against the logs.

At this point, what we've seen is consistent with what we expected. We'll basically do two more wells like this in terms of taking a full data evaluation suite. We still expect to get six to seven wells drilled this year. 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.

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

No. So we're going to do our science. We're going to do this right. We've done seismic -- let me back up. I'm not saying Exxon didn't do it right, but we have our own program here and we'll carry that out as far as it goes.

The Niobrara, we've got three wells down, fracked 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 two rigs through the remainder of the year. It's a big basin, as you know, and we're basically testing six or seven areas out there. Not discouraging, even though we do think that -- I'm glad that you classified the play as exploration because I think it's very frontierish compared to what we're doing elsewhere.

The Gulf of Mexico, we're participating in two wells right now. The Gunflint Appraisal, which one of our partners is drilling and the Kilchurn exploration well which Statoil is drilling and we're a participant in that. We're going to get back on Innsbruck in the 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.

Clarence, you've talked about selective acquisitions and 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?

I don't think, Arjun, it would be fair to say that one year's results particularly if it's two or three wells is going to sway us completely off the Gulf of Mexico. 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. 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.

Ed Westlake, Credit Suisse.

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

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 expect to see these 1,500 to 1,650 BOE per day IPs. In the volatile oils, you're going to see this 900 to 1,000; in the back hole you're going to see these numbers in the 400 range.

What we would say is as our program has developed and we have drilled wells primarily in the latter two areas, our results are very consistent with those numbers and we've got two 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 and 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.

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

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 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 vintage, but to give you an idea, we're seeing 4 million to 5 million cubic feet of gas, 90 barrels of condensate, and 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 than you'd like 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.

The Eagle Ford is a great basin. What are your thoughts in terms of increasing your footprint across the US?

Well, the Eagle Ford is the top basin we have in the world today. 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 would 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 to work as we can down there.

Paul Sankey, Deutsche Bank.

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

I'll start with the Bakken. It's obviously a very positive story in terms of leading last year at 24,000. We've 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 six rigs working, one that's doing recompletions and adding one more in the second quarter for a total of eight. We're basically going to retask the rig that's doing refracks into straight-up drilling, so we're very excited about being able to continue the momentum in that play.

I would highlight one thing is, we've obviously gone to all 30 states' fracks, our early results are very good, we're very encouraged about it. The only thing that may hold us back a little bit in the Bakken is a lot of our efforts going to be directed towards the Diomedes area which is basically on the fringes of the play. It's early days and 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.

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 use is 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. The fact that we took over a lot of wells that weren't set up for long term production, just didn't have any tubulars in them.

I want to be very clear here. Hill Corp did a great job with this asset base. They delivered us a top-class asset that is built for speed and we're going to do very well with it, but the heart of the matter is we have 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 in 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.

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

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

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

No, I think we're thinking in terms of both, and we continue 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 of the Bakken and other areas.

And we stand by our earlier guidance of $1.5 billion to $3 billion of dispositions over the next two to three years. But that's going to be driven by what we see as the opportunities to divest at the right price and reinvest at good prices and good economics as well. I wouldn't say that either is preferred at this point. It's a balance of how we go about high grading our portfolio.

Evan Calio, Morgan Stanley.

The Marathon family has sure kept us busy the last 12 months with restructurings. A lot of major questions had been covered, but maybe a couple follow-ups, one on Paul's question. On Eagle Ford pricing, you put it in reference to TI, but has the pricing structure shifted to an LLS pricing dynamic, like LLS under six versus a TI correlation for you?

And then also, thanks for a lot of the comments on the Eagle Ford. Any comments on shortages you see in frac crew proppants or any other challenges that you're looking at managing here in your activity ramp?

We saw that, because 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 as somewhere in between the two, but ultimately, I think you're right.

You're going to see this as an LLS marker because 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. I think it's six of one and half dozen of the other.

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 a 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 improve our efficiency and make us more money. 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.

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

I think we're still on the view that you're going to see a Q2 start and 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. I would expect some incremental ramp up from the middle of this year into that right into the Q1 of next year.

Paul Cheng, Barclays Capital.

Janet, on the deferred tax item in your cash flow, we understand for the total Corporation you probably get the cash flow benefit on that item in the US due to the IDC deduction and then you're probably spending some money or that you're paying some additional tax, the book tax and the overseas, that's why for the first nine months of the year, 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 benefit showing up in the consolidate or is it going to get overwhelmed by the international?

My guess is, of course it depends upon the production mix as well as pricing, is that because the UK, Brae, in particular Norway, are in a position where actually our current taxes, our cash taxes are higher than book as the DD&A reversed. That will probably continue to outweigh or at least balance the deferred tax benefit that we get in the US.

Starting January 1, 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, just the timing difference, but it would get amortized -- the balance, 30% -- would get amortized over the remaining nine years. So yes, we do get the IDC benefit in the year incurred in the US, but it does largely get offset if not completely offset by the international tax payments.

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 launch and it will be longer?

I don't like to predict anything, and certainly going out three years on deferred versus current taxes in foreign jurisdictions is just way too many variables. Way too many variables I'm afraid. But our mix of production over time should be shifting to more US, and you'd see UK, Norway be a smaller percentage of production so it could certainly happen.

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

The well costs that we're seeing in the Eagle Ford, the 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. We have added seven 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 three of them and volatile oil rates for four of them.

We expect the volatile oil wells to be in the thousand barrel a day equivalent IP when we get to those dates and the black oil ones to be somewhat less than that. 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.

Ozona 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 4000 barrels a day and 7 million cubic feet.

We're going to continue to monitor it and see what it does but importantly what I would say is Ozona marks the end of a 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.

Is Droshky producing right now?

Yes, Droshky is running about 7500 barrels a day, net.

Blake Fernandez, Howard Weil.

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

I think the issue relative to the first quarter is worth noting, and I think we have before. We've got a 30-day shut down of EG coming that will begin the middle of March and then run to the middle of April, so 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 our gas plant facility over there. That's the 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 balance opportunity, we're clearly going to have issues across those quarters but we expect on the basis of resource plays to continue to grow rates both in the Bakken and the Eagle Ford throughout the year. We should show inclining rates throughout the year.

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

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

Blake, 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 -- again we get asked the question all the time what is the priority use for our cash. Very clearly the number one priority as we go forward is reinvesting in the business and value-accretive projects. You will have noted 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.

Faisal Khan, Citigroup.

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

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.

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

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

Yes, Faisel, we put out -- 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 so it was early December, I want to say December 2 or 3, we put out a full press release outlining our 2012 budget that will give you all those details.

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

Yes, I think we would have said $21, but that general range is probably a good way to look at the business. 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 I would support that as a number.

John Malone, Global Hunter Securities.

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

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 would 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. One of the reasons we're doing this because it is 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.

One on international, Equatorial Guinea, you hear the government talking periodically about expansion on Bioko Island of the LNG facility and proven up gas and neighboring countries. You have been pretty quiet on that. Any comment on the government's plans or what they want to do?

We're participants in those discussions and we have done very well with our LNG franchise in Equatorial Guinea. Clearly, we think that there needs to be more work to develop gas sources in the country to support a future train. Our first priority has always been making sure that we keep train one 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 opportunities to create value in Equatorial Guinea, but as we said in our response, there's a lot of work to be done in terms of making sure that there's sufficient gas resources and the commercial arrangements are in place to make sure it's a fair return for the risk we would take in that venture.

Mark Gilman, The Benchmark Company.

Janet, is there a potential tax on the buyback that MPC 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?

This was contemplated in the tax [sharing] agreement that MPC obtained an unqualified tax opinion, that the stock repurchase program and the MLT perspectively would not disqualify in any way the tax-free status of the spinoff.

Dave, let me go back to this stricter choke management issue. I guess I'm a little bit confused. You cut some of the initial 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 activity level or indicated spend, can you help me reconcile those?

I don't think that they are not reconcilable at all. 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, which is what we would say in addition to some of our lease hold activities.

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 rate that 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 we had on some of the more highly perspective areas. I think we're in pretty good shape.

Basically what we would say is, to go back and talk about flow management or choke management, a lot of the stuff was done at a very rapid pace because Hill Corp wanted to deliver us an asset that we could pick up and run with. We had to go back and do a lot of stuff that we would call normal production engineering, making sure that the wells flow longer before you could get artificial lifts installed. This is nothing out of the ordinary and I'd consider it a minor bump in the road.

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

Earlier in '11, you indicated 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?

No, we certainly looked at opportunities to bring in a partner in our Gulf of Mexico portfolio in large part not to share the risk on certain prospects but 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 so we have no intention of pursuing that anymore.

Pavel Molchanov, Raymond James.

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

Pavel, that well would be about $12 million.

$12 million. And then a little more broadly, are you seeing any budding opposition in Poland to fracking or shale drilling in general as one of your peers recently experienced in Bulgaria?

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 perspective. They're very interested making sure that we do enough work together with them to make sure that popular opinion stays on side of energy security versus making a choice, which we don't think is a correct choice of, against the environment. Consistently we've said to them as we operate we could 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.

Katherine Minyard, JP Morgan Chase.

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

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 Mermadon 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, so we have to go out there and do some lease drilling out there.

It's early days, and if you followed us, you know we're always pretty conservative in the Bakken, so we're not over-hyping that particular area. Obviously we hope it's as prospective as what we've seen in Dunn County, but we'll get drilling results and see.

Can you talk about 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 $2.7 billion that you have in your four 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?

We don't do a whole lot of that anymore. We really try to focus our efforts in. So basically what I would tell you is the $1.4 billion we have directed to Eagle Ford is all on stuff that we consider prospective and economic. Obviously there's a variability in the play but it's all driven towards adding substantial value.

The Bakken, when we talk about that area, you probably are only talking about one rig year. So essentially one-eighth of the overall $700 million program, and then I would argue that the two-rig program in the Niobrara would certainly fall into that type of an area.

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 might not charm you by the end of the year.

Can I just quickly clarify, on the 30-day turnaround or the shut down at EG, can I just confirm that that's all your volumes in EG, not just the gas volumes?

That's everything.

Ed Westlake, Credit Suisse.

On the depreciation, particularly in the US, obviously Droshky made that a little bit, some more volatile in 2011 but $25 to $27.50. Is there any residual Droshky impact in that, and when do you think that would start dropping as you'll get your production up on stream?

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

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

Yes.

And it's $25 to $27.

That seemed a little high, I guess. I know you're spending on shale and there's always up-front costs, so I was just wondering if there was any Droshky in there or is that a clean number we should use as a base?

I think our expectation is, and we pretty much said this, is that Droshky will likely decline out of the portfolio in the first half, 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 unconventional.

Doug Leggate, Merrill Lynch.

Just a couple of clarification points on the Eagle Ford. Dave, I understand the exit rate was down 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 whether or not you've got the infrastructure in place to accommodate comfortably your planned ramp up this year?

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. 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 the liquids are in place, 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 five years.

Dave, you also made some comments about gas in your earlier remarks in response to one question. Are you drilling any dry gas wells right now and maybe you could help us with rig allocation across your plays?

First of all, my drilling people are clamoring after me to make sure that the total well cost 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, dry gas well I get in trouble and so we're trying not to do that, but the closest thing we have is in the Woodford and we're still seeing a lot of liquids plays. We are 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. In terms of our rig deck right now we've got 14 in the Eagle Ford and that number is obviously going to go to 18. We're running six in the Woodford and monitoring that very closely. We've got two in the Niobrara, one or two more up in Wyoming doing some work for us up there and seven in the Bakken right now and that will be going to eight. As we see it, we've got 35 or 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.

Paul Cheng, Barclays Capital.

In Angola, I think at one point you have been marketing your remaining interest as part of the asset sales program. Wondering if that is still being actively pursued or that you have not seen satisfaction so that's similar to the other area that you are not marketing on that one. And also, can you tell us when the next project is going to [scension] 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 Hill Corp asset. When will you start testing the area outside the Hill Corp asset?

I think what we've said is we think Hill Corp can deliver the rate we've talked about, and we're going to continue to look at areas outside of the core. It's important for people that follow us and our investors to understand we think the heart of this play, which is what we bought with Hill Corp, is where we should focus our activities and that's where we're going to drive the rate from. 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 Hill Corp acreage and to deliver the numbers we've talked about from that --.

Can I just want to make sure or clarify, in your presentation, 2016 you're looking for over 100,000 barrel per day, for Eagle Ford. Is that 100% coming from Hill Corp or is only 80,000 coming from Hill Corp? It seems like there's two different numbers that I recall.

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 what we would call the broader Hill Corp footprint.

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 so I wouldn't comment on anything that might have appeared in the press relative to our intentions to the contrary. The other thing I would say is that I'm also not going to speculate on what the next opportunity for development would be. That's a better question to ask our partners Totale in Block 32 and BP in Block 31.

Can you give us a timeline of when you expect to have something announce?

No.

Mark Gilman, The Benchmark Company.

As you tie in some of these 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 your working interest in the volumes coming off that platform?

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

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

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

(Operator Instructions)

Ed Westlake, Credit Suisse.

Just some color on integrated gas and oil sands mining in the quarter, obviously they were a little bit weak.

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 was delivered. All the partners are working very closely together to see if we can focus on improving the reliability in 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 in the beginning of the year with some cold weather but pretty clear that the operator is 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 us moving 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 our 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 a liquids side but pretty clearly, we're going to be challenged in the Henry Hub environment on the integrated gas side.

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 difficulties.

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

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

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