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Marathon Oil (NYSE:MRO)

Q2 2011 Earnings Call

August 02, 2011 2:30 pm ET

Executives

Clarence Cazalot - Chairman, Chief Executive Officer, President and Member of Proxy Committee

Howard Thill - Vice President of Investor Relations & Public Affairs

David Roberts - Executive Vice President of Upstream

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

Analysts

Edward Westlake - Crédit Suisse AG

Evan Calio - Morgan Stanley

John Herrlin - Societe Generale Cross Asset Research

Paul Cheng

Arjun Murti - Goldman Sachs Group Inc.

Douglas Leggate - BofA Merrill Lynch

Pavel Molchanov - Raymond James & Associates, Inc.

Faisel Khan - Citigroup Inc

Ann Kohler - CRT Capital Group LLC

Unknown Analyst -

Blake Fernandez - Howard Weil Incorporated

Howard Thill

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 the 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 continuing operations for 2010 and the first 2 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 pretax adjusted income from continued 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 pretax earnings.

The effective income tax rate for the second quarter, including special items and the effect of foreign currency remeasurement of our deferred tax balances, was 67%. Excluding special items and the effect of foreign currency remeasurement 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 remeasurement 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 cost. 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 and 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 U.K. and Alaska, offset by an overlift of 341,000 boe in EG and 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 cost per boe increased as a result of additional domestic work over expense, the lack of lower-cost Libyan production and turnaround cost of 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 costs. DD&A and foreign income taxes were also higher because of the increased volumes. On a boe basis, operating cost 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 increase.

Moving to Slide 12, in 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 spin-off 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 service by U.S. Steel.

With that, I will turn over the call to Clarence Cazalot for a few remarks.

Clarence Cazalot

Thank you, Howard, and good afternoon, everyone. As you're well aware, this was our last quarter as an integrated company, having spun off MPC June 30. And 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 liability 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 premier liquids-rich resource plays in North America is only the start, and every member of our team understands that execution and results are how we will be judged. We'll 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's about delivering profitable growth, and our increased guidance of 5% to 7% compound average 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 a 15 U.S.-operated land rigs currently to over 40 rigs operating 18 months from now. It's about continuing to increase our overall resource position with a focus on liquids-rich plays, and we are doing this.

Bottom line, it's about consistent execution and demonstrating profitable growth year-after-year and funding this growth from internally generated cash flow. And that's precisely what we intend to do.

And now we will move to the Q&As.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from Ed Westlake of Crédit Suisse.

Edward Westlake - Crédit Suisse AG

Yes, it's Ed Westlake. I guess, the first question on the Bakken. Obviously you've flagged that you're going to be raising sort of production and increasing recounts there. Can you talk about any of the latest drilling results that you've had up there in terms of maybe EURs or IPs or particularly capital cost per well in light of service cost inflation?

David Roberts

Yes, Ed, this is Dave Roberts. I think we're still very happy with the estimates that we have across the play for the various EURs that we have. And I think we've been fairly consistent that in what we would consider the poorer areas there on the border of 450,000 barrels, and we're seeing 500,000 to 600,000 in our more promising areas, Myrmidon and EMEA. And we 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 to $7.5 million for our wells today. But I'd like, at this point, really to talk about what's going to 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 completed our wells. And we got a significant stock of wells that have been drilled and are waiting on completion. The 28 that we have waiting are -- 26 of them will be 20 stage frac jobs, but they'll be pumped at 300 pounds per foot, which will put us in the range of what most people are seeing in terms of the larger states frac jobs. And 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 life in the play. We expect that, that will add on the order of $500,000 to $1 million to the costs 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 other operators have seen. And we'll to continue to monitor the play to see if we should continue to move forward by increasing those stages to accelerate the recovery in the play.

Edward Westlake - Crédit Suisse AG

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

Janet Clark

Certainly, the U.K. tax rate did increase during the year on the special corporation tax there, but it's also -- it's about mix. As we look forward with higher oil prices, Norway contributes a higher percentage of pretax income with lower gas prices. Our EG -- LNG generates lower proportion of pretax income. As you know, Norway has 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 rate, because of the broad range of effective tax rate in the various jurisdictions in which we operate, the volatility of commodity prices, it can be a little bit difficult to predict.

Edward Westlake - Crédit Suisse AG

Okay, but those are the main moving cost?

Janet Clark

Those are the 2 biggest ones, yes.

Operator

Our next question comes from Arjun Murti of Goldman Sachs.

Arjun Murti - Goldman Sachs Group Inc.

Clarence, over the years, you've shown a willingness to adjust your Upstream portfolio. You've not necessarily been wed to any specific asset. I think you bought into Russia, sold that 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're in, and the Gulf of Mexico is one of the areas I'm thinking about. Droshky is obviously a recent disappointment, as the Neptune before it. It's a shorter reserve life area. You're starting to gain some critical mass in the shale plays, which tended to receive better valuations amongst the E&P analysts. How are you thinking about your portfolio now as independent and, I guess, specifically the Gulf of Mexico and should that remain a part of your portfolio?

Clarence Cazalot

Arjun, 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 have, that, that might indeed make sense. I would simply say that you characterize my position of the past correctly. There are no sacred cows. I've 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've seen in the past, we haven't hesitated to divest of those assets that don't fit that. But 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 poor resource plays that we want to grow in. And as we view our investment, it's not all incremental. It's 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, Arjun, 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. And 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.

Arjun Murti - Goldman Sachs Group Inc.

That's a very candid and helpful answer, Clarence. Maybe just as a follow-up, you've 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's 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?

Clarence Cazalot

Well, I think we certainly are approaching, if not at a critical mass. I think, if you look at what we said in the press release, Arjun, 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 in the U.S. resource plays. That's indeed critical mass. But at the same time, I think, as we've indicated, we continue to seek bolt-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 can have a broader opportunity set or indeed even have a higher interest in the wells that we're already going to be drilling. That's of great interest to us. So that's where you're going to see us putting our incremental dollars in terms of building our positions there. You know what I like 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-5 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.

Operator

Our next question comes from Evan Calio of Morgan Stanley.

Evan Calio - Morgan Stanley

You guys talked about U.S. unconventional growth, but maybe I could shift to Poland where I know Marathon's acreage across the 3 major basins in the country and in fact you have the largest, by factor, relative exposure versus your peers. And so I know it's early days. I mean, could you talk to me about the differences you see in the 3, the geology amongst the 3 basins and where you expect to drill. I think it's 2 wells in the second half of the year. And I have 2 follow-ups.

David Roberts

Evan, this is Dave. And I guess what we tried to do is similar to what we think we ascertained about things in unconventional plays in the United States. We believe that there's a potential for there to be liquids as well as gas windows across this very large area. And so that's the reason you see our portfolio spread out the way it is because we're hoping to catch on to that. And 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 the company we are. So we think we've got a good spread of opportunity clearly as a portfolio because of the number of blocks that we have, and we're very excited about getting a couple of drills towards the latter part of this year.

Evan Calio - Morgan Stanley

So it's interesting. So you're looking for a potential liquids window as well. And is that in the Baltic basin? Is that -- you'd mentioned kind of what basin your drilling your wells in?

David Roberts

Let me check that real quick. My Polish is kind of bad. I think what we'll be looking at doing is -- the level in trough [ph] is what we think will be the most likely area for there to be a liquids potential. And that's would be where we drill our first well.

Evan Calio - Morgan Stanley

Okay. And then let me just move on to a different production guidance question. I know you narrow the full range year end, and on the first quarter conference call, I thought you'd guided to your 15 to 17 on Droshky. Clearly, your comments here producing to abandonment in 1H '12. What is the embedded Droshky volume going to in that guidance in the second half and first half 2012?

David Roberts

Well, I think that the -- right now, Droshky is producing between 11,000 and 12,000 barrels a day of oil, and what we're 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're producing 22,000 gross. If you can think about this in terms of we're seeing about a 25% to 30% annual decline rate, an issue is right now we're seeing slugging issues, as you'd expect, towards the latter stages of this. And so it's difficult to use just a decline curve analysis. But our view suggests that where the 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.

Evan Calio - Morgan Stanley

Okay, that's good. And then just to confirm, your new guidance includes you acquire Eagle Ford acreage. And I guess with the offset of Droshky and plate Ozona, it appears you're making up some of the balance also on the portfolio. Can you discuss maybe some positive contributions Q-on-Q?

David Roberts

Yes, we're obviously counting the Eagle Ford acquisition post the 1st of November, but it's a fairly small volume, even though we're very excited about the exit rate being 13,000 barrels-a-day-plus, so the mass is just small volume. I think, 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 is kind of an aberration. Continue to expect those assets to over-deliver on what the 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.

Operator

Our next question comes from Blake Fernandez of Howard Weil.

Blake Fernandez - Howard Weil Incorporated

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 then secondly on the natural gas realization, it looked like they actually declined sequentially, which is a little bit confusing to me because most of the benchmarks that we looked at actually increased.

David Roberts

Yes, I -- this is Dave. And I can answer the first one categorically. Our guidance for '12 does not include Libya. And the sequential gas price realizations are actually up quarter-to-quarter.

Blake Fernandez - Howard Weil Incorporated

Okay. I'm sorry, I'll have to double-check that. Clarence, I had a strategic question for you. As you move to more of a independent E&P peer group, obviously the integrated tend to focus more on margins and return on capital employed, whereas the E&P space tends to focus more on volumetric growth. Right out of the gate, you've got 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?

Clarence Cazalot

Yes, I think, Blake, there's no question that the yardsticks, the metrics doing the 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 two-fold. One is production growth per share, and we'll view that on a debt-adjusted basis. And again, that's an area that we recognized that, at 5% to 7% compound average growth on a pure volumetric basis, we may not be as high as some of our E&P brethren. But the reality is, again from our standpoint, we believe we generate sufficient cash flows internally to fund our growth. And so 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 instances, buy back stocks. So that's a measure we think we can perform quite well on. And the other metric of course is the generation and growth in free cash flow. And again we believe, with the 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, a competitive group, to now what is a cash-focused group for all the reasons you know well in terms of different accounting methods between the 2 and again moving away from ROCE to really growth in volumes, both reserves and production.

David Roberts

Blake, on your gas question, the reason -- the difference 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.

Blake Fernandez - Howard Weil Incorporated

Okay, that makes sense.

Operator

Your next question comes from Paul Cheng of Barclays Capital.

Paul Cheng

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

David Roberts

Paul, this is Dave. We expect to approve an additional cargo or two in August or September, and then at that point, our view is that the plant will reach the end of its useful life.

Paul Cheng

So Dave, so you have -- what is the won-in that we're talking about in the third quarter, then?

David Roberts

I'm sorry, Paul?

Paul Cheng

What's the total won there, average won for Alaska in the third quarter?

David Roberts

I'll give you that offline.

Paul Cheng

Okay, that's fine. And Dave, what's the actual downtime impact in the second quarter?

David Roberts

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

Paul Cheng

And you say it's already back up. So did they back up at the -- before the end of the quarter or just after the quarter?

David Roberts

No, it was a shutdown in May, Paul, so...

Paul Cheng

Okay, so that by July, just everything back up?

David Roberts

That's correct.

Paul Cheng

And U.K., you dropped sequentially. Is it a lifting situation or the actual production just dropped?

David Roberts

I think, in the notes, we do have a lifting situation, but obviously we are experiencing a continuous decline in our Brae assets.

Paul Cheng

And I think, when Howard was going through, he was saying that maybe I guided wrong. We have a total underlift at the end of June of 1.6 million barrels and underlift of 2 million barrels in Alaska. So with that, should we assume that international you overlift by 400,000? And if it is the case, do you have a breakdown by countries?

Howard Thill

Yes, Paul, for Europe, at the and of period we were about 540,000 for the quarter. To-date balance is about 450,000 for all of Europe. For EG, it's about an underlift of about 280,000. Libya's underlifted about 850,000. And Alaska's underlifted by about 2 million. The total underlift is about, on a to-date basis, is about 3.6 million. But the number you were looking out was excluding -- or the number we talked about was excluding the Libya underlift.

Paul Cheng

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

David Roberts

We have not changed, Paul, and that figure is on the order of 7.2 million barrel.

Paul Cheng

7.2 million barrels. And you're assuming that the 9,000 barrel per day net to use, so that was just about 15,000 barrel per day gross. So you're expecting, out of the 7.2 million, about 5.5 million barrels to be produced in the first year?

David Roberts

That would not be beyond expectation, Paul...

Paul Cheng

Okay. So that then, in 2013, we should assume you probably drop 70% or so in the production run rate?

David Roberts

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

Paul Cheng

Okay. On Droshky, Dave, what's the second quarter production and unit DD&A? And will the unit DD&A change dramatically after the write-off in the third quarter?

David Roberts

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

Paul Cheng

Okay. And the final 1, Howard, in the oil sand sales number, 41,000 barrel per day, can you remind me, is that net of the royalty? Or that this is not net of the royalty?

Howard Thill

The sales number is net of royalty.

Operator

Our next question comes from Faisel Khan of Citi group.

Faisel Khan - Citigroup Inc

Can you talk a little bit about the discovery at Kurdistan? It seems like a fairly large oil column. What were the plans that kind of delineate this? And kind of figure out what you guys have here?

David Roberts

Yes, Faisal, we're shooting seismic across all 4 of our licenses because it's pretty important to be able to tie that down. This particular area, there's 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 where I think the most important thing that we'll 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's not that big of a deal, but 2 things that gives you. Number one, and most importantly, it tests the fiscal regime that you have because there's reports that the people are getting paid for the 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 it is that we ultimately have. So you'll feel very good about the fact that we've 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.

Faisel Khan - Citigroup Inc

Okay, got you. So first production test some time second half of next year, that fair?

David Roberts

Yes.

Faisel Khan - Citigroup Inc

Okay. And then just on the rig count kind of 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? Maybe secure these rigs under long-term contracts, give out completion clues like -- how do you get comfortable ramping up to that level of rig count?

David Roberts

We have a very deep relationship with our primary drilling rig contractor in the United States, and we've scheduled -- we've worked out with them to basically take delivery of rigs as they're manufactured. We do have contractual line of sight to be able to get to those numbers and in each of the various basins. They're outfitted obviously a little bit differently for cold weather service than they might be for the ones that we're going to have in South Texas. Part and parcel of that is they have a very diligent training program to make sure that we that qualified crews at the same time we get the rigs, so that's important. The same time, one of the things that we mentioned is previously having a greater depth of rig inventory has given us a little bit more impact and clout in terms of being able to contract for pressure pumping services. And we're 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're in very good shape to go from the 15 that we're running today across the U.S. to probably on the order of 10 more by the end of the year, so that jump up to 40-plus is not that big of a leap.

Faisel Khan - Citigroup Inc

Okay, got you. Last question for me. I guess there was a USGS report that was done one the Cook Inlet of Alaska. I know you guys have some producing field in that area. Is there sort of an opportunity for you? Or is that kind of outside your set?

David Roberts

No. We're the oldest and longest-serving producer in Cook Inlet. Marathon was one of the first companies that discovered oil and gas up there, and it's 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 to us by the regulators in Alaska. I think one of the things that we would say is there's tremendous number of wells that have been drilled in that particular basin. While we're 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. But the other thing we're very focused in a lot is they had the highest impact, the least sale they've had since 1983 up there a couple months ago, the couple of new operators, and so we we'll be paying close attention to the activity in the area. Let's see if it warrants another look on Marathon's behalf.

Operator

Our next question comes from Pavel Molchanov of Raymond James.

Pavel Molchanov - Raymond James & Associates, Inc.

First, just a quick housekeeping item. As an independent company, should we assume that your deferred tax component is going to generally get higher over time?

Howard Thill

On the tax deferral, Pavel?

Janet Clark

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

Pavel Molchanov - Raymond James & Associates, Inc.

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

Janet Clark

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

Pavel Molchanov - Raymond James & Associates, Inc.

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

Clarence Cazalot

None. There's -- again, none of the ranked exploration, the impact exploration activities that we're 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.

Janet Clark

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

Operator

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

Ann Kohler - CRT Capital Group LLC

A question -- most of my questions have been answered, but do you have any update on Birchwood? And the status, if you're looking after submitting an application to the Canadian government at the end of this year, the beginning of next year?

David Roberts

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

Operator

Our next question comes from John Herrlin of Societe Generale.

John Herrlin - Societe Generale Cross Asset Research

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

David Roberts

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

John Herrlin - Societe Generale Cross Asset Research

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

David Roberts

Well, again, I think it's -- I think one of the things that we would characterize in Niobrara is very early days, and it's one of the things that we'll be looking at that. But my guess is, from what we have seen at this point, you're looking at more of a matrix situation than fraction.

John Herrlin - Societe Generale Cross Asset Research

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

David Roberts

Well, we've said that we're going to move to a non-operated status. We've got 2 more blocks over there that we continue to evaluate, and obviously 1 of them, the Kumawa Block, we're paying very close attention to a very high profile dryhole-ing area and a well that's currently drilling, so we'll continue to look at that. I think, Romeo, the Pasangkayu block in general could be characterized as pure frontier-type drilling. Great reservoirs, good concept, no hydrocarbons, and so it just didn't work.

John Herrlin - Societe Generale Cross Asset Research

Okay, that's all right. I got in the call late. With the Gulf of Mexico, do you think, given Droshky and Ozona, that maybe you need to reduce your network in interest exposure or diversify a little more? Or have you given that any thought?

David Roberts

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

John Herrlin - Societe Generale Cross Asset Research

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

Clarence Cazalot

Capitalize the acquisition costs, you mean?

John Herrlin - Societe Generale Cross Asset Research

Correct.

Janet Clark

Yes.

Clarence Cazalot

Yes.

John Herrlin - Societe Generale Cross Asset Research

And last one for me. North Sea taxes, any sort of adjustment? Maybe you mentioned that, it's just that I got in the call late.

Janet Clark

On the U.K.? It was...

John Herrlin - Societe Generale Cross Asset Research

U.K. side, yes.

Janet Clark

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

Operator

Our next question comes from Michael Carsh of Carsh Capital [ph].

Unknown Analyst -

I guess I'm trying to understand. You'd articulated a strategy that you're not very interested in buying back stock. We shouldn't expect that, and I understand you've played it out early on. But is that a permanent goal -- permanent objective? Or are your stocks trading below 8x earnings? Is that something you would consider if the stock got to a more depressed level? Or do you always feel like you could put -- you're better off with your money back in the ground?

Janet Clark

I think our priority for cash has really never changed, it's to reinvest in the business in a value-accretive way. We think that's the best way to drive shareholder value. We're going to keep a strong balance sheet. Obviously, for independent, the dividend yield is probably less important than it was for the integrated, and as it is, we're that near the top end of our competitor group in terms of yield. So to the extent that we've got excess cash being generated, stock buyback is absolutely one of the tools that we would use to optimize our balance sheet.

Clarence Cazalot

Yes, I didn't say we were opposed to it, anyway. We simply said it's an option. As Janet said, as we have a strong balance sheet, that's one of the options we have.

Operator

[Operator Instructions] Our next question comes from Doug Leggate of Bank of America Merrill Lynch.

Douglas Leggate - BofA Merrill Lynch

I had a couple of quick ones, and forgive me if some of these have already been addressed. The first one is, going, looking into 2012, you've 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 head towards potentially ramping up that drilling program. Can you just give us a feel as to where your field head is there? And I've got a couple of quick follow-ups, please.

David Roberts

Yes, Doug, as Clarence indicated, we have 2 permits submitted: One Dane submitted, which is important, it's the Innsbruck reentry, 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've 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's going to be smaller. We believe there'll be rigs of opportunity in order to get after our program on that particular basis. And so once we start getting the permits, we're obviously going to wait well after hurricane season. We'll probably get back after our drilling program in the Gulf of Mexico.

Douglas Leggate - BofA Merrill Lynch

Great. Two quick follow-ups, if I may, and they are quick. Forgive give if this has already been addressed, but can you quantify the opportunity cost of the change in mix? Meaning that, obviously you were underlifted in the U.K., that's some of your highest margin bowels, I guess. Can you help put a number around how that might have impacted the quarter? And the second the one, very quickly, is we're hearing from Noble and others that there's moves at first to maybe try to monetize gas in West Africa. Any update as to how you see a potential second train in Equatorial Guinea? And I'll leave it there.

David Roberts

Yes, I think we estimate the underlift on an earnings basis, on the order of $15 million to $20 million decrement. So 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, and 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 one full. And then as we get volumes beyond that, then we would consider expanding our franchise.

Operator

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

Edward Westlake - Crédit Suisse AG

Just on the Athabasca oil sands. Obviously, you're mid-startup. Your costs sort of have come down, but when do you think you'll be fully up and running in AOSP? And maybe what sort of OpEx do you think you can get down until its reliability improves?

David Roberts

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're marking now, at about $46 coming into the $35 range. Clearly, all the equipment is up and running. This is a matter of keeping the equipment running reliably and obviously we're looking forward to some solid quarter-on-quarter performance to demonstrate that we can actually use the nameplate capacity that we have out there, and 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'd expect reliability to improve out there.

Operator

I am showing no further questions at this time.

Howard Thill

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

Operator

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

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