馬拉松石油 (MRO) 2011 Q2 法說會逐字稿

Welcome to Marathon Oil Corporation's second 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 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 on 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 is a reconciliation of quarterly net income to adjusted income from continued operations for 2010, and the first two quarters of 2011, preliminary balance sheet information, third quarter and full year 2011 and 2012 operating estimates, and other data that you may find useful.

Slide 3 provides net income and adjusted income from continued operations on an absolute and per share basis. Our second quarter 2011 adjusted income from continued operations of $0.96 per share reflects a 9% increase from the first quarter and a 55% increase from the second quarter.

The waterfall chart on slide 4 shows the first to second quarter change in pre-tax adjusted income from continuing operations by segment and the change in income taxes. The increase in income was driven by improved results in Oil Sands Mining and lower income taxes reflecting no production from our Libya operations in the quarter. These were partially offset by a decrease in E&P pre-tax earnings. The effective income tax rate for the second quarter, including special items and the effect of foreign currency re-measurement of our deferred tax balances, was 67%.

Excluding special items and the effect of foreign currency re-measurement of our deferred tax balance, the rate was 54%. We expect the effective tax rate for the full year 2011, excluding special items and the effect of foreign currency re-measurement of our deferred tax balances to be between 50% and 55%.

As shown on slide 5, E&P segment income compared to the first quarter was down about 10%, largely due to lower sales volumes, partially offset by higher realizations and lower costs. The lower sales volumes were a result of the Libyan conflict and downtime in Norway and Equatorial Guinea.

Our historical realizations are shown on slide 6. Our liquid hydrocarbon average realization increased $9.14 per barrel compared to the first quarter, which is largely in line with the $7.74 per barrel increase in WTI, and the $11.61 per barrel increase in Dated Brent.

Moving to slide 7, as a result of lower international liftings, our second quarter sales volumes decreased 15%, while production available for sale decreased 13%, both primarily a result of the previously discussed downtime in conflict in Libya. The difference in sales volumes and production available for sale was the result of an underlift for the quarter of approximately 674,000 BOE in the UK and Alaska, offset by an overlift of 341,000 BOE in EG in Norway.

At the end of the second quarter, our cumulative international operations were underlifted by approximately 1.6 million barrels. Domestically, we remained 2 million BOE, cumulatively underlifted due to gas storage in Alaska. Slide 8 shows the 7.5% growth in E&P production available for sale since the beginning of 2010, excluding Libya by quarter.

Turning to slide 9, Exploration expense fell in the second quarter with lower dry well expense while field level controllable costs per BOE increased as a result of additional domestic work over expense, the lack of lower cost Libyan production and turnaround costs at Brae. Also influencing per barrel costs were lower volumes in the second quarter.

Turning to slide 10, the second quarter E&P segment income increased 6% primarily due to higher per BOE realizations partially offset by lower sales volumes. Total E&P expenses per BOE were relatively unchanged.

Turning to slide 11, the Oil Sands Mining segment's improved results were largely driven by higher prices and increased volumes partially offset by higher operating and blend stock cost. DD&A and foreign income taxes were also higher because of the increased volumes.

On a BOE basis, operating costs per synthetic barrel actually declined moving from $54 per barrel in the first quarter to $46 per barrel in the second quarter. We expect the per barrel cost to continue to trend downward as reliability and production increases.

Moving to slide 12 and the Integrated Gas segment, second quarter segment income decreased $17 million, primarily as a result of lower sales volumes.

Slide 13, while rather busy, provides an analysis of preliminary cash flows for the first half of 2011. Operating cash flow from continuing operations, before changes in our working capital, was slightly over $2.4 billion. Our cash balance was increased by working capital changes of $872 million as a result of increased commodity prices and the ensuing higher payables related to Norwegian taxes.

Capital expenditures were $1.7 billion. Asset disposals generated proceeds of $371 million, and dividends paid totaled $356 million, reflecting a $0.25 dividend of which we will retain 60% on a go-forward basis. As a result of the spinoff of the downstream businesses, debt was reduced by $2.8 billion, and a distribution was made to MPC of just over $1.6 billion, while discontinued operations contributed $3.6 billion. Our cash balance at the end of the second quarter was $4.7 billion.

As shown on slide 14, at the end of the second quarter, our cash adjusted debt to total capital ratio was 2%. But I would remind you, we have the pending all cash Eagle Ford acquisition of $3.5 billion, subject to closing adjustments, expected to close November 1. Taking this into consideration, had the Eagle Ford acquisition closed in the second quarter of 2011, cash adjusted debt to capital would have been approximately 18%.

As a reminder the net debt to total capital ratio includes about $221 million of debt serviced by US Steel. With that, I will turn over the call to Clarence Cazalot for a few remarks.

Thank you, Howard, and good afternoon, everyone. As you are well aware, this was our last quarter as an integrated company, having spun off MPC June 30. I'm proud of the team that worked so diligently to make this happen. I wish everyone at MPC all the best.

From the standpoint of our continuing operations, I'm personally not satisfied with our overall second quarter performance, and I know our team feels the same way. The short-term reliability issues in some of our international assets, which as you know have historically demonstrated outstanding reliability, and the disappointing results at Droshky impacted both our second quarter production and financial results.

Our international operations are now back at full speed, and we have properly addressed the reliability issues. Going forward, we are pursuing a more balanced, lower risk, and I believe more sustainable program of investment and growth in unconventional resource plays. This move is best demonstrated by the outstanding position we have built in the Eagle Ford, particularly with our pending 141,000 net acre acquisition, largely in the heart of the play.

Building the position we have across the premiere liquids rich resource plays in North America is only the start. Every member of our team understands that execution and results are how we will be judged. We will be focused on growing both production and reserves on an absolute and per share basis and generating sufficient free cash flow to fund this growth.

Our emergence as an E&P Company is more than just a name only. It is about delivering profitable growth, and our increased guidance of 5% to 7% compound averaged growth between 2010 and 2016, is a good start in this regard. It's about a significantly higher level of drilling activity to deliver this growth, going from 15 US-operated land rigs currently to over 40 rigs operating 18 months from now. It is about continuing to increase our overall resource position with a focus on liquids rich plays, and we are doing this.

Bottom line, it is about consistent execution and demonstrating profitable growth year after year, and funding this growth from internally generated cash flow, and that is precisely what we intend to do. Now we will move to the Q&As.

(Operator instructions)

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

Yes, it is Ed Westlake. Good luck as an independent E&P Company. The first question on the back-end. Obviously you flagged you are going to be raising production increasing rig counts there. Can you talk about any of the latest drilling results that you have had up there in terms of EURs or IPs, particularly capital costs per well in light of service cost inflation?

Ed, this is Dave Roberts. I think we are still very happy with the estimates that we have across the play for the various EURs that we have. And I think we have been fairly consistent that, in what we would consider the poorer areas, on the border of 450,000 barrels and we are seeing 500,000 to 600,000 in our more promising areas, Mermadon and Aeneas. We continue consistently see 30-day IPs across the play of between 500 and 700 barrels per day.

In terms of completed well costs, we generally are on the order of $7 million -- $7.5 million for our wells today. But I would like, at this point, really to talk about what's going it happen in the future. Because, as you know, we have been probably a little bit slow in the minds of a lot of people in terms of how aggressively we have completed our wells. And we've got a significant stock of wells that have been drilled and are waiting on completion.

The 28 that we have waiting, 26 of them will be 20-stage frac jobs, but they will be pumped to 300 pounds per foot, which will put us in the range of what most people are seeing in terms of the larger stage frac jobs. We will be moving beginning in the next month or so towards outfitting our wells to be able to pump 30-stage fracs on a perspective basis for the remainder of the life in the play.

We expect that that will add on the order of $500,000 to $1 million to the cost of our well. So we'll be seeing those kind of increases on a go-forward basis. But we do expect that that will at least increase the initial rates consistent with what other operators have seen. We'll continue to monitor the plays to see if we should continue to move forward by increasing those stages to accelerate the recovery in the play.

That is very clear. And maybe just switching topic. On the corporate tax outlook of 50% to 55%, obviously E&P in the second quarter was at the low end of that at 50%. Could you just walk us through a little bit what the increase in taxes is likely to come from? Is it an assumption about UK taxes or something else in the mix?

Certainly the UK tax rate did increase during the year, the special corporation tax there, but it is also about mix. As we look forward with higher oil prices, Norway contributes a higher percentage of pre-tax income with lower gas prices. Our EG LNG generates a lower proportion of pre-tax income. As you know Norway has a 78% tax rate. EG has a 25% tax rate.

So while we'd like to help you and give you guidance on what to expect in terms of tax rates because of the broad range of effective tax rates in the various jurisdictions in which we operate, the volatility of commodity prices, it can be a little bit difficult to predict.

But those are the main moving parts?

Those are the two biggest ones, yes.

Okay. Thanks very much.

Our next question comes from Argun Murti of Goldman Sachs.

Clarence, over the years you have shown a willingness to adjust your upstream portfolio. You've not necessarily been [whipped] to any specific assets. I think you bought into Russia, sold out at a profit. And there are numerous examples of that.

I'm just curious, now as an independent how do you see the areas you are in? The Gulf of Mexico is one of the areas I'm thinking about. Droshky is obviously a recent disappoint. There's been Neptune before it. It's a shorter reserve life area. You are starting to gain some critical mass in the Shale plays, which has tended to receive better evaluations amongst the E&P analysts.

How are you thinking about your portfolio now as an independent, I guess specifically the Gulf of Mexico; and should that remain a part of your portfolio? Thank you.

Argun, we certainly saw the write-up that you published several weeks ago that suggested perhaps the disposition of the Gulf of Mexico in light of the stronger onshore, unconventional asset base we had that that might indeed make sense.

I would simply say that you characterized my position of the past correctly. There are no sacred cows. I have said many times before that we constantly review our portfolio, in terms of those assets and opportunities that have the kind of growth and value creation that we want to invest in the future. And as you have seen in the past, we haven't hesitated to divest of those assets that don't fit that.

We are, indeed, looking at our portfolio, particularly as we seek to generate additional funds to invest in profitable growth. We continue to see good opportunities coming our way in the attractive core resource plays that we want to grow in. And as we view our investment, it's not all incremental. It is really about redeploying proceeds out of, again, less promising, lower growth, more mature declining assets and into growth.

With respect to the Gulf of Mexico, Argun, I don't want to speculate about any one asset at this time. We certainly, from an exploration standpoint, see the Gulf of Mexico as one of our better, high potential exploration focus areas around the world. As soon as we can get some permits to get back to drilling, that's what we intend to do out there. So that's where we are.

That is a very candid and helpful answer. Thank you very much, Clarence. Maybe just as a follow-up, you have clearly made progress in the Shale plays and you'll close on this Bakken acquisition -- or excuse me, the Eagle Ford acquisition in November.

Do you believe that Shale program is at a critical mass where you have confidence in its running room and is today a core part of the portfolio? I realize it is a subjective question. But how do you perceive where you are in that? Or are there still a number of steps you still need to take in the Shale areas?

Well, I think we certainly are approaching if not at a critical mass. I think if you look at what we've said in the press release, Argun, that in terms of these unconventional plays in North America, that we expect to have production of about 175,000 BOE per day by 2016. Again the vast majority of that from the US resource plays. That is indeed critical mass.

But at the same time, I think as we have indicated, we continue to seek both on acquisitions in those core areas to grow our position. Again this is a program that we operate, that we drive the value creation in and to the extent we could have a broader opportunity set or indeed even have a higher interest in the wells that we are already going to be drilling, that's of great interest to us. So that is where you are going to see us putting our incremental dollars in terms of building our positions there.

What I liked about the Eagle Ford is not simply our total position but our position in the core area. As we've indicated, we believe we have a top five, leasehold position in that core area, and we see a great deal of upside, certainly in terms of productivity, but also the ability to down space in those areas. So again, that's where we'll focus our investment.

Appreciate your thoughts. Thank you very much.

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

Good afternoon, guys. Thanks for taking my call.

You guys talked about US unconventional growth. Maybe I could shift to Poland where Marathon has acreage across the three major basins in the country. In fact, you have the largest by factor relative exposure versus your peers. I know it's early days, could you talk to me about the differences you see in the geology amongst the three basins and where you expect to drill two wells in the second half of the year? I have a couple of follow-ups.

Evan, this is Dave. What we tried to do is similar to what we think we've ascertained about these unconventional plays in the United States. We believe that there is the potential for there to be liquids as well as gas windows across this very large area. So that is the reason you see our portfolio spread out the way it is, because we are hoping to catch on to that.

The first well that we'll drill will be to test that particular concept and then we'll go ahead and drill out. I guess I would say one of the reasons that we did the farm downs that we did was to make sure that we had a very large acreage exposure. But making sure that the financial exposure to the play is relevant to the size of company we are.

We think we've got a good spread of opportunities. It clearly is a portfolio, because of the number of blocks that we have. And we are very excited about getting a couple of wells drilled towards the latter part of this year.

So it is interesting. So you are looking for a potential liquids window as well, is that in the Baltic basin? Is that what you mentioned what basin you are drilling your wells in?

Let me flip to that real quick, since my Polish is kind of bad. What we'll be looking at doing is the Loveland Trough is what we think will be the most likely area for there to be a liquid potential and that will be where we drill our first well.

Okay, and then, maybe we could just move on to a different production guidance question. You've narrowed the full range year-end. On the first quarter conference call, I thought you had got it to 15 to 17 on Droshky. Clearly your comments here, producing to abandonment in 1H12. What is the imbedded Droshky volume going to in that guidance in the second half and first half of 2012?

Right now Droshky is producing between 11,000 and 12,000 barrels a day oil. And what we are looking at is, essentially, there's a physical limitation of the ability of the reservoir to lift barrels when the total fluid gets to about 12,000 barrels a day. We are producing 22,000 gross. If you can think about this in terms of we are seeing about a 25% to 30% annual decline rate.

An issue is, right now we are seeing slugging issues, as you would expect, toward the latter stages of this. And so, it's difficult to use just a decline curve analysis. But our views suggest that we are at a 40% water cut now, assuming that's consistent. My guess is that Droshky would probably end its life on the order of 3,000 to 4,000 barrels a day sometime next year, oil.

Just to confirm your new guidance includes your acquired Eagle Ford acreage? With the offset of Droshky and Delatte Ozona, it appears you are making up some of the balance elsewhere in the portfolio? Can you discuss some positive contributions Q-on-Q?

We are obviously counting the Eagle Ford acquisition post the first of November. But it is a fairly small volume, even though we are very excited about the exit rate being 13,000-plus barrels a day. So the mass serves a small volume.

Consistent with Clarence's earlier comments and what we saw in the first quarter, we looked at the reliability issues that we had in the Norwegian North Sea and to a lesser degree in West Africa, and EG as kind of an aberration. Continue to expect those assets to over deliver on what your expectations might be, which we think is going to carry us in good stead to hitting our guidance in the latter part of the year.

Okay, that's great. Thank you.

Our next question comes from Blake Fernandez of Howard Weil.

Good afternoon, guys. Thanks for taking my question. I had a couple of quick modeling questions and then one broader strategic question. On the modeling, just wanted to confirm, on 2012 production guidance, for one, does that include Libya? And secondly on the natural gas realizations, it looked like they actually declined sequentially, which was a little bit confusing to me, because most of the benchmarks that we looked at actually increased.

Yes, this is Dave. I can answer the first one categorically. Our guidance for 2012 does not include Libya. The sequential gas price realizations are actually up quarter-to-quarter.

Okay. I'm sorry. I'll have to double check that.

Clarence, I had a strategic question for you. As you moved to more of an independent E&P peer group, obviously the integrated tend to focus more on margins, a return on capital employed whereas the E&P space tend to see focus more on volume metric growth. Right out of the gates, you have a nice Eagle Ford acquisition here which is going to increase your production growth. I'm just curious, is there any change to your strategic focus on running the Company?

Blake, I think there is no question that the yard sticks -- the metrics do indeed change as you move from an integrated space to an E&P. I think the measures that you'll see us focusing on with respect to our new business are really twofold. One is production growth per share, and we'll view that on an debt adjusted basis. And again that is an area that we recognize that at 5% to 7% compound average growth on a pure volume metric basis, we may not be as high as some of our E&P brethren.

But the reality is from our standpoint, we believe we generate sufficient cash flows internally to fund our growth. We won't be issuing equity or necessarily having to go to the debt markets to fund our CapEx, and indeed with sufficient free cash flow having the ability to either pay down debt or potentially in certain stances buy back stock. So that is a measure we think we can perform quite well on.

The other metric of course is the generation and growth and free cash flow. And again, we believe with a strong base, with a solid set of liquids focused, growth assets that we'll be executing on, we believe will perform well against that metric as well. So it is clearly a shift from what has been an earnings focus, competitive group to now what is a cash focus group for all the reasons you know well in terms of different accounting methods between the two. And again, moving away from ROCE, to really growth in volumes, both reserves and production.

Blake, on your gas question, the reason the difference is that a large portion of our Alaska gas volumes are through long-term contracts, which tend to lag in price and have alternative commodity indexes rather than Henry Hub.

Okay, that makes sense. Thank you very much.

Next question comes from Paul Cheng of Barclays Capital.

Thank you, a number of quick questions. Maybe this is for Howard. Alaska LNG operation, when that is going to cease to operate?

Paul, this is Dave. We expect there will probably be an additional cargo or two in August or September. Then at that point, our view is that the plant will reach the end of its useful life.

So Dave, what is the warning that we are talking about in the third quarter then?

I'm sorry, Paul?

What is the total, the FH1 for Alaska -- (multiple speakers)

Volume? Average volume?

Yes. In the third quarter.

Why don't we get that for you?

I'll get you that offline, Paul. (multiple speakers)

That's fine. Dave, what is the actual downtime impact in the [Niohim] in the second quarter?

It is on the order of 11,000 barrels a day for the quarter.

And you say it is already back up. So did they back up before the end of the quarter? Or just after the quarter?

No. It was a shut down in May, Paul, so -- (multiple speakers)

So by July everything back up?

That's correct.

And UK, you dropped sequentially. You said the lifting situation or that the actual production just dropped?

I think in our notes, we do have a lifting situation. But obviously, we are experiencing a continuous decline in our Bray assets.

I think when Howard was going through, he was saying that, and maybe I got it wrong, we have a total underlift at the end of the June of 1.6 million barrel, an underlift of 2 million barrel in Alaska. So should we assume that in international, you are overlift by 400, then? If it is the case, do you have a breakdown by country?

Yes, Paul, for Europe, at the end of the period, we were about 540 for the quarter. A to-date balance is about 450 for all of Europe. For EG, it is about an underlift of about 280. Libya is underlifted about 850, and Alaska's underlifted by about 2 million. The total underlift is about, on a to-date basis, is about 3.6, but the number you were looking at was excluding -- or the number we talked about was excluding the Libya underlift.

Okay. All right. And in Ozona, Dave, what is the total recoverable resource that we expect for Ozona? Any change?

No, it has not changed, Paul. That figure is on the order of 7.2 million barrel.

7.2 million barrel. You are assuming that the 9000-barrel per day net you use, so that would suggest about 15,000 barrel per day gross, so you are expecting out of the 7.2, about 5.5 million barrel to be produced in the first year?

That would not be beyond expectation, Paul.

Okay. And that in 2013, we should as soon it probably dropped 70% or so in the production run rate?

That would be a normal Gulf of Mexico decline, Paul, yes.

On Droshky, Dave, what is the second quarter production and the unit DD&A? And would the unit DD&A change dramatically after the weigh off in the third quarter?

It is 17,500, was the Q2 production for Droshky and we'll get you the DD&A number.

Final one, Howard, in the Oil Sands sales number 41,000 barrel per day, can you remind me if that is net of the royalty or that this is not net of the royalty?

The sales number is net of royalty.

That is net of royalty? Okay. Thank you.

Our next question comes from Faisel Khan of Citigroup.

Good afternoon. Can you talk a little bit about this discovery in Kurdistan; it seems like a fairly large oil column. What are the plans to delineate this and figure out what you guys have here?

Faisel, we are shooting seismic across all four of our licenses, because it is pretty important to be able to tie that down. This particular area, there is multiple other targets. So we'll be drilling, likely later this year, an appraisal well to offset this discovery to see what we actually have and then there will be some follow-on exploration.

I think the most important thing that we will be doing here is we'll be setting up to install early production facilities that will be ready probably by the middle of next year. These are fairly elementary type systems, so it is not that big of a deal, but two things that gives you, number one and most importantly, it tests the fiscal regime that you have. Because there's reports that people are getting paid for their cost barrels in Kurdistan. We think that's very important from an overall risk standpoint.

And then secondly, these are fractured carbonate reservoirs, notoriously tricky. And so getting some extended production data out of this will tell us what we ultimately have. We feel very good about the fact that we have only been in the country since October, have a couple of discoveries and are setting up to at least have a look-see on the production side pretty quickly as well.

First production test sometime second half of next year; is that fair?

Yes.

Just on the rig count ramp up in North America, from 15 rigs to 40 rigs by the end of next year, it seems like a very large ramp up. Logistically, how do you guys get there? Have you secured these rigs under long-term contracts? Do you have all of the completion crews? How do you get comfortable ramping up to that level of rig count?

We have a very deep relationship with our primary drilling rig contractor in the United States. And we have a schedule that we've worked out with them to basically take delivery of rigs as they are manufactured. We do have contractual line of sight to be able to get to those numbers in each of the various basins, they are outfitted obviously a little bit differently for cold weather service than they might be for the ones that we are going to have in South Texas.

Part and parcel of that is, they have a very diligent training program to make sure that we get qualified crews at the same time we get the rigs, so that is important. At the same time, one of the things, and we mentioned this previously, having a greater depth of rig inventory has given us a little bit more impact in clout in terms of being able to contract for pressure pumping services. And we are on the cusp of getting contractual line of sight on the pumping services requirements and ancillary services that we need in order to get all the stuff done. So we are in very good shape to go from the 15 that we are running today across the US to probably on the order of 10 more by the end of the year. That jump up to 40-plus is not that big of a leap.

Okay. Got you. Last question from me. I guess there was a USGS report that was done on the Cook Inlet of Alaska. I know you guys have some producing fields down in that area. Is there any opportunity for you or is that outside of your set?

No, we are the oldest and longest serving producer in the Cook Inlet. Marathon was one of the first companies that discovered oil and gas up there and has produced on the order of 3 Tcf from that basin. We obviously have taken a hard look at the USGS, and it's been pointed out to us by the regulators in Alaska. I think one of the things that we would say is, there is a tremendous number of wells that have been drilled in that particular basin.

While we are always looking for new opportunities, much of the resource that was outlined in the report is going to be in an off-limits wilderness area that we operate right next to. The other thing we are very focused in on is, they had the highest impact lease sale they've had since 1983 up there a couple of months ago, a couple of new operators. So we'll be paying close attention to the activity in the area to see if it warrants another look on Marathon's behalf.

Thanks for the time, guys.

Next questions comes from Pavel Molchanov of Raymond James.

As an independent company, should we assume that your deferred tax component is going to generally get higher over time?

On the tax deferral, Pavel?

Yes.

I'm sorry, Pavel. I was distracted for a moment. Can you repeat the question, please?

Sure. Typically independents have a higher deferred tax component in their overall tax expenditure than integrated companies. I was wondering whether you would expect that to be true of Marathon?

You know, I don't really have a good answer for that, because I haven't looked at the deferred tax rates for other companies.

Okay. Fair enough. Let me ask a slightly broader one. The long term growth target of 5% to 7%, how much exploration credit is embedded within that?

None. There is, again, none of the rank exploration -- the impact exploration activities that we are undertaking today, factor into that. The existing discoveries we have, for example in the Gulf of Mexico, like Shenandoah, our interest in that, or in the Gunflint discovery, those are in our production growth, but those are existing discoveries. So no future exploration success, impact exploration success, is factored into our production growth.

Pavel, just thinking about it, to the extent that a company is entirely domestic, the IDC generates a lot of deferred taxes, ASO. So I guess if a company was completely domestic, then they probably would have a higher component of deferred to current cash taxes than we would, overall.

Thanks very much.

Our next question comes from Ann Kohler of CRT Capital Group.

Good afternoon, gentlemen and Janet. Most of my questions have been answered. But do you have any update on Birchwood and the status? Are you still looking at submitting an application to the Canadian government at the end of this year, the beginning of next year? Thanks.

Ann, this is Dave. We are continuing with our reservoir analysis; and as we kind of indicated, we are pushing that towards bringing that project to an FID for the first stage toward the middle of next year. Our permitting people are working diligently on what's going to be required to push that application forward, consistent with that timing.

Okay, great. Thank you.

Our next question comes from John Herrlin of Societe Generale.

Got a bunch of quick ones. Kurdistan, matrix or fracture porosity or don't you know yet?

It is too early. I think that's the reason we are going to do a pressure test. Obviously, we hope we have both. That is the reason we need an extended production time.

Same question for the Niobrara? Matrix or fracture or both?

Well, again I think one of the things that we would characterize in Niobrara is very early days and it is one of the things that we'll be looking at that. My guess is from what we've seen at this point, you are looking at more of a matrix situation than fracture.

Okay, good. Could you give us some kind of postmortem on Romeo and will you be drilling more in Indonesia?

We have said that we are going to move to a non-operated status. We have two more blocks over there that we continue to evaluate, and obviously one of them, the Kumawa Block, we are paying very high close attention to a very high profile dry hole in the area in a well that is currently drilling. So we'll continue to look at that.

I think Romeo, the passing guiding block in general, could be characterized as pure frontier type drilling. Great reservoirs, good concept, no hydrocarbons, so it just didn't work.

Okay, that is fine. I got on the call late. With the Gulf of Mexico, do you think even Droshky and Ozona that maybe you need to reduce your networking interest exposure or diversify a little more? Or have you given that any thought?

Clarence answered that a little bit earlier. I think we have consistently said on Droshky that, in retrospect, having a 100% interest there is a challenge at this particular point. But given our optimism going in, it would have been a difficult decision to take.

I think we continue to look at that as we evaluate the risk of the aggregate Gulf of Mexico portfolio, both on an exploration and a future production basis. It's certainly something that we'll take into consideration.

Okay, great. With Hill Corp., are we going to capitalize all of it?

Capitalize the acquisition costs, you mean?

Correct.

Yes.

Yes.

Okay, thanks. And last one for me. North Sea taxes, any sort of adjustment? Maybe you mentioned that. As I said, I got on the call late.

On the UK?

UK side, yes.

Yes, special corporation tax went up by 12 percentage points.

Okay. Thanks.

Next question comes from Michael Karsch of Karsch Capital.

Thank you for taking my call. I guess I'm trying to understand, you had articulated a strategy that you are not very interested in buying back stock. We shouldn't expect that and I understand you played it out early on. But is that a permanent objective or are stocks trading below eight times earnings, is that something you would consider if the stock got to a more depressed level? Or do you always feel like you are better off putting the money back in the ground?

Yes, I think our priority for cash has really never changed. It is to reinvest in the business in a value accretive way. We think that is the best way to drive shareholder value. We are going to keep a strong balance sheet.

Obviously, for an independent, the dividend yield is probably less important than it was for an integrated. As it is, we are near the top end of our comparative group in terms of yield. So to the extent that we've got excess cash being generated, stock buy back is absolutely one of the tools that we would use to optimize our balance sheet.

Yes, I didn't say we were opposed to it in any way. We simply said it is an option, as Janet said, as we have a strong balance sheet; it is one of the options we have.

Thank you very much.

(Operator instructions)

Our next question comes from Doug Leggate of Bank of America Merrill Lynch.

So sorry for being on late. I was still on a plane when the call started. I have a couple of quick ones and forgive me if some of these have already been addressed. The first one is, going and look into 2012, you have got a fairly large footprint still in the Gulf of Mexico, but we haven't really heard anything about rig allocation or rig commitments, as you look towards potentially ramping up that drilling program.

Can you just give us a feel as to where your head is there? And I have a couple of quick follow-ups, please.

Yes, Doug, as Clarence indicated we have two permits submitted. One Dean submitted which is important; it is the Innsbrook re-entry, if you want to call it that, and then one of our exploration projects. I think what we're looking at is, we do still believe we have a deep portfolio, on the order of 20 prospects in the Gulf. We have said previously that we thought about 3 to 4 co-op wells drilling at any one time on an annual basis in the Gulf. I think that number is going to be smaller.

We believe there will be rigs of opportunity in order to get after a program on that particular basis. So once we start getting the permits, we are obviously going to wait until after hurricane season. We'll probably get back after our drilling program in the Gulf of Mexico.

Thanks, Dave. Two quick follow-ups if I may, and they are quick. Forgive me if this has already been addressed, but can you quantify the opportunity cost of the change in mix? Meaning that obviously you are underlifted in the UK. That is some of your highest margin bowels, I guess.

Can you help put a number around how that might have impacted the quarter? And the final one very quickly is, we are hearing from Noble and others that there's moves afoot to maybe try and monetize gas in west Africa. Any update as to how you see a potential secondary and on the next one, and I'll leave it there. Thanks.

We estimate the underlift on an earnings basis on the order of $15 million to $20 million decrement. Not insignificant, but not a large number. I guess the question with respect to future LNG volumes out of EG, one of the things I would say is, we still believe that the Atlantic basin is grossly oversupplied in terms of LNG, and we think that that's going to continue for some period of time. I think you saw something in our release that indicated our belief in that.

We continue to have discussions with the government of EG about what's the most practical way to continue to expand our position there. But we continue to believe and we think the government supports the fact that the most economic and viable way is to utilize the equipment that we already have in EG LNG. And we think most of the gas will come on in a period of time such that it can just be used to keep train 1 full. As we get volumes beyond that, then we would consider expanding our franchise.

Thanks, Dave. Appreciate it.

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

Thanks for a second question. On the Athabasca Oil Sands, obviously you're mid start-up; your costs sort of have come down. When do you think you will be fully up and running in AOSP and what sort of OpEx do you think you can get down to as reliability improves?

I think, Ed, the historic number has always been sub-30. I think the partnership right now is saying that they would like to see the numbers that we are marking now about 46 coming in to the $35 range. Clearly all the equipment is up and running. This is a matter of keeping the equipment running reliably.

And obviously we are looking forward to some solid quarter-on-quarter performance to demonstrate that we can actually use the name plate capacity that we have out there. So we'll keep a watch on that. But we have some very good days; we have some not so good days. Certainly as the cooler weather approaches, we would expect reliability to improve out there.

Thank you.

I'm showing no further questions at this time.

Thank you much, and we appreciate everyone's attention and interest in Marathon Oil and will be speaking with you hopefully very soon in the future. Have a great day.

Thank you, ladies and gentlemen, this concludes today's conference. Thank you for participating, you may all disconnect.