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Executives

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

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

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

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

Analysts

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

Evan Calio - Morgan Stanley, Research Division

Paul Y. Cheng - Barclays Capital, Research Division

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

Mark Gilman - The Benchmark Company, LLC, Research Division

Blake Fernandez - Howard Weil Incorporated, Research Division

Edward Westlake - Crédit Suisse AG, Research Division

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

Paul Sankey - Deutsche Bank AG, Research Division

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

Faisel Khan - Citigroup Inc, Research Division

Marathon Oil (MRO) Q3 2011 Earnings Call November 1, 2011 2:00 PM ET

Howard J. Thill

I apologize for that confusion with the wonders of technology we were playing the second quarter. Apparently, they picked up the wrong quarter recording. So we'll do this the old-fashioned way live. And welcome to Marathon Oil Corporation Third Quarter 2011 Earnings Webcast and Conference Call. 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 Treasurer; and David Roberts, Executive Vice President and COO.

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

In accordance with Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995, Marathon Oil Corporation has included in its annual report on Form 10-K for the year ended December 31, 2010, 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 income from continuing operations for 2010 and the first 3 quarters of 2011 and preliminary balance sheet information.

On Slide 3, you'll see the third quarter 2011 adjusted net income from continuing operations of $421 million with a 39% increase -- decrease, excuse me, from the second quarter of 2011. This decrease was largely driven by a noncash charge of $227 million for foreign tax credit that we currently expect the company to be unable to utilized in the future periods. This noncash charge is largely driven by an outlook of higher than originally anticipated Brent pricing and a higher production outlook for Norway.

As indicated on Slide 4, excluding the higher effective tax rate for the quarter, segment income improved across all 3 segments compared to the second quarter results. In addition to the previously discussed increase in taxes related to foreign tax credits, a higher proportion of third quarter earnings came from the international operations, also contributing to an increase in taxes.

As shown on Slide 5, the E&P segment third quarter to second quarter price and volume variances essentially offset. Lower DD&A and exploration expenses were largely offset by an increase in other expenses. The other expense category was higher primarily because of higher field level controllable associated with the timing of international liftings. This leads almost the entire difference in the quarters related to previously discussed change in mix and noncash deferred taxes.

Slide 6 shows our historical E&P realizations and highlights $3.05 per BOE decrease in our average realization. This decrease was driven by a $5.69 per barrel decline in liquids realizations, while natural gas realizations were $0.40 per Mcf lower quarter-to-quarter. Our liquids realizations were in line with the average of a $12.80 decrease in WTI and a $4.02 decrease in Brent, largely because of our higher exposure to Brent. Our natural gas price realizations fell more than the move and the market indicators because we had a higher percentage of lower priced international gas and the lagging price impacts in Alaska.

Moving to Slide 7, E&P production volumes sold in the third quarter increased approximately 4% from the second quarter, while production available for sale increased 1%. Europe was overlifted by almost 1 million BOE in the quarter, while EG was underlifted by 330,000 BOE and Alaska added 100,000 BOE to gas storage. As of the end of the quarter, our cumulative international underlift position was approximately 950,000 barrels. This consists of underlifts in EG and Libya of 600,000 and 850,000 barrels, respectively, offset by cumulative overlift in Europe of 500,000 barrels. Domestically, we are 2.1 million BOE underlifted as a result of gas storage in Alaska.

Slide 8 shows the more than 8% growth in E&P production available for sale since the beginning of 2010, excluding Libya.

Slide 9 shows Marathon's E&P cost structure by category over the past 7 quarters. DD&A increased through the fourth quarter of 2010 but has started to decline in the past 2 quarters as a result of lower Gulf of Mexico volumes, while exploration expenses per BOE dropped again this quarter, primarily driven by lower dry well expense.

Turning to Slide 10. The third quarter E&P segment income decreased 48% primarily due to the previously discussed higher taxes. Lower per BOE realizations were partially offset by reduced expenses. Total E&P expenses per BOE were lower by $2.01.

Turning to Slide 11. The improvement in the Oil Sands Mining segment income, third quarter to second, was primarily a result of higher volumes from a full quarter with the expanded facility partially offset by lower price realizations.

And to finish out segment reporting, Slide 12 shows that the Integrated Gas segment income was $55 million compared to the $43 million recorded in the second quarter of 2011. This was primarily a result of the sale of our 30% interest in the Kenai, Alaska LNG facility and higher LNG and methanol sales volumes in EG.

Slide 13 provides an analysis of preliminary cash flows for the third quarter. Operating cash flow, before changes in our working capital, was approximately $1.3 billion, while working capital changes reduced cash by $262 million. We had capital expenditures of $735 million. Asset sales contributed $14 million. We paid dividends of $106 million, and we repurchased 12 million shares of common stock for $300 million. Our cash balance at the end of the third quarter stood at slightly over $4.6 billion.

Slide 14 goes to the 9-month preliminary cash flow analysis, but for the second time, I won't go through this line by line.

As shown on Slide 15, at the end of the third quarter of 2011, our cash adjusted debt-to-total capital ratio was 2%. But remember that we are today closing on the 141,000-acre Hilcorp deal and by the end of this year, including the Hilcorp deal, expect to close on the purchase of nearly 167,000 acres in the Eagle Ford, largely in the core, totaling approximately $4.5 billion. As a reminder, the net debt-to-capital ratio includes about $217 million of debt service by U.S. deal and almost all is contractually required to be removed from our balance sheet by the end of this year. We expect the overall corporate effective income tax rate from continuing operations to be between 55% and 62% from Q4 2011. The full year 2011 effective tax rate, including discontinued operations, is estimated to be between 50% and 56%. And both of these estimates exclude special items and the effect of foreign currency remeasurements of our tax balances.

Slide 16 is one we generally have in the appendix, but we want to highlight the production targets for the fourth quarter of this year and for 2012. Excluding any production from Libya, we expect our 2012 production to be approximately 5% higher than 2011.

This is even more evident as we turn to Slide 17, where you can see that our projected Lower 48 production, excluding the Gulf of Mexico, is estimated to grow from 75,000 boepd to between 120,000 and 130,000 boepd over the next 5 quarters, a 60% to 73% increase.

And on Slide 18, we have provided estimates, production and effective tax rates by country for 2012.

And with that, we will open up the call to questions. I would ask you to keep your questions to one and a follow-up or 2 separate questions. Thank you.

Question-and-Answer Session

Operator

[Operator Instructions] And we have a question from Arjun Murti from Goldman Sachs.

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

Two questions, hopefully both short. Bakken, it looks like you're making good progress. Can you talk about what you're seeing on the inflation front there on the well cost side?

David E. Roberts

Arjun, this is Dave. We're basically targeting now between $8 million and $8.5 million per well for our wells. I would say that we have fixed contracts for our drilling and the 10 fracs a month that we have contracted. And so we're not as exposed to further upward pressure on the inflation side. Most of what we've seen in terms of driving our costs up have been the fact that we're now putting 30-stage kit in the ground, and all of our wells next year will be 30-stage frac jobs.

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

And you used the word "fixed contract," Dave. Is there a component that moves with some sort of price index? Or is it truly kind of a fixed rate for some several year period?

David E. Roberts

Well, it's essentially -- I would call it fixed. The -- really, the only thing that's variable in most of these contracts is fuel.

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

Great. And then hopefully, a very quick follow-up. On the MPC call, they mentioned as a result of the tax-free spin, the inability to both issue and buy back stocks. The buyback piece I get, are you all, MRO, unable to issue stock if you wanted to as a result of the tax-free spin-off? And with the issued stock, I mean, it could be for an acquisition or whatever corporate use you might choose to issue stock for.

Janet F. Clark

Yes, I think, Arjun, that the tax-free spin requires that the shareholders who held the stock before the spin continue to hold over 50% of the stock afterwards for, call it, 2 years. And so we can issue stocks, but it would have to be less than 50% of our current shares outstanding.

Operator

Our next question comes from Ed Westlake from Credit Suisse.

Edward Westlake - Crédit Suisse AG, Research Division

Can you, Clarence, maybe talk a little bit, or Janet, about the rationale on the buybacks that you've started. Is this just share price driven on valuation of the stock? Or is this sort of a signal that you want to return excess cash to shareholders?

Clarence P. Cazalot

Well, Ed, this is Clarence. I think it's more a signal of that particular point in time as our share price had dropped to 25. We felt it was a prudent move to be in the market, repurchasing those shares. Certainly, we have said all along that share buybacks are certainly an element of our cash flow priorities. But as we've said, consistently, our #1 priority is reinvesting back in the business. And I think you've certainly seen that here in this quarter. You've seen it with our acquisitions in the Eagle Ford. But again, I think it demonstrates that, that is a vehicle with respect to the use of our cash that we're not hesitant to use.

Edward Westlake - Crédit Suisse AG, Research Division

And then switching to the acquisitions and investments. I'm just wanting to check I heard correctly. You said $4.5 billion of closing cost of the Hilcorp was $3.5 billion. And you've said that the acres goes from sort of net acres, 141,000 up to 167,000. It seems a sort of relatively high extra billion dollars for the extra acres. Maybe just clarify that for me. Maybe I got that wrong.

Clarence P. Cazalot

Yes. I think you have to go back and remember June 1, when we talked about the Hilcorp acquisition. We said 141,000 net acres for $3.5 billion. We also said -- excuse me, that the effective date of the transaction was May 1. And so certainly, any of the costs that were realized between the May 1 effective date and the November 1 closing date, those costs less whatever revenue would be reflected in the closing adjustment. So you recognize that the activity continued very strongly on that Hilcorp acreage. They actually exceeded the number of wells they had committed to both drill and complete. So pretty significant expenditure on the assets. It took the production, as you know, from 7,000 barrels of oil equivalent per day net as of June 1, to as we said almost 13,000 barrels a day net currently. So you certainly have the closing adjustments -- excuse me, as a portion of that -- excuse me. We also said at the time of the acquisition, there was roughly 14,000 net acres made up of those tag-along rights under the existing lease agreements, as well as follow-on acreage that we would attempt to secure. And so as compared to the 14,000, as you've seen now, we've actually acquired some 26,000 net acres and what I would say is that 26,000 acres is largely, as Howard said in his remarks, in the core part of the play. And importantly, it is associated with the Hilcorp acreage. And so back in June, we said our average working interest was 65%. Our average working interest now in the Hilcorp acreage will be 76.5%. The other component that's in that $4.5 billion that wasn't talked about back in June, it was the purchase of the gas gathering line that is really key to these assets. It's the main gas gathering line that runs through this acreage and allows us to tie in directly to Kinder Morgan and access their gas plant and the Southcross gas plants. So put all that together, additional acreage, closing adjustments and the gas gathering line, and that's how you get to the higher closing cost.

Edward Westlake - Crédit Suisse AG, Research Division

And would you be willing to give a price for just the sort of 12,000 non-tag-along right to increase in terms of dollar per acre, roughly, arranged?

Clarence P. Cazalot

Not at this point because there's still a pretty competitive market out there.

Operator

Our next question comes from Paul Sankey from Deutsche Bank.

Paul Sankey - Deutsche Bank AG, Research Division

Two questions. Firstly, just on the tax adjustment you did. I hate to be dull about this, but I think, Howard, you mentioned in your comments that it was owing to higher expected Norwegian production and the higher, it seemed, Brent price. Can you just clarify how that works? I need to -- out of interest, there's not -- they're not going the way I would have thought they would go if you were going to be reducing the anticipated tax benefit?

Janet F. Clark

Yes, Paul. What we basically did was took an allowance against our foreign tax credit. Because we are seeing now with the higher Brent price, we think that can last longer than we initially have at the beginning of the year. And in fact, production outlook has improved during the planned period. We will generate more income from Norway and more foreign tax credit from Norway in the future years than we will be able to utilize. So therefore, the foreign tax credits that we are generating this year, we have to put an allowance against. But I think the important thing is that on a go-forward basis, we will be able to continue to repatriate cash earnings from low tax jurisdictions without having to pay any incremental U.S. tax because of the foreign tax credit situation we're in.

Paul Sankey - Deutsche Bank AG, Research Division

Yes. Okay, that's helpful. And if I could a second one. The volume outlook, you've clearly stated, is 5% 2012 over 2011. I believe previously, you were using a range of 5% to 8%. I assume that it's still your aspiration that you get above 5% even towards 8%. Is there any reason why you dropped the 8% upper limit? Or are you just being conservative? Or can you just talk about the sensitivity related to production growth over the next year and any potential upside there is?

Clarence P. Cazalot

Yes, Paul. I think just to clarify, we have talked to a 5% to 7% compound average growth rate over the 2010 to 2016 time frame. So that remains unchanged. What we have said with respect to the 5% growth, that's 5% growth in 2012 over 2011 excluding Libya from both years. So as you're aware, we did have some Libya production in January and February of this year. If you take that out and assume no Libya contribution next year, we're saying we're up 5%. And then that's indeed we have a slide here in the presentation showing the Lower 48, excluding Gulf of Mexico with very substantial growth because clearly, it's the Eagle Ford and the Bakken and perhaps the Woodford that are the primary drivers of that growth year-on-year, '11 to '12.

Paul Sankey - Deutsche Bank AG, Research Division

Yes, I'm sorry. My mistake. So it was a 5% to 7% target and you've clarified the years there for me, Clarence.

Operator

Our next question is from Doug Leggate from Bank of America.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

I apologize, folks. I was a little late getting on the call. So if this has been asked, I apologize again. I got 2 quick ones. The first one is on the Eagle Ford. The 17 rigs, can you give any additional color as to how you're going to allocate those rigs because clearly, if you go back to your original presentation when you did the deal, you got substantially higher IPs in the core of the play versus in the other areas, I guess. So any clarity there? And what's assumed in your 5% growth will be helpful? My follow-up really, as you look across the 3 key plays, the Bakken, the Anadarko Woodford and the Eagle Ford, the economics in the Eagle Ford again are vastly superior, it seems, to the Woodford in particular. Why would you continue to allocate capital to the Kenai as opposed to ramping up even further than you're already doing in Eagle Ford now and I'll leave it as that.

Clarence P. Cazalot

Yes. It's a fair challenge, Doug, the second question in terms of -- because we get the same challenge here and we're certainly challenging our teams with that. I think at the end of the day, it's a question of efficiency in the number of workspaces that you can engage in some of these plays. And we're clearly going to take a look at that because it goes to the first question you asked. We're going to allocate our drilling rig resources as quickly as we can to the highest value part of this play, which is in the condensate window. So we obviously have some work to do in terms of making sure we maintain our lease position in those areas that we want to maintain our lease position in 2012. But whenever we have discretionary ability, we will devote the majority of the 17 rigs to the core of the Eagle Ford and to drilling gas condensate well. I would say though that is consistent to Woodford as well. All of the wells we have in the plan are going to be in the condensate window of the Woodford because clearly, that is the strongest portion of that play. We've got a lot of work to do there to understand it, but we are clearly devoting our capital resources to the highest value in each of the plays that we're pursuing.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

So, Dave, the higher IP rates in the Eagle Ford, is that what's assumed in your 5% growth target already? Or how would you -- what was embedded in your target for next year?

Clarence P. Cazalot

Well, I think we're pretty clear in our presentations on what we think this thing is going to do in terms of driving to 100,000 barrels a day. And that number feels in the Eagle Ford to be circa 30,000 barrels a day. So you can assume that the majority of that is going to come from the condensate window wells that we're drilling there.

Operator

Our next question comes from Evan Calio from Morgan Stanley.

Evan Calio - Morgan Stanley, Research Division

A couple of questions. One on Alvheim, I know you've bought a few more wells in the FPSO in conjunction with your allotment tax side. I mean, are we looking at a higher plateau production level there? And maybe you can talk me through that for the next few years, if you would.

David E. Roberts

I think what we said is we're currently running obviously 85,000 circa net to Marathon out there. We brought on some new wells this quarter. We're pretty clear that we're going to be able to maintain at or near this level through next year, and then we should see an additional chameleon [ph] well package come on the latter part of the year. And again, I think we've put lot of slides out that shows that we've been able to drive that plateau period out from what we previously thought was 2 years to before now. And we'll continue to look for opportunities to keep that FPSO full.

Clarence P. Cazalot

There's a slide, Evan, in our investor presentation that shows that where is your higher production, higher plateau versus what we thought back in 2008 when this asset was brought on stream. So really, through 2014, we maintain a very substantial level of production through these additional types as Dave referred to.

Evan Calio - Morgan Stanley, Research Division

Okay, good. I thought it was a little higher from what I remember from the Howard well package. Maybe I'll look at that again. My follow-up on the -- and it's a follow-up to the other question on the Eagle Ford. Could you specifically locate the 26,000 additional acres for us? I mean, you've been very specific in quantifying acreage in the condensate volatile black oil and the gas windows and specifically with the new well data. I mean, just any update where you're trending versus those type wells that you provided in conjunction with the acquisition package?

Clarence P. Cazalot

Yes. I'd say virtually all, maybe, other than about 2,000 acres is in the core in either the gas condensate or the volatile oil window. It's not -- certainly, none of it is in the dry gas and very little perhaps really outside the core and into the black oil. So the vast majority of it is in the core part of the trend. And as I indicated, because we're increasing our average working interest in the Hilcorp acreage specifically from 65% to 76.5%, you can see what we've in essence done as we bought out other working interest operators -- owners, I should say, in the Hilcorp operated acreage, again in the core. So the beauty of that is in essence, we're not having to drill more wells to get additional benefit both in terms of reserves and production and value. In essence, it's a higher interest in the activity we're already operating.

David E. Roberts

And Evan, and I think I would just add to that, the wells that we're seeing being brought online and that we anticipate bringing online the remainder of this year and the future bang on with what we thought they are going to do. And if anything, we're seeing improvements as we add some wrinkles to how the completions are being done with the different types of fluid packs. And we'll continue to look at that, but all indications are this is going to be as good or better than we had anticipated.

Evan Calio - Morgan Stanley, Research Division

That's good. Any asset sales in your guidance? I know you gave a range on that 15 to 3.

David E. Roberts

Nothing specific other than the range we've given. And obviously, we mentioned in here the Gulf of Mexico pipelines that the announcement was made on those. But again, it really doesn't make good sense in terms of creating leverage to talk about assets you're going to sell before you have a deal to sell them. So our preference would be to continue to refine our portfolio. We will execute on the range of dispositions we've indicated, but I don't want to be specific on assets.

Evan Calio - Morgan Stanley, Research Division

Okay. And I meant production guidance. That's all. If it was included in that, that's all.

Clarence P. Cazalot

No, it's -- there's no impact in our production guidance either for additional acquisitions or dispositions.

Operator

Our next question comes from Paul Cheng from Barclays Capital.

Paul Y. Cheng - Barclays Capital, Research Division

Two, hopefully quick ones. With your current status as a E&P company, what is the percent of the tax deductible for your intangible drilling cost? And do you have an estimate that -- how much is the cash benefit in 2012?

Janet F. Clark

Well, as you know, Paul, as an independent, we can deduct 100% of the intangible drilling cost in the year incurred. As part of what's integrated, that's only 70% with the balance spread over, I think, the additional 9 years. And what was the second part of the question?

Paul Y. Cheng - Barclays Capital, Research Division

Janet, do you have an estimate as how big is that cash benefit in 2012?

Janet F. Clark

I don't know that we've given that out yet in terms of what our cash taxes and that kind of breakdown.

Paul Y. Cheng - Barclays Capital, Research Division

Okay. Let me try a second question. In Bakken, Dave, you gave a 1-day IP for the 20 frac out. Do you have any of the wells that you have a 30-day IP you can share? And also, do have an estimate for the year out?

David E. Roberts

Yes, Paul. I think what we're seeing is that over 30 days, these things are coming back into the ranges that we previously had experienced. And so I'd say 600 to 800 barrels a day. And we believe with the move to 20-plus stages that our EURs on a per well basis are going from 350,000 to, let's just call it, an average of 500,000 barrels of oil.

Operator

And our next question comes from Blake Fernandez from Howard Weil.

Blake Fernandez - Howard Weil Incorporated, Research Division

A question for you in the divestiture targets. I wanted to confirm the $1.3 billion to $3 billion is kind of a clean slate beginning today. So I'm assuming the $205 million Gulf of Mexico pipeline assets kind of marks the beginning of that. And in conjunction with that, is there any designated use of the proceeds? In other words, would that be allocated toward buybacks or redeployed into other M&A?

Clarence P. Cazalot

Yes, I think -- let me just clarify that, that is clean slate, including the $205 million Gulf of Mexico pipelines. And on the cash uses, Janet?

Janet F. Clark

Blake, I think as we've always said, our highest priority is to reinvest in the business in value-accretive opportunities. I think as an E&P company, now that we've established pretty strong positions in at least the 3 resource plays through our 4 resource plays here in the U.S., what you'll see has continued to strengthen those positions. But as Clarence talked about earlier, to the extent we believe that we've got excess cash on hand, certainly, stock buybacks are a part of the way that we can provide value to our shareholders.

Blake Fernandez - Howard Weil Incorporated, Research Division

Okay, great. And then the second question was on the per unit cost. Howard had mentioned that we've kind of seen it rollover here and began to decline. I'm assuming Droshky was a large part of that. But is it fair to believe that cost on a per unit basis should continue to moving maybe toward where we were in, say, first quarter through third quarter of 2010?

Clarence P. Cazalot

I think that's true for the U.S. We should see. We think of normalizing our prices back to 2010 levels on an FLC basis. Internationally, we're seeing a little bit of upward pressure because some of the turnaround activity we have next year. But generally, it's on trend with 2010 as well.

Operator

Our next question comes from Faisel Khan from Citigroup.

Faisel Khan - Citigroup Inc, Research Division

On the Bakken, the well cost of $8 million to $8.5 million, is that still the same even under a 30-stage frac?

David E. Roberts

Yes, Faisel. That's our prospective cost.

Faisel Khan - Citigroup Inc, Research Division

Okay. So the cost aren't really moving up and you're still increasing the fracs and the EORs. Is that a fair assumption?

David E. Roberts

What we talked about is, we can deliver the rights, as we've said, for the $8.5 million. So I wouldn't expect them to exceed those kind of levels.

Faisel Khan - Citigroup Inc, Research Division

Okay. And you're still expecting 2 more rigs in the Bakken next year, going from 6 rigs to 8 rigs?

David E. Roberts

Well, we technically have 7 already. One of them is doing re-fracs for us, and so we will be moving from 7 to 8 in our current view.

Faisel Khan - Citigroup Inc, Research Division

Okay, I got you. And then one last question. On the Eagle Ford, the gas gathering and processing system that you guys bought, how big is that system?

Clarence P. Cazalot

It's about a 39-mile gathering system. It runs right through the heart of the acreage there. It varies from a 6- to 16-inch diameter pipe, capable of handling 150 million to 200 million a day with added compression.

Faisel Khan - Citigroup Inc, Research Division

Is that going to be able to handle kind of most of your kind of off-gas sort of production?

Clarence P. Cazalot

Yes. [indiscernible] but yes.

Operator

Your next question comes from Kate Minyard from JPMorgan.

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

I just wanted to ask quickly about Kurdistan. I know in your -- I guess one of your presentations earlier this fall, you've got appraisal drilling plan for 2012 on your 2 minority interest blocks and you've got planning early production system start-up in 2012 and -- for both of those blocks. And I was just curious as to the status of that, whether that's going to deliver any measurable level of volume into next year, and then also whether the progress on that is contingent on partner funding.

David E. Roberts

Yes, Kate. We're still on track for that. I think we're -- in terms of the EPS, we're basically in the design stage now. This is not high-tech stuff, so it shouldn't be that difficult to do. Our partners are actually pushing quite hard on this, but we're working closely together to make sure that we get that done. You will see some minimal production effects if we continue to move down this track next year. A lot of that, I would tell you, is contingent on surface issues there. I mean, the technical side of this is pretty straightforward. We're going to be watching very carefully the above-ground issues on a go-forward basis. And you're also correct that with similar contingencies, you'll see further exploration and appraisal drilling on the outside operated blocks. And Marathon is pointed towards actually drilling its own wells on our company-operated blocks in the country next year.

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

Great. Would that kind of be second half? Or should we kind of anticipate something in the first part of next year?

Clarence P. Cazalot

Our view right now is you should expect in the first half.

Operator

Your next question comes from Mark Gilman from Benchmark.

Mark Gilman - The Benchmark Company, LLC, Research Division

A couple of things. Janet, what if you could just talk about fourth quarter tax rate being above that in the third when one might expect the U.S. income to rebound a little bit?

Janet F. Clark

I don't think we talked about the fourth quarter being higher than the third.

Mark Gilman - The Benchmark Company, LLC, Research Division

Well, it looks like the clean tax rate for the third is about 52, whereas I think you're talking 55, 60 for the fourth. Do I have those numbers wrong?

Janet F. Clark

Well, I think that what you've got is in the third -- you have in the fourth quarter is we won't get the benefit of any of those foreign tax credits in the fourth quarter either.

Mark Gilman - The Benchmark Company, LLC, Research Division

Okay. We'll try it offline. I'm getting confused. Let me try another one. Dave, give me an update on Droshky. Is it still producing? When is the shutdown date? Anything that you can talk about in terms of that field.

David E. Roberts

Yes. Droshky is still producing 10,000 barrels a day net. So we're obviously very pleased. We're engaged in a lot of production optimization to make sure that we can keep it going. Obviously, we're dealing with some slugging issues, and we're still looking at that field falling below its productive limit sometime in the second quarter of next year.

Operator

Our next question comes from Pavel Molchanov from Raymond James.

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

I appreciate the fact that you're not ready to assume any Libyan volumes in your guidance. I'm curious what do you think needs to happen on the ground and with your partners for you to get more visibility on the pace of production and recovery.

David E. Roberts

Well, I think, Pavel, we need to get on the ground and see what it is that we're dealing with there. I know that right now, the country has restored about 0.5 million barrels a day. So that's slightly less than the third of the pre-conflict level. But as we've kind of pointed out, our production is largely driven by electric submersible pumps. Those are pieces of equipment that do well when they're left idle for the period of time that we've been away. And so we have to physically get out there and see what we have on the surface. We have to be able to return a lot of our employees to be able to actually physically do that work, and then we'll have to engage in some subsurface work to see exactly what it is we've got in terms of repair jobs so we can determine when the restoration is going to be. All of that is predicated on the front-end work, making sure that it's a secure place for our people to work and that the United States government is on site in terms of making sure that our re-entry is compliant with all their laws and regulations. So it's still some time away before, I think, you'll see us talk with any confidence about Libya.

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

Okay. And have you had discussions with the new authorities regarding your existing contract and your plans for the future?

Clarence P. Cazalot

Oh, yes. We've been in contact with the transnational administration and now the new administration in Libya for some time. They're very consistent in saying that their anxious for Marathon's return, as well as the other western companies. And there is no question that they're going to honor the contract that they had in place with us and the Libyan sovereign government.

Operator

Our next question comes from Ed Westlake from Credit Suisse.

Edward Westlake - Crédit Suisse AG, Research Division

Just firstly, on that tax mark off to 55% to 62% for 4Q and you mentioned the foreign tax credits, but I mean, is that something that will then fade into 2012? Can you sort of give us -- would you just use the numbers in the presentation? Or could you give us some guidance around 2012 tax, say, at the black commodity debt?

Janet F. Clark

Yes. I think you know that obviously, our tax rate is very dependent upon which jurisdiction in which we earn our income. But as we look at 2012, on a broad-brush basis, we would expect an effective tax rate for the year somewhere in the mid 50% range.

Edward Westlake - Crédit Suisse AG, Research Division

Okay, great. And then 2 operational questions. Downspacing in the Eagle Ford, you're doing a pilot there and when might we get a result? And then the Niobrara, I mean, you've got rigs now in-situ. So when do you think you can talk about the Niobrara drilling program?

Clarence P. Cazalot

Well, we actually have done our first frac on our first horizontal well in Niobrara and we have discussed that we've been flowing back. Well, the results have been very encouraging. We've seen 500 barrel a day oil rates. So our first foray into this, into the Niobrara -- it's very early but you always like it when you produce oil on one of these wells. We'll be frac-ing 2 more wells in November. And so certainly, by the end of the year, we'll have a much broader understanding of what's going on out there. But the big area, a lot of work to do before we get too overconfident, the Eagle Ford, we'll be doing multiple pilots both at looking at a simple 80-acre downspacing and then further downspacing to see exactly what's an optimum drainage pattern at various places in the field. That will happen in the first half of next year. And so as the next 2 quarters go along, we'll be able to give a lot more color in terms of what we think that we're ultimately going to be able to develop this field at, but it's clearly not 160.

Operator

Our next question is from Paul Cheng from Barclays Capital.

Paul Y. Cheng - Barclays Capital, Research Division

A quick follow-up. On Eagle Ford, Dave, did you guys originally was talking about the exit the year at 11 -- I think 11 rigs and will be adding about one rig a month. So we exit next year at 23 and not by based on what you see here that you're several rigs short. Is that a change in your drilling program?

David E. Roberts

No. I think what we said, Paul, is we'll certainly exit the year at 10. And in fact, we essentially have operational control of 10 rigs, right now, as of about noon today in various stages of Marathon control. And I think what we're looking to doing is adding a rig a month to get to a number of about 17. And we think that that's going to map. But right now, our view is that's an optimum way to pursue the play. We had previously talked about a number north of 20. We certainly have the capability to potentially do that on the acreage, but I think what we're going to do is get our feet on the ground. We can certainly deliver the numbers that we suggested over the next 5 years with that kind of rig complement. So I don't think it's changed. We've been pretty consistent on 17 at least for the last couple of months. And while you're on the phone, let me clarify 30-day IP in the Bakken and what we're currently seeing. 400 to 600 is better than 600 to 800.

Paul Y. Cheng - Barclays Capital, Research Division

400 to 600. And Dave, on the -- can you just remind me what is your current target for the Eagle Ford for next year? And also do you have an exit rate for 2012?

David E. Roberts

Well, I'll have to think about the exit rate for 2012, but you can pull it off the chart. We're looking at being able to average about 30,000 barrels a day next year there.

Operator

Our next question is from Faisel Khan from Citigroup.

Faisel Khan - Citigroup Inc, Research Division

Just a couple of follow-ups. In terms of getting the crude out of both the Eagle Ford and the Bakken, I mean, how are you guys thinking about the logistics of evacuating that crude to the higher-priced markets?

David E. Roberts

Well, in terms of the Eagle Ford, we're pretty comfortable -- I think we've been on the front end of this one in terms of saying that we recognize that this is 1 million barrel a day liquids basin. And we're very comfortable that many of the big shippers are coming in and offering. We think multiple options either taking the crude north ceiling and over to the ship channel. But more importantly, there's a lot of activity of driving towards the Corpus Christi Bay, which is going to put this on a water-based market, which we feel pretty good about. We have very good coverage for our volumes for the initial stages of the play, and we're currently engaged in looking at what our longer term optionality is going to be. So we feel very good about the exit capacity there. We've been a little bit concerned about some of the bottlenecking -- bottlenecks that have been developing in the Bakken, largely around road traffic in terms of the able to truck most of our crew at least to the transit point either through rail or piping. As you know, we had a pretty solid base arrangement with what we thought was going to be our top end volumes with some local refineries. And we've now -- are now in the process of making arrangements to get our oil on pipes and rail to get it out of there so we can continue to enjoy some of the benefit of higher netback there. So we're in good shape in both places. I would say we're a little bit behind the Bakken. We're well in front in the Eagle Ford.

Faisel Khan - Citigroup Inc, Research Division

Is it, David, fair to say in the Eagle Ford that we should have -- what kind of realization should we kind of expect next year? We're looking at these volumes, so it would something between WTI and LLS or more WTI linked.

David E. Roberts

Yes, you're going to see a blend, but basically, we'll do -- we will just throw something out, the current numbers, WTI plus 7. And so you're starting to see this stuff look more like LLS as it gets closer to water.

Clarence P. Cazalot

You got to remember there is 700,000 barrels a day of refining capacity between Valero Stream Rivers refinery and in Corpus, and this is a very attractive crude. So it is, as Dave said, attracting a nice premium to WTI to keep those barrels in the area. So it's always good to see pipelines and refineries competing for our crude.

Faisel Khan - Citigroup Inc, Research Division

Great. And one last question. The Key Largo prospect, is that here to secure a rig for that one also, including Innsbruck?

David E. Roberts

Yes, we're looking for rigs to drill both of those next year in 2012. And obviously, our preference would be that it will be the same rig and we'll drill it back to back.

Operator

[Operator Instructions] And we have a question from Mark Gilman from the Benchmark.

Mark Gilman - The Benchmark Company, LLC, Research Division

Hey, Dave, what's the Bakken contribution to the 130, 120, 130 exit rate for 2012?

David E. Roberts

It's going to be on the order of 20% plus or minus.

Mark Gilman - The Benchmark Company, LLC, Research Division

20% of what, I'm sorry?

David E. Roberts

20% of the 120.

Mark Gilman - The Benchmark Company, LLC, Research Division

Okay, so about 25%?

David E. Roberts

Your math is as good as mine, Mark.

Mark Gilman - The Benchmark Company, LLC, Research Division

Those Bakken wells that are referenced in the release, Dave, what counties are they located in?

David E. Roberts

I'll get back to you on that. We're mostly in Dunn County, but I'll make sure that we've got those correct counties to you.

Mark Gilman - The Benchmark Company, LLC, Research Division

Okay. Just one other real quick one. There's 2 South Texas dry holes referred to in the press release, can I assume that, that was legacy Eagle Ford acreage? Or is it somewhere else?

Clarence P. Cazalot

It was legacy Eagle Ford acreage. It has nothing to do with Hilcorp.

David E. Roberts

Most of our wells, Dunn, Mountrail and McLean County.

Operator

At this time, I show no questions.

Clarence P. Cazalot

Okay, we appreciate your attention and interest in Marathon Oil. I hope to speak to you all soon. Thank you. Have a great day.

Operator

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

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