馬拉松石油 (MRO) 2011 Q3 法說會逐字稿

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 Dave 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 it's 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 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 will see that our third quarter 2011 adjusted net income from continuing operations of $421 million was a 39% increase -- decrease, excuse me, from the second quarter of 2011. This decrease was largely driven by a non-cash charge of $227 million for foreign tax credits that we currently expect the Company to be unable to utilize in the future periods. This non-cash 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 costs associated with the timing of international liftings. This leaves almost the entire difference in the quarters, related to previously discussed change in mix and non-cash deferred taxes.

Slide 6 shows our historical E&P realizations and highlights the [3.05] per BOE decrease in our average realizations. 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 realization fell more than the move and the market indicators, because we had a higher percentage of lower priced international gas, and the lagging price impact 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 1million 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 in Libya of 600,000 and 850,000 barrels respectively, offset by a 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 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 quarter, 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 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 through 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 total capital ratio includes about $217 million of debt serviced by US Steel, 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% for 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 BOE PD to between 120,000 and 130,000 BOE PD over the next 5 quarters, a 60% to 73% increase. And on slide 18, we have provided estimates of production, and effective tax rates by country for 2012. And with that, we will open the call to questions. I would ask you to keep your questions to 1 and a follow-up or 2 separate questions. Thank you.

Thank you.

(Operator Instructions).

And we have a question from Arjun Murti from Goldman Sachs. Please go ahead.

Howard, all these years, I didn't know we were listening to a recording of your voice. (Laughter).

Well, that's good, Arjun.

Having a little Milli Vanilli or Ashlee Simpson moment I think, but --

Absolutely.

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?

Yes, Arjun, this is Dave. We're basically targeting now between $8 million and $8.5 million per our wells. I would say that we have fixed contracts for our drilling, and the 10 fracs a month that we have contracted, so we are not 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 are now putting 30 stage kit in the ground, and all of our next year will be 30 stage frac jobs.

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

It is -- I would call it fixed. Really, the only thing that is variable in most of these contracts is fuel.

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

Yes, I think, Arjun, that the tax free spend 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 stock, but it would have to be less than 50% of our current shares outstanding.

Got it. Thank you very much.

Our next question comes from Ed Westlake from Credit Suisse. Please go ahead.

Good afternoon. And congrats on the results of adding tax back. 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 it sort of a signal that you want to return excess cash to shareholders?

Well, Ed, this is Clarence. I think it is more a signal, of at that particular point in time, as our share price to drop to $25.00, we felt that 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 number one 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.

And then, switching to the acquisitions, and investments. I'm just wanting to check, I heard correctly, you said $4.5 billion of closing costs, of the Hilcorp, was $3.5 billion. And you said that the acres goes from sort of net acres 141 up to 167. It seems a sort of relatively high extra $1 billion dollars for the extra acres. Maybe just clarify that for me. Maybe I got it wrong.

I think Ed, you have to go back, and remember June 1 when we talk 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 a 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, took the production as you know, from 7,000 barrels of oil equivalent per day net as of June 1, to as we've said, almost 13,000 barrels a day net, currently. So you certainly have the closing, excuse me, adjustments as a portion of that, excuse me. We also said at the time of the acquisition, that it was roughly 14,000 net acres made up of both 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.

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 is 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 is the main gas gathering line that runs through this acreage, and allows us to tie in directly to Kendall Morgan and access their gas plant, and the Southcross gas plant. So you put all that together, and additional acreage and the closing adjustments, and the gas gathering line, and that's how you get to the higher closing costs.

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

Not at this point, because it is still a pretty competitive market out there.

Okay. Thanks very much.

Our next question comes from Paul Sankey from Deutsche Bank. Please go ahead.

Thank you. Good afternoon, all. Two questions. Firstly, just on the tax adjustment you did. I actually thought about this, but I think Howard you mentioned in your comments that it was owing to higher production Norwegian production, and the higher assumed Brent price. Can you just clarify how that works for me, out of interest? It's not -- they're not going the way, I would of thought they would go, if you were going to be reducing the anticipated tax benefit. Thanks.

Yes, what we basically did, was take an allowance against our foreign tax credits. Because we are seeing now, with the higher Brent price, we think that is going to last longer than we initially had 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 credits 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.

Okay. That explains it. Thank you.

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 US tax, because of the foreign tax credit situation we're in.

Yes, okay. That is helpful. Thank you. 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 is 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? Thanks.

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 why indeed, we have the slide here in the presentation showing the Lower 48, excluding Gulf of Mexico, with very substantial growth. Because clearly, it is the Eagle Ford and the Bakken, and perhaps the Woodford that are the primary drivers of that growth year-on-year, 2011 to 2012.

Yes, it was my mistake. It was 5% to 7% target, and you've clarified the years for me there, Clarence. Okay. Thanks very much.

Thanks.

Our next question comes from Doug Leggate from Banc of America. Please go ahead.

Thank you. I apologize folks, I was a little late getting on the call, so if this has been asked, I apologize again. I've got two 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 had substantially higher IPs in the core of the play, versus in the other areas, I guess. So any clarity there, and what is assumed in your 5% growth would be helpful? And my follow-up is really as you look across the 3 key play, 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 Cana, as opposed to [bumping] it up even further than you're already doing in the Eagle Ford? I will leave it at that. Thanks.

Yes, it is a fair challenge, Doug, the second question, in terms of, as we get the same challenge here, and we're certainly challenging our teams with that. I think at the end of the day, it is a question of efficiency in the number of work faces that you can engage in, 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, for the majority of the 17 rigs, to the core of the Eagle Ford, and to drilling gas condensate wells. I would say though, that is consistent with the Woodford as well. All of the wells that 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 pursuing.

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

Well, I think we are pretty clear, in our presentations 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. And so you can assume that the majority of that is going to come from the condensate window wells that we're drilling there.

All right. That's very clear. Thanks a lot.

Our next question comes from Evan Calio from Morgan Stanley. Please go ahead.

Good afternoon, guys. I like the retro -- the start there. I thought I would get to ask about the downstream separation again. (Laughter).

Thanks, Evan.

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

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 (inaudible) million well packets come on, the latter part of the year. And again, I think we've put a 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 be 4 now. And we will continue to look for opportunities to keep that FPS hopeful.

Good.

And there is a slide, Evan, in our investor presentation that shows that wedge of higher production, higher plateau, versus what we thought back in 2008, when this asset was brought onstream. So really through 2014, we maintain a very substantial level of production through these additional tie-backs, Dave referred to.

Okay. Good. Now I thought it was a little higher, from what I remember from the Howard Weil package. Maybe I will look at that again. My follow-up on the -- and it is a follow-up to another 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 acres in the condensate, volatile black oil, and the gas windows, and then, 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?

I would 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 is 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, it is in -- 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, is 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 in value. In essence, it is a higher interest in the activity, we're already operating.

And Kevin, I think I would just add to that, the wells that we're seeing being brought online, and then that we anticipate bringing online, the remainder of this year, and in the future are bang on, with what we thought they were going to do.

Okay.

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 will continue to look at that, but all indications are this is going to be as good or better than we had anticipated.

That's good. Any asset sales in your guidance? I know you gave a range on that, 1.5 to 3.

Nothing specific. Other than the range we had 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.

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

No, there is no impact in our production guidance, either for additional acquisitions, or dispositions.

Perfect. I will leave it there. Thank you.

Our next question comes from Paul Cheng from Barclay's capital. Please go ahead.

Hi, guys. Two, hopefully quick ones. With your current status as an E&P Company, what is the percent of the tax deductible for your intangible [June end] costs, and do you have an estimate that how much is the cash benefit in 2012?

Well, as you know, Paul, as an independent, we can deduct 100% of the intangible drilling costs in the year incurred. And (inaudible) integrated, it is only 70% with the balance spread, I think over the additional nine years. And what was the second part of the question?

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

I don't know that we have given that out yet in, terms of what our cash ex is and that kind of breakdown.

Okay. Let me try a second question. In Bakken, Dave, you gave a 1 day IP for the 20 frac. Now, do you have any other well that you have a 30 day IP you can share? And also your estimate for the year out?

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 would 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 a well.

Okay. Thank you.

Our next question comes from Blake Fernandez from Howard Weil. Please go ahead.

Guys, good afternoon. A question for you in the divestiture targets. I wanted to confirm that $1.3 to $3 billion, is kind of a clean slate beginning today, so I'm assuming the $205 million Gulf of Mexico pipeline asset 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?

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?

Blake, I think as we've always said, our highest priority is reinvest in the business and value accretive opportunities. I think as a E&P company, now that we've established pretty strong positions in at 3 resource plays, throughout 4 resource plays here in the US, what you will see is us, is continuing 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.

Okay. Great. And then the second question was on the per unit costs. Howard had mentioned that the -- we've kind of seen it roll over here, begin to decline. I'm assuming Droshky was a large part of that. But is it fair to believe that costs on a per unit business should be moving continuing maybe toward where we were in the first quarter toward the third quarter of 2010?

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

Okay. Thank you very much.

Our next question comes from Faisel Khan from Citigroup. Please go ahead.

Thanks. Good afternoon.

Hi, Faisel.

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

Yes, Faisel. That's our prospective costs.

Okay. So the costs are not really moving up and you are still increasing the fracs and the EURs. Is that a fair assumption?

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

And still expecting 2 more rigs in the Bakken next year, going from 6 rigs to 8 rigs?

Well, we technically have 7 already. One of them is doing refracs for us, and so we will be moving from7 to 8 in our current view.

Okay. Got you. And one last question, on the -- in the Eagle Ford, the gas gathering and processing system that you guys bought, how big is that system?

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

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

Yes.

Okay.

For the area that it traverses, yes.

Okay. Great. Thanks, guys.

Thanks, Faisel.

Our next question comes from Kate Minyard from JPMorgan. Please go ahead.

Hi, good afternoon. Thanks for taking my question. I just wanted to ask quickly about Kurdistan. I know in you -- I guess in one of your presentations earlier this fall, you've got appraisal drilling planned for 2012 on your 2 minority interest blocks. And you've got planning early production system startup in 2012 for both of those blocks. And I was just curious as to the status of that, whether that is going to deliver any measurable level of volumes into next year? And then also, whether the progress on that is contingent on partner funding?

Okay, we're still on track for that. I think we're -- in terms of the EPS, we're basically in the design stage now, and 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 the surface issues there. On 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 will see further exploration and appraisal drilling on the outside operated blocks. And Marathon is pointed towards actually drilling it's own wells on our Company-operated blocks in the country next year.

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

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

Great. All right. Thanks very much.

Thanks, Kate.

Our next question comes from Mark Gilman from Benchmark. Please go ahead.

Folks, good afternoon. A couple of things. Janet, I wonder if you could just talk about fourth quarter tax rate being above that in the third, when one might expect the US income to rebound a little bit?

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

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

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

Okay. Well, we will 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?

Droshky is still producing 10,000 barrels a day net to us, so obviously we're very pleased. So 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 issue, and we're still looking at that field falling below its productive limit, sometime in the second quarter of next year.

Okay, folks. Thanks.

Thanks, Mark.

Our next question comes from Pavel Molochanov from Raymond James. Please go ahead.

Thanks for taking my question. 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 with your partners, for you to get more visibility on the pace of production and recovery?

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 is restored, about 0.5 million barrels a day. So that is slightly less than a third of the pre-conflict level. But as we kind of pointed out, our production is largely driven by electric submersible pumps. So those are not 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 will have to engage in some subsurface work to see exactly what it is we've got, in terms of a repair job, so we can determine when a restoration is going to be. All of that is predicated on the front end work, making sure that it is a secure place for our people to work. And that the United States government is onside, in terms of making sure our re-entry is compliant with all of their laws and regulations. So still sometime away, before I think you will see us talk with any confidence about Libya.

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

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 saying, that they are anxious for Marathon's return, as well as the other western companies. And there is no question, that they're going to honor the contracts that they had in place with us, and -- as a sovereign government.

Appreciate the color on that. Thanks.

Our next question comes from Ed Westlake from Credit Suisse. Please go ahead.

Thanks. Thanks for a follow-on. Just firstly, on that tax mark-off, the 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 a -- or should we just use the numbers in the presentation, or could you give us some guidance about 2012 tax? Say, at a flat commodity tax?

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.

Okay. Great. And then two operational questions. Down spacing in the Eagle Ford, you are doing a pilot there, and when might we get our results? And then the Niobrara, I mean, I think you got a rigs now in situ, so when do you think you can talk about the Niobrara drilling program?

Well, we actually have done our first frac on our first horizontal well in the Niobrara, and we have discussed it. We have been flowing back the well. Results have been very encouraging. We've seen 500 barrel a day oil rates. So our first foray into this, into the Niobrara, it is very early, but you always like it when you produce oil out of one of these wells. We will be fracing two more wells in November. And so certainly by the end of the year, we will have a much broader understanding of what is going on out there. But it is a big area, a lot of work to do before we get too overconfident.

The Eagle Ford, we will be doing multiple pilots. Both at looking at a simple 80 acre down spacing, and then further down spacing to see exactly what is an optimum drainage pattern at various places in the field. That will all happen in the first half of next year. And so as the next 2 quarters go along, we will be able to give a lot more quarter -- color in terms of what we think that we're ultimately going to be able to develop this field at, but it is clearly not 160.

Very clear. Thanks very much.

Our next question is from Paul Cheng from Barclay's Capital. Please go ahead.

Hi, a quick follow up. On Eagle Ford, Dave, do you guys, (inaudible) talking about exit the year at 11, I think 11 rig, and will be adding about 1 rig a month. So we exit next year at 23. And looked like based on what you say here, that you're several rigs short. Is there a change in your drilling program?

No, I think what we said, Paul, is we will 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 at doing, is adding a rig a month to get to a number of about 17. And we think that is a -- but right now, our view, there is 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 compliment. So I don't think it is a change. 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, a30 day IP in the Bakken, we're currently seeing 400 to 600, is better than 600 to 800.

400 to 600. And Dave, on the -- you can 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?

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

Okay. All right. Thank you.

Thanks, Paul.

Our next question is from Faisel Khan from Citigroup. Please go ahead.

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

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 this as a 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 to Sealy, and over to the ship channels. But more importantly, there is a lot of activity driving toward 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 feel very good about the exit capacity there.

We have 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 being able to truck most of our crude at least to the transit points, either through rail or piping. As you know, we have a pretty solid based 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 and pipes and rails, to get it out of there. So we can continue to enjoy some of the benefits of the higher net back there. So we're in good shape in both places. I would say, we're a little bit behind in the Bakken. We're well in front in the Eagle Ford.

Is it fair to say in the Eagle Ford that we should have -- what kind of realizations should we kind of expect next year, when we're looking at these volumes? Will it be something between WTI and [NLS], or more WTI linked?

Yes, you're going to see a blend. But basically, we will just throw something out. The current numbers, WTI plus 7. And so you're starting to see the stuff look more like LOF, as it gets close to the water.

You got to remember there are 700,000-barrels a day of refining capacity between Valero Three Rivers refinery and 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 is always good to see pipelines and refiners competing for our crude.

Okay. Great. And one last question on the Key Largo prospect, is that -- you have to secure a rig for that one also, including Innsbrook?

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

Okay. Great. Thanks. I appreciate it.

(Operator Instructions).

And we have a question from Mark Gilman from Benchmark. Please go ahead.

Thanks. Dave, what is the Bakken contribution to the 130 -- 120, 130 exit rate for 2012?

It is going to be on the order of 20%, plus or minus.

20% of what, I'm sorry?

20% of the 120.

Oh, okay. So about 25?

Your math is good as mine.

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

I will get back to you on that. We're mostly in Dunn county, but I will make sure that we have the correct counties, Steve.

One other real quick one. There are two 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?

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

Okay, thanks, Clarence.

And we -- those -- most of our wells, Dunn, Montrail, and McLean county.

At this time, I show no questions.

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

Thank you. Ladies and gentlemen, this includes today's conference. Thank you for participating. You may now disconnect.