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Executives

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

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

Lance Robertson - Regional Vice President of The South Texas/Eagle Ford

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

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

Analysts

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

Edward Westlake - Crédit Suisse AG, Research Division

Evan Calio - Morgan Stanley, Research Division

Scott Hanold - RBC Capital Markets, LLC, Research Division

Guy A. Baber - Simmons & Company International, Research Division

Blake Fernandez - Howard Weil Incorporated, Research Division

Paul Y. Cheng - Barclays Capital, Research Division

Paul Sankey - Deutsche Bank AG, Research Division

John Malone - Global Hunter Securities, LLC, Research Division

Eliot Javanmardi - Capital One Southcoast, Inc., Research Division

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

Marathon Oil (MRO) Q2 2012 Earnings Call August 1, 2012 2:00 PM ET

Operator

Welcome to the Marathon Oil Corporation Second Quarter 2012 Earnings Conference Call. My name is Christine, and I will be your operator for today's conference. [Operator Instructions] Please note, today's conference is being recorded.

I will now turn the call over to Howard Thill, Vice President, Investor Relations and Public Affairs. Please go ahead, sir.

Howard J. Thill

Welcome to Marathon Oil Corporation's second quarter 2012 earnings webcast and teleconference. The synchronized slides that accompany this call can be found on our website, marathonoil.com. On the call today are: Clarence Cazalot, Chairman, President and CEO; Janet Clark, Executive Vice President and CFO; Dave Roberts, Executive Vice President and COO; and Lance Robertson, Regional Vice President, South Texas/Eagle Ford.

Slide 2 contains the forward-looking statement and other information related to this presentation. Our remarks and answers to questions today will contain forward-looking statements subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied by such statements. In accordance with Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995, Marathon Oil Corporation has included in its Annual Report on Form 10-K for the year ended December 31, 2011, and subsequent Forms 10-Q and 8-K cautionary language identifying important factors, but not necessarily all factors, that could cause future outcomes to differ materially from those set forth in the forward-looking statements.

Please note that in the appendix to this presentation, there is a reconciliation of quarterly net income to adjusted net income for 2011 and 2012, balance sheet and cash flow information, third quarter and full year 2012 operating estimates and other data that you may find useful.

Moving to Slide 3. Our second quarter 2012 adjusted net income of $416 million was a 13% decrease from the first quarter of 2012, largely a result of higher income taxes driven by a change in the mix of production, with higher sales volumes in Libya and lower U.S. pretax earnings. This decrease was partially offset by higher international pretax income.

As shown on Slide 4, earnings before tax from the international portion of our E&P segment increased $76 million, driven by higher sales in Libya, while the domestic portion of that segment decreased $62 million, largely a result of higher exploration expenses. Pretax income for the Oil Sands Mining and Integrated Gas segments each increased $13 million over the previous quarter. Again, the change in production and income mix led to higher overall income taxes.

On Slide 5, we've included a comparison of the total Upstream second quarter versus the first quarter liquid hydrocarbon sales volumes, excluding Libya. In the appendix to this presentation, you will find a similar slide comparing actual second quarter to projected third quarter sales volumes to help you in modeling the company's third quarter. Again, this slide excludes Libya because of the unpredictability of those volumes.

As shown on Slide 6, the second quarter was a good operating quarter for the E&P segment, with higher sales volumes compared to the first quarter. However, this increase was more than offset by lower prices, higher segment income tax expense and higher absolute cost, although on a BOE basis, costs were relatively flat quarter-to-quarter.

Moving to Slide 7. Our U.S. liquid hydrocarbon sales volumes increased while gas volumes decreased, netting to a positive volume variance quarter-to-quarter. Both domestic liquid hydrocarbon and natural gas realizations were lower in the second quarter. On an absolute basis, DD&A was lower owing to our anticipated Alaska disposition.

As shown on Slide 8, total U.S. E&P costs per BOE remained flat with the previous 4 quarters. Excluding exploration expenses, costs per BOE were down $3.80 quarter-over-quarter, with the previously mentioned decrease in DD&A, lower production taxes and reduced field level controllable costs.

Slide 9 graphically demonstrates the Lower 48 onshore production growth we have realized over the past few quarters, with the production from the first to second quarter up almost 7%. Excluding our pending Paloma acquisition, we expect to reach between 120,000 and 130,000 BOED in the fourth quarter 2012, a 60% to 70% increase since the third quarter of 2011. You will also see this growth is weighted to liquids, with the largest increase coming from oil and condensate, followed by an increase in NGL.

Slide 10 shows the positive pretax impact from the previously discussed higher international sales volumes, more than offset by lower liquid hydrocarbon price realizations, higher costs and higher taxes related to the mix issue previously discussed.

Slide 11 compares the international E&P cost structure by category over the past 6 quarters. Compared to the first quarter of 2012, field level controllable cost, DD&A and other costs increased in the second quarter, partially offset by a decrease in exploration expenses.

As shown on Slide 12, quarter-over-quarter, our E&P segment production available for sale was flat while sales volumes increased approximately 6%. Increased production available for sale from the continued ramp-up in the Eagle Ford, Bakken and Anadarko Woodford plays plus Libya were offset by decreased volumes in EG, Norway and the Gulf of Mexico as a result of planned turnarounds.

The second quarter was relatively balanced between production available for sale and actual sales volumes compared to a 23,000 BOED underlift in the first quarter. The cumulative underlift at the end of the second quarter was approximately 5.9 million BOE: 2.7 million BOE underlifted in Libya, 2 million BOE in Alaska gas storage and underlift positions of 1 million BOE in Europe and 200,000 BOE in EG.

Slide 13 shows the more than 14% growth in our E&P production available for sale since the beginning of 2010, excluding Libya. Adjusting for the impact of major turnarounds during the first and second quarters of 2012, we would have had production available for sale of approximately 376,000 and 381,000 BOED, respectively.

Slide 14 shows our Oil Sands Mining segment income increased $10 million sequentially. This was a result of lower operating costs and other expenses, mostly offset by lower price realizations. Net synthetic crude sales were essentially flat quarter-to-quarter at 44,000 barrels per day.

Slide 15 shows that the Integrated Gas segment income increased $9 million quarter-over-quarter on lower volumes. While the terms and conditions of our offtake agreement are confidential, the second quarter results are indicative of what investors can expect from this segment on a go-forward basis with similar volumes and Henry Hub natural gas prices.

Slide 16 provides an analysis of cash flows for the second quarter year-to-date. Operating cash flow before changes in working capital was $2.3 billion, while working capital changes resulted in a $575-million use of cash, primarily due to international tax payments in the second quarter. Cash capital expenditures year-to-date have been $2.2 billion dollars, with proceeds from dispositions totaling $218 million and dividends paid of $240 million. Net debt has increased $430 million year-to-date and the quarter-end cash balance was approximately $450 million.

As shown on Slide 17, at the end of the second quarter 2012, our cash-adjusted debt-to-total-capital ratio was 21%, a slight increase from the first quarter. I'd like to remind you that the appendix has a significant amount of forward-looking data for use in modeling the company's third quarter and full year results.

With that, we'll move to Slide 18, and I'll turn the call over to Clarence for some remarks.

Clarence P. Cazalot

As Howard mentioned, we saw another good performance from our base business, with major turnarounds in Equatorial Guinea and Norway being completed ahead of schedule and under budget. Top quartile reliability and solid operations allowed us to deliver production available for sale at the upper end of our guidance.

We also had strong growth in the second quarter in our 3 key resource plays. Comparing the second quarter to the first quarter, Eagle Ford production was up 50%, Bakken was up 4.7% and the Woodford was up 24%. We're on track to deliver annual 5% growth in production available for sale in 2012 over 2011, excluding Libya. We're also on track to deliver greater than 150% reserve replacement in 2012, excluding acquisitions and divestitures. And we're targeting 6% to 8% growth in annual production available for sale from 2012 to 2013, excluding Libya and Alaska.

In the face of weaker crude and NGL prices, particularly in inland U.S. markets, our focus on profitable growth and our commitment to capital discipline has led us to seek capital reductions without sacrificing growth. For the remainder of 2012 and perhaps into 2013, we're reducing our rig count in the Anadarko Woodford from 6 to 2 rigs, and we're reducing our Bakken rig count from 8 to 5 rigs. We believe we can maintain flat production in both of these areas through 2013 at these rig levels, but obviously, we retain the flexibility to ramp back up if prices and/or costs improve. We've also suspended drilling in the Niobrara and plan to frac 1 additional well already drilled. We will further evaluate the area from data already collected and from the future production history of the 16 production wells we have in the area.

A real success story is being seen in the Eagle Ford, where we've continued to reduce the time needed to drill wells there. And we're now in a position to drill and complete our target number of wells with 18 rigs rather than ramping up to 20 as planned with the Paloma acquisition.

We are focused on maintaining our growth while living within our cash flows. To that point, I'll tell you our asset divestiture program is on track, and we expect to meet or exceed our $1.5-billion to $3-billion divestiture program by the end of 2013. And you'll note in the press release that we have disclosed the potential purchase price in Alaska as being $375 million, and I would also tell you that interest in the sale of our Neptune gas plant, our 50% interest there, has been quite strong, and we'll be reviewing those bids very shortly.

Turning to exploration. We have enhanced the potential and risk profile of our global exploration portfolio, with new entries into Gabon, Kenya and potentially Ethiopia. And as you've seen yesterday, we farmed down 2 Kurdistan blocks, our two 100% blocks, to balance our portfolio.

Lastly, there's been a great deal of attention obviously and a great deal of focus by investors on our Eagle Ford position, and so I've asked Lance Robertson to provide an update on our operations there.

Lance Robertson

Thanks, Clarence. Going to Slide 19, you'll see a map of the Eagle Ford and our acreage position, along with where we are currently drilling. Also in the slide are indicative well results illustrating continued strong performance across the acreage position.

During the second quarter, we became active in the condensate acreage as we continued to build midstream infrastructure to support this area. Our rig activity is currently 50% discretionary and will continue to be directed toward high-value condensate and high GOR oil areas. We anticipate we will keep 10 to 12 rigs active in the core Karnes County area through year end. Note, we are not active in the Wilson County or dry gas areas.

Turning to Slide 20. During the first few months of 2012, we focused on expanding our capability and growing our development capacity. The second quarter saw us build on this solid base with increased rig and frac activity, along with increasing efficiency. With these efforts, quarter-on-quarter production growth was almost 50% in the second quarter. Net production has increased by more than 17,000 barrels of oil equivalent a day in 2012, with the majority of the increase in the second quarter. We anticipate similarly strong growth in the second half of 2012 as we continue to refine our operation practices and move into more pad-driven activities.

We have demonstrated material reduction in cycle time, reducing our average spud-to-spud time by almost 50% since taking over operations late last year, now averaging 23 days spud-to-spud over the last 2 months. Driven by this efficiency, we expect to continue full field development with 18 rigs, inclusive of the Paloma acreage. We also anticipate continuing with 4 fracture stimulation fleets to complement the drilling rigs.

Turning to Slide 21. We have supported our production growth through investing in extensive midstream infrastructure. Shown in green are 5 new large central delivery facilities that have been built in 2012. Shown in red are 6 more central facilities now under construction. Additionally, over 210 miles of 4-, 6- and 8-inch pipelines have been installed to interconnect these facilities with markets. Building midstream capacity has allowed us to maintain a strong cycle of spud to first sales of less than 60 days with minimal shut-in or flaring. Midstream investment will continue through 2012 to ensure sufficient access to markets.

Slide 22 updates our expected number of locations and production forecast inclusive of the Paloma acquisition. Paloma adds 100 high-value, low-risk locations to our existing inventory. We now anticipate our Eagle Ford production reaching 120,000 barrels of oil equivalent a day in 2016 compared to 100,000 barrels previously. Change of control of operations is in progress today in existing Paloma operations, and wells will be assumed with current Marathon personnel. And importantly, no contribution from our downspacing studies has been included in either the well count or production numbers.

To that point and moving to Slide 23, we are evaluating the potential to significantly increase our drill locations and by association production, resource and reserves through validating downspacing with targeted infill pilot projects. 5 density pilot projects are currently producing, 2 are in progress and 3 more remain in 2012. 4 additional pilots targeting vertical lateral placement are currently producing.

We're excited about the progress we've made across the basin to date. We have a dedicated team, and while we have a lot of hard work ahead of us, we're seeing great strides in operational capacity. We're confident in our ability to deliver an average of 30,000 barrels of oil equivalent a day for 2012 and to meet or exceed our projections in coming years. With that, I'll turn the call back to Howard.

Howard J. Thill

Thanks, Lance. [Operator Instructions] Christine, with that, we'd like to open it up for questions.

Question-and-Answer Session

Operator

[Operator Instructions] The first question comes from Doug Leggate from Bank of America.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

I appreciate the additional color, and it's interesting to -- it's great to have Lance on the call. So if I may take advantage of him being here, and I do have a follow-up before you go cutting me off here. So, Lance, the well results -- on the last call, Dave Roberts had suggested a completion rate of 16 to 20 wells. 1,200 barrels a day per week, I think, was the number he gave. And you achieved -- you appear to have achieved that step-up, the average step-up in production in the Eagle Ford despite completing fewer wells. So I'm wondering if you can give us some color, what's happening to the well rates a little bit, maybe some color on what happened to the completions. And if I may, just generally an update because it looks like things are going fairly strong there, if you could give us some guidance. My follow-up is on tax, please.

Lance Robertson

Doug, I'd actually say that I think we have achieved what Dave suggested in the previous call. We are consistently delivering 16 to 20 wells per month to sales for the last 4 months. It does vary up and down, modestly driven sometimes by pad activity. And if we fall a little short of that one month, we typically materially increase the next month. And we've worked concertedly to build a little bit more well inventory so that we can dampen down that oscillation as we move to pad-driven activities more and more for both the opportunity to drive down costs, as well as to improve the well EURs. And regarding the well productivity themselves, I think I would just say that we put out a fair amount of disclosure on that first Eagle Ford slide. And we've gotten really positive well results from the northeast all the way to the southwest of that acreage position. And we're very pleased with those results to date, continue to see some improvements and still have a lot of work ahead to make them even better.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

Okay. I appreciate that color. My follow-up is on tax. Obviously, there's a lot being made of the very high tax rates that you guys have right now. My question is really on Norway. A year or 2 ago, you used to give a slide showing what the trajectory was in Norway in terms of production. And if we take the mix change of that decline in Norway along with the increase in the U.S., one would expect a fairly precipitous decline in that tax rate. Can you just give us an update as to when you anticipate the Norway decline to really start to kick in and whether or not -- how you would frame our expectations for the medium-term tax rate, in other words, beyond 2012?

David E. Roberts

Doug, this is Dave. I think the charts that we're using in our updates have not changed in terms of we expect next year to still be a very strong year. We'll have boiler production coming on to offset some of the decline that we'll see. That comes on in late 2014. And then you'll start to see the declines that you mentioned. And so I'll turn -- then turn it to Janet about forecasting tax.

Janet F. Clark

Of course, Doug, we certainly hope that the production in Norway stays as high as possible for as long as possible, because generally it's very good returns for us on an after-tax basis. But you're directionally correct. As the mix of pretax income shifts from high tax jurisdictions, such as Norway, to a lower tax jurisdiction such as the U.S., our overall effective tax rate, excluding Libya, will continue to decline. So [indiscernible] prices and differentials, et cetera, I can't be more quantitative about that.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

Sure. Just getting some clarity, Janet, the U.S. tax will be 0 cash tax. Is that a fair assumption at this point?

Janet F. Clark

The federal rate is 35%. Currently, we are not in a cash-tax-paying mode given the high level of CapEx here in the U.S.

Operator

The next question comes from Ed Westlake from Crédit Suisse.

Edward Westlake - Crédit Suisse AG, Research Division

Just maybe also given that we could focus on the Eagle Ford, a question around the condensate window to start off with. Just I think it's the Davila or the Davita [ph] well, if I'm reading this correctly, one of the first wells you've drilled in the condensate window. How did the results compare to the sort of 1,650 30-day IP that you were hoping for in the condensate window was a whole?

Lance Robertson

I'd say the Davila wells are relatively new and are performing very strongly. I think our experience in that area is, like you'd expect with many, that there's diversity. I think we're confident that, that area is going to consistently produce, on average, wells that are about 1,650 BOE a day average for 30 days in that group. And there are others in that area that have delivered that year-to-date. I think we're -- essentially, our acquisition model has been proven accurate at this point.

Edward Westlake - Crédit Suisse AG, Research Division

But it's fair to say the results at the moment from that well, I think, it's a 2000 -- just doing the math in my head, it's a 2,024 IP. So with the decline that you see in the early part of the month, maybe what will change to get up to 1,650?

Lance Robertson

I'm sorry, I'm thinking of the math. I mean, that particular well should be in excess of 2,000 barrels a day equivalent right now and has been. I think more I was saying is that in that broad area, we'll have some wells that are below that 1,650 marker and we have some above. But that group will average 1,650 BOE a day on a full-month basis.

Edward Westlake - Crédit Suisse AG, Research Division

Okay. Good. And then just switching to the overall corporate CapEx. You've got $2.2 billion as a run rate for the first half, and you're dropping some rigs in the Bakken and the Woodford, which sort of suggests that maybe the $4.5 billion to $5.5 billion would require a big step-up somewhere else in the portfolio to keep the CapEx unchanged. So maybe just talk through some of the moving parts around the sort of low run rate of CapEx in the first half.

David E. Roberts

Yes. Ed, I think we're right at 50% actually on a run rate basis. So I wouldn't consider that low at all. And I think what we're saying is we're reiterating what we said that last quarter, that the number is going to be circa $5 billion. We've seen pretty significant pressure from 1 particularly large OBO project in our portfolio and a lot of other OBO pressures in some of the unconventional basins, notably the Woodford and the Bakken, that have pushed some of those numbers up. And then in the Eagle Ford, we are drilling longer laterals and putting bigger completions on the wells. And so we're seeing some cost pressures there. But obviously, we're getting better well results also. So that and the early part of the year, we actually are exceeding our pace expectations in places like the Bakken. And so in order to balance out, that's the reason we're cutting back the rigs in the 2 Northern unconventional basins. And it's a pure efficiency decline in South Texas.

Operator

The next question comes from Evan Calio from Morgan Stanley.

Evan Calio - Morgan Stanley, Research Division

Keeping on the theme, in the Eagle Ford, maybe a question for Lance. Was there any update or results you can share on your various downspacing pilots? Or how should we expect the release of that? Are you going to aggregate the data into early 2013? Or was there -- I know at one point, there had been discussed plans for an Analyst Meeting in the fall. Any update there, please.

Lance Robertson

Well, I'd say 3 of those infill pilot tests are producing. When we said that 2 are in progress, those are actually being stimulated now this week and next week. And so our results are early. I mean, we have very limited production history from those. I think we would anticipate being in a position to share results more materially in 2013. And I think we've said before, the failure case would be, if it didn't work, we'd know that very soon. I think we're very optimistic based on simulation modeling and work we already had on wells in 80-acre spacing that it's not going to fail and it's going to longer, both pressure and rate data, to validate how well that is working. I think we're really focused on making sure we get those early 2012 and start that data collection process so that we don't delay reaching those decision points any longer than we have to.

Evan Calio - Morgan Stanley, Research Division

Got it. And maybe another question. I know you guys have invested a lot in midstream infrastructure assets, particularly in the Eagle Ford, in gathering and treating facilities. I mean, do you see any monetization potential of those assets, given a reasonable tax basis and MLP cost of capital advantage there?

David E. Roberts

No, Evan. We don't see that this time. I think we needed to build out the infrastructure, and we put an increased amount of capital to that to make sure that we have the capabilities to deliver on Upstream business. So we're not contemplating any kind of special vehicles in order to release that value.

Operator

The next question comes from Scott Hanold from RBC Capital Markets.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Looking at your presentation, Slide 20 shows the Eagle Ford wells production over the last several months, and there's a bit of a lumpiness. Can you explain if you expect that type of lumpiness going forward? Or now that you're kind of closer to development mode, is it going to be kind of closer to that 16, 18 wells kind of per month type of pace?

Lance Robertson

Sure, Scott. I think we do expect some variability in that, month to month. And I think you're referring particularly to June was down from May. And as it turns out, those were actually large pad-driven infill densities, those pilot projects being completed and brought online. And so there were some low there. I think what you'll see in future quarters is that we're materially up in July as account of that, as we brought on those large groups of well, ups in well count, I would say. I think what we expect forward is some variability, but we're going to continue to dampen that by managing inventory appropriately.

Scott Hanold - RBC Capital Markets, LLC, Research Division

So I think your guidance is, what is it, like 200, 230 wells this year in the Eagle Ford. Is that still intact here? Or do you think you will be at the higher end now or with better efficiencies?

Lance Robertson

Well, we do believe we're going to be in that range from 241 and 251 wells, inclusive of Paloma. And the primary driver of not moving up to 20 rigs for the balance of 2012 is to avoid going off the high end of that range. We've become so efficient that we're just going to capture all the wells we need and finish that development with 2 fewer rigs than we anticipated some months ago.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay. Now I understand. Okay. And then as a follow-up, in the Bakken and, I guess, the Woodford, it looks like you're scaling back activity. So is the intent basically to kind of keep those areas flat over the next year or so or until you see some cost pressure relief? Is that sort of your intent at this point?

Lance Robertson

Yes, Scott. I think as we mentioned in the release, and I think Clarence echoed this in his comments, it's our expectation that we'll be able to hit the exit rates we talked about in the release and maintain flat production with the 2 rigs in Oklahoma and the 5 in North Dakota.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay. And then are your contracts coming for turnaround for pressure pumping and rig rate, so you may have some leverage due to that? Or when do those go through?

Lance Robertson

We're being able to release the rigs on the basis of contracts expiring. And so as economics shift in the basins, we would expect our overall pricing power on drilling rigs to be able to lead us to attractive contract rates. And we are seeing continued pressure downward on pressure pumping services, particularly in the 2 Northern basins. And we'll try to reap those benefits as well over time.

Operator

The next question comes from Guy Baber from Simmons & Company.

Guy A. Baber - Simmons & Company International, Research Division

I had a question on the Eagle Ford just on efficiency gains there. But you mentioned spud-to-spud days at 23, down from 25 a couple of months ago and significant improvement from last year. My question is, what opportunity do you see for further improvement there? Or are you operating right now at levels that you're satisfied with? And if you could provide more specifics on any efficiency improvements you're driving in the Bakken and the Woodford, that would be helpful as well.

Lance Robertson

Guy, referring to Eagle Ford, I think we're really happy with how quickly we've been able to reduce those cycle times. We're managing both the drilling as well as the moving of the rig as active as we can to drive that. We do not think that we're leveling out to extent we're not going to continue to improve. We've taken very little pad activity. It's been in small groups. And as we convert our rig fleet to more pad-efficient rigs with integrated moving systems, which we're in the process of, as we speak, then we expect to be able to move to more and more large pads, and we're going to drive that time down further. But I think we hope to be able to talk about that in future quarters.

David E. Roberts

Yes. And just to amplify what's going on in the Bakken, just talking about year-on-year quarters, we've seen almost a 30% decrease in our times. And we've seen that really in 2 areas. We've been consistently good in our spud-to-TD times, although we've taken about 10% there. But we've halved our moving rates, and we've taken about 10% off of our completion rates as well to get to the levels that we're looking at. And in Oklahoma, at this point and with the limited number of wells that we've drilled, it's all been improved drilling performance, taking the well curves down from on the order of 70 days into the 50s. And that's just drilling performance, getting used to the basin and trying to be as competitive as we can.

Guy A. Baber - Simmons & Company International, Research Division

Okay. Great. Very helpful. And then my follow-up is just with respect to the role exploration will play in the portfolio strategically and longer-terms. But obviously, you guys have been very active recently in acquiring some new frontier acreage. And we had previously been assuming that you were deemphasizing exploration to a certain extent in favor of your North America onshore development. I think your 2012 exploration budget, for example, is down just under 10% year-on-year. So I was just hoping you could provide a little bit more color there on the strategy and how it may or may not have changed.

Clarence P. Cazalot

Dave, I'll take that. This is Clarence. Our strategy has fundamentally not changed. We've said all along that the third leg of our stool of strong base assets, profitable growth is a strong exploration program. And we would devote 10% or roughly $500 million a year to high-impact exploration. And what we've done this quarter is wholly consistent with that.

Operator

The next question comes from Blake Fernandez from Howard Weil.

Blake Fernandez - Howard Weil Incorporated, Research Division

And while we're on exploration, I was just curious, I see there's an increase sequentially from $58 million up to about $115 million. Can you confirm, is that expensing the Kilchurn well in the Gulf?

David E. Roberts

Yes. It is, Blake.

Blake Fernandez - Howard Weil Incorporated, Research Division

Okay. My second one was in the Eagle Ford, really on the transport side. I see you're now up to about 70% of the volumes being transported via pipe. And I'm just trying to understand, if you could maybe give us some color on what the price realizations are looking right now on that piped crude and how that compares to maybe to like the $88-a-barrel realization that you've got for the entire U.S. portfolio.

Lance Robertson

Well, Blake, that's a unique question. We sell to multiple contracts in that because we have a variety of gravity. I would say we've focused very hard the first 2 quarters of '12 on marketing and market access. We sell the majority of our oil today on an LLS-less-$6 kind of contract. We're very happy to have that pricing because you guys were aware those differentials are moving a lot in that regard. So the majority of our oil sales are to that LLS-less-$6, and we have some other contracts as well. And we continue to both take market contracts as we grow our production base in both gas and oil.

Blake Fernandez - Howard Weil Incorporated, Research Division

So just to confirm, so I guess, it's fair to think that as you're growing those volumes and you're increasing your pipeline takeaway, we should think that the price realizations relative to benchmark should improve.

David E. Roberts

Correct.

Operator

The next question comes from Paul Cheng from Barclays.

Paul Y. Cheng - Barclays Capital, Research Division

Two quick ones. First, just to -- for the modeling. For Droshky and Ozona, what is the second quarter average? And should we assume that now you're pretty much 0?

David E. Roberts

No, Paul. Let me get to my sheets here real quick while I'm look at it. Second quarter in Droshky -- or in Ozona was just about 2,300 barrels a day. And Droshky, because we did have a turnaround, is right at 5,000. So we're still hanging in at both of them.

Paul Y. Cheng - Barclays Capital, Research Division

Okay. The second one that, Dave, you were talking about in the Eagle Ford, I think, in the press release, 75% oil and condensate. Do you have a further split between what's the percent of oil -- frac oil and what is the percent of condensate? And have you seen any indication that the condensate started selling at a discount to the frac oil? And whether you could consider the C5, C4 is NGL or condensate in your classification.

David E. Roberts

So between oil and condensate, it's approximately 70% oil and about 30% condensate. And we're currently experiencing strong price realizations on both the crude and the condensate. There's really no material change in that at this time.

Paul Y. Cheng - Barclays Capital, Research Division

And do you consider C5, C4, those molecules, is NGL or condensate in your classification?

David E. Roberts

Yes. We do. I'm not sure -- yes, in the NGLs, we do have a very heavy NGL mix. And those price realizations are very strong, all selling to the Mont Belvieu market. However, as you guys have seen, there's been pressure on that basket of pricing over the recent 90 days.

Paul Y. Cheng - Barclays Capital, Research Division

Yes. That's very helpful. I just want to know that the classification that for the C5, the pentane, or that the C6 are those that are being classified as the NGL in your classification or is being classified as a condensate in your classification.

David E. Roberts

The C5s are in the NGLs. C5, C6s and heavier are all in the NGL split, Paul.

Operator

There's time for one last question. Today's final question comes from Paul Sankey from Deutsche Bank.

Paul Sankey - Deutsche Bank AG, Research Division

Clarence, could you just talk a little bit about the decision to pull back on activity and stay within cash flow or close to cash flow as opposed to -- I assume you had the option to actually accelerate your growth rate by maintaining activity high.

Clarence P. Cazalot

Yes. I think, Paul, again, it's wholly consistent with what we've said around capital discipline and focusing on value rather than volume. And you're spot on. We could continue to maintain higher rig levels and grow the volumes at a faster rate. But in the face, as we've said, of lower commodity prices, both crude and NGL, and continued high costs, we don't see that, that makes a great deal of sense. We'll watch to see if cost and/or pricing improves, and we've got the ability to ramp back up.

Operator

The next question comes from John Malone from Global Hunter Securities.

John Malone - Global Hunter Securities, LLC, Research Division

One question on Libya. Why the continued unpredictability? What is it going to take for you to get comfortable with including that in guidance? And the 43,000 net in production in the quarter, is that -- do you think it's potentially still flush production?

David E. Roberts

Well, John, this is Dave. I think the critical issue is we've passed an important marker with the elections. But we did see some disruptions relative to social unrest continuing into July. There is no question that we have not yet returned to our full capacity in terms of our ability to direct production out there in terms of our workover capacity. And importantly, it's still an unsure enough situation, where we have not had any Western expats looking at the actual production centers in terms of being in the deep desert. And so our view is until we actually put all those things together, being able to get actual eyes on, actually understanding what's driving what probably is a large degree of flush production, but also ensuring -- the Libyans are making great progress, but that we do have a stable environment, we don't think it would be prudent to forecast volumes.

John Malone - Global Hunter Securities, LLC, Research Division

Okay. So once you have some guys there on the ground looking at the conditions of the wells, that would lead you to be more comfortable making a decision on one or the other.

David E. Roberts

Yes. I think obviously, we're very interested in being able to predict these barrels with certainty. They are important to us. So when we get to that level of comfort, we'll be certainly happy to share that with everybody.

John Malone - Global Hunter Securities, LLC, Research Division

Okay. And another question. So what drove the curtailment in the Niobrara? What would it take to start up operations there again? Was it what you saw subsurface? Or is it more a cost issue?

David E. Roberts

I think it's both. I think this is a -- these unconventional plays all share similar characteristics. Because we are drilling horizontal wells and putting very large completions, the well costs are obviously an important factor of the economics. And you have to have an appropriate amount of EUR. And to this particular point, we've not found the right mix of cost and completions versus the type of wells that we're actually able to deliver in the DJ Basin. So we're going to evaluate what it is we have and see if it makes sense for us to either change the way we're looking at that program or do something else altogether.

Operator

The next question comes from Eliot Javanmardi from Capital One.

Eliot Javanmardi - Capital One Southcoast, Inc., Research Division

Just a question on the Oil Sands Mining pricing realizations that we're seeing. I'm seeing a downward trend over the past 3 quarters. Just would like to know what you see happening there and what kind of pricing you could expect going forward in the second half of the year.

David E. Roberts

Yes. We did see obviously weakness in the first half relative to some of the things that drove Bakken weakness. But frankly, Syncrude has bounced back. Our basket should be really looked at as a Syncrude basket because of what we have in terms of our upgrading capability there. And it's comparing very favorably against the WTI. And our expectation is that, that relationship is going to be maintained.

Eliot Javanmardi - Capital One Southcoast, Inc., Research Division

Okay. And finally, last question, sort of a headliner overall-looking questions. How would you respond to some investors who would say you have an attractive multiple from the standpoint that it is lower EBIT to EBITDA compared to some of your peers? And when you're going and looking to get a foothold exploration-wise in some of these international regions, how would you respond to investors who feel that, that international exploration may not pay off in the end based on investors being so favorable towards resource plays in the U.S.? How would you respond to that in regards to Marathon's strategy, going forward, in international exploration?

Clarence P. Cazalot

Well, I would say, first of all, I don't think that the exploration we're conducting is at all hindering or limiting the amount of activity we can pursue in the resource plays that we believe generates profitable growth. What we do believe is that exploration in the areas we're looking, where we see very significant potential, has the potential to create significant value for us. And again, as we've seen and Marathon, indeed, has done in the past, you don't have to develop and produce those discoveries out for the next 30 or 40 years. Making the discovery, commercializing it, demonstrating the value gives you the opportunity to monetize at that point. So we see it really as not conflicting. We see it as complimentary. Ultimately, we are all about value creation, and we think that we create that value by running our base assets in a strong, safe way, generating profitable growth from our resource plays, and then complementing that with impact exploration success. So as we've said -- as I said earlier, allocating about 10% of our budget a year. It fluctuates a little bit. We think exploration makes very good sense and is a key part of our strategy.

Operator

The next question comes from Pavel Molchanov from Raymond James.

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

Similar actually to the question from the previous caller. As you -- given that you clearly have a pretty high tax rate that you're working to lower, as you look at these new frontier exploration plays, Kenya, Ethiopia, Gabon, how confident are you that the fiscal terms there will facilitate improving your overall tax structure?

Clarence P. Cazalot

Well, again, when it comes to exploration, our threshold decision isn't around tax. It starts really with the subsurface and, do we see the sort of geology and the potential belowground to make big finds? We then couple that, obviously, with all the aboveground risk, the risk of operating in that country and infrastructure requirements, but importantly, the fiscal terms. And so we look at the fiscal terms to make sure that the rewards, if we're successful, certainly offset the risk. And in many cases, as you look at production sharing contracts, the taxes for the most part are paid on your behalf. It's sort of rolled up into the PSC. We have some very high tax regimes in Norway and Libya that are sort of unique relative to new production sharing contracts that we enter into around the world. So the tax rate is not the big determinant there. It's really what we see, again, as our ability to create very significant value for the amount of dollars that we're exposing there. And as I said a moment ago, you don't have to produce this out over 40 years. You've got the opportunity with good success to monetize it upfront and capture the value that way.

Janet F. Clark

And I would just add that we look at all of our investments on an after-tax basis. And so even if there is a high tax rate, if the after-tax rate of return is attractive, then it makes sense to make that investment.

Clarence P. Cazalot

Right.

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

Okay. And just quickly, can you share the tax terms for either Kenya or Gabon?

Clarence P. Cazalot

No. Not at this time.

Operator

The next question comes from Ed Westlake from Crédit Suisse.

Edward Westlake - Crédit Suisse AG, Research Division

It's a follow-on. So I mean, just in follow-on to the previous question. I guess, you're going to continue a balanced approach. And one of the measures of success is going to be not just delivery in the Eagle Ford but also developing other shales in North America. And to that end, you've got this disposal program with quite a big chunk of assets. Is there any way you can give us some guidance as to how much might fall within 2012 and how much might fall into 2013 as you have those discussions at this point?

Clarence P. Cazalot

Ed, I think the only guidance we give is sort of around what we've already talked about. We've said in terms of Alaska that we now described as a $375-million asset sale that is still, as you know, going through necessary governmental approvals. We would expect that to close this year. As I said earlier, we are going to be reviewing shortly the bids on our 50% interest in the Neptune gas plant. And I think we feel strongly that will close this year. Beyond that, I don't want to speculate because we've not really talked about anything else that's on the asset sale list. I'll simply tell you that, again, we're confident in getting to the numbers, the range we've talked about before or potentially exceeding them by the end of next year. So we're pressing it.

Operator

The final question comes from Paul Cheng from Barclays.

Paul Y. Cheng - Barclays Capital, Research Division

A real quick one. Dave, on Page 19 of your presentation, you're very kind to provide the 24-hours day rate for some of the wells. Do you have an average 30-day IP for the second quarter?

David E. Roberts

No, Paul. We don't have anything like that, but -- no, we don't have -- we don't think about the business that way. I guess, I think what I would say is, consistent with meetings that I've been in, and Lance has just said this, we're very confident in the type curves that we've seen. And we'll provide updated information as we get it. We don't expect them to change materially. And that's the best thing -- way to think about an average, is the type of wells we're bringing on versus those type curves.

Operator

Gentlemen, that was last question. Please go ahead with any final remarks.

Howard J. Thill

All right, Christine, appreciate it. Thank you, everyone, for their interest in Marathon Oil. We hope to see you soon. If you have follow-up questions, please let Chris or myself know. Thank you, and have a great afternoon.

Operator

Thank you for participating in the Marathon Oil Corporation's Second Quarter 2012 Earnings Conference Call. This concludes the conference for today. You may all disconnect at this time.

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