馬拉松石油 (MRO) 2012 Q2 法說會逐字稿

Welcome to the Marathon Oil Corporation's second-quarter 2012 earnings conference call. My name is Christine and I will be your Operator for today's conference. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. 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.

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 related 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 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 US 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 to $76 million, driven by higher sales in Libya. While the domestic portion of that segment decreased to $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 have included a comparison of the total upstream second quarter versus 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 US 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 US E&P cost per BOE remained flat with the previous four quarters. Excluding exploration expenses, cost 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 cost and higher taxes related to the mix issue previously discussed.

Slide 11 compares the international E&P cost structure by category over the past six quarters. Compared to the first quarter of 2012, field level controllable cost, DD&A, and other cost 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 compare 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 BOED 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 cost 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 run 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, 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 would 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 will turn the call over to Clarence for some remarks.

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 three 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 are 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 US 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 six to two rigs. And we're reducing our Bakken rig count from eight to five 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 have also suspended drilling in the Niobrara and plan to frac one 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 have 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 will 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 will note in the press release that we have disclosed the potential purchase price in Alaska as being $375 million. And I would also tell that you that interest in the sale of our Neptune gas plant, our 50% interest there, has been quite strong, and we will 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 have seen yesterday, we farmed down two 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 have asked Lance Robertson to provide an update on our operations there.

Thanks, Clarence. Going to slide 19, you will see a map of the Eagle Ford and our acreage position, along with where we are currently drilling. Also on 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 towards high-value condensate and high GR 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 the 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 two 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 four 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 five new large, central delivery facilities that have been built in 2012. Shown in red are six more central facilities now under construction. Additionally, over 210 miles of four-, six- and eight-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 in control of operations is in progress today and the 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. Five density pilot projects are currently producing. Two are in progress, and three more remain in 2012. Four additional pilots targeting vertical lateral placement are currently producing.

We're excited about the progress we have made across the basin to date. We have a dedicated team. And while we have a lot of hard work ahead of us, we have seen great strides in operational capacity. We are 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 will turn the call back to Howard.

Thanks, Lance. Before we open the call to questions, I would like to remind you, and you know who you are, to limit yourself to two questions so that we might accommodate all people who want to ask questions. You may reprompt for additional questions as time permits. Christine, with that, we'd like to open it up for questions.

(Operator Instructions) Doug Leggate from Bank of America.

I appreciate the additional color and it's interesting, 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 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? 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. Thanks.

Doug, I would actually say that I think we have achieved what Dave suggested in the previous call. We are consistent. We delivered 16 to 20 wells per month to sales for the last four 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 have 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 in that first Eagle Ford slide. And we have 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 of us to make them even better.

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 two ago, you used to give a slide showing what the trajectory was in Norway in terms of production. If we take the mix change of that decline in Norway, along with the increase in the US, 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. Thanks.

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 will 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. I will then turn it to Janet about forecasting tax.

And, of course, Doug, we certainly hope that the production in Norway stays as high as possible for as long as possible, because it generates very good returns for us on an after-tax basis. But you are directionally correct. As the mix of pretax income shifts from high tax jurisdictions, such as Norway, to a lower tax jurisdiction, such as the US, our overall effective tax rate, excluding Libya, will continue to climb. (multiple speakers) prices and differentials, et cetera, I can't be more quantitative about that.

Sure. So just some clarity, Janet, the US tax will be zero tax? Is that a fair assumption at this point?

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

Terrific. Thanks very much.

Ed Westlake from Credit Suisse.

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

I would say the Davila wells are relatively new and are performing very strongly. I think our experience in that area, like you would expect with many, 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 essentially our acquisition model has been proven accurate at this point.

But it's fair to say that the results for that moment, I think it's a 2,000 -- just doing the math in my head -- a 2,024 IP. So, with the decline you see in the early part of the month, maybe what will change to get up to 1,650?

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 will have some wells below 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.

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 are dropping some rigs in the Bakken and the Woodford, which 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 low run rate of CapEx in the first half.

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 are saying is, we are reiterating what we said last quarter, the number is going to be circa $5 billion. We've seen pretty significant pressure from one 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 are seeing some cost pressures there. But obviously, we are 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 are cutting back the rigs in the two Northern unconventional basins. And it's a pure efficiency decline in South Texas.

Thanks very much.

Evan Calio from Morgan Stanley.

I'm a two-question guy. Keeping on the theme, in the Eagle Ford, maybe a question for Lance, if there's 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? I know at one point there had been discussed plans for an analyst meeting in the fall. Any update there, please?

I would say three of those infill pilot tests are producing -- a we said, two are in progress. Those are actually being stimulated now, this week and next week. And so our results are early. 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 have said before, the failure case would be if it didn't work we would know that very soon. I think we are 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 take longer of both pressure and rig 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.

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

No, Evan, we don't see that at this time. We needed to build out the infrastructure and we put an increased amount of capital to that to make sure that we had the capability to deliver our upstream business. So we are not contemplating any kind of special vehicles in order to really set value.

Got it. Appreciate it.

Scott Hanold, RBC Capital Markets.

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

Sure, Scott. We do expect some variability in that month to month. I think you are 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 was some low there. I think what you will see in future quarters is that we are materially up in July on account of that, as we brought on the large groups of well. Upped the well count, I would say. I think what we expect forward is some variability, but we are going to continue to dampen that by managing inventory appropriately.

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

We do believe we are going to be in that range from 241 to 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 have become so efficient that we are just going to capture all the wells we need and finish that development with two fewer rigs than we anticipated some months ago.

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

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 will be able to hit the exit rates we talked in the release and maintain flat production with the two rigs in Oklahoma and the five in North Dakota.

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

We are 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 two Northern basins, and we will try to reap those benefits, as well, over time.

Guy Baber from Simmons & Company.

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? Are you operating right now at levels that you are satisfied with? And if you could provide more specifics on any efficiency improvements you are driving in the Bakken and Woodford, that would be helpful, as well. Thanks.

Guy, referring to Eagle Ford, I think we are really happy with how quickly we have been able to reduce those cycle times. We are managing both the drilling, as well as the moving of the rig as active as we can to drive. We do not think we are leveling out, to the extent we're not going to continue to improve. We have 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 are in the process of as we speak, then we expect to be able to move to more and more large pads and we will drive that time down further. I think we hope to be able to talk about that in future quarters.

Yes, and just to amplify what's going on in the Bakken, just talking about year-on-year quarters, we have seen almost a 30% decrease in our times. And we have seen that really in two areas. We have been consistently good in our spud-to-TD times, although we have taken about 10% there. But we have halved our moving rates and we have taken about 10% off of our completion rates, as well, to get to the levels that we are looking at. And in Oklahoma, at this point, and with the limited number of wells we have 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.

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 term, but obviously you guys have been very active recently in acquiring some new frontier acreage. And we had previously been assuming that you were de-emphasizing 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. Thanks.

Dave, I will take that. This is Clarence. Our strategy has fundamentally not changed. We have 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 have done this quarter is wholly consistent with that.

Thank you.

Blake Fernandez from Howard Weil.

While we are 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?

Yes, it is Blake.

Okay, thanks. 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 like now on that piped crude. And how that compares maybe to the $88 a barrel realization that you've got for the entire US portfolio.

Blake, that's a unique question. We sell to multiple contracts in that because we have a variety of gravities. I would say, we have focused very hard the first two 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 are very happy to have that pricing, because you guys are aware those differentials are moving a lot in that regard. The majority of our oil sales are at 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.

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

Correct.

Thank you.

Paul Cheng from Barclays.

Two quick ones. First, just for the modeling, for Droshky in Ozona, what is the second-quarter average? And should we assume that now it's pretty much zero?

No, Paul. Let me get to my sheets here real quick while I'm looking at it. The second quarter 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 on both of them.

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

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

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

Yes, we do. In the NGLs, we do have a very heavy NGL mix. And those price realizations are very strong, and all selling to the [Mount Bellevue] market. However, as you have seen, there's been pressure on that basket of pricing over the recent 90 days.

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

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

Paul Sankey from Deutsche Bank.

I will more than respect your one question or two question limit, with just one question. And I think you have answered it. 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. Thanks.

Yes, I think, Paul, again, it's wholly consistent with what we have said around capital discipline and focusing on value, rather than volume. And you are spot on. We could continue to maintain higher rig levels, and grow the volumes at a faster rate. But in the face, as we have said, of lower commodity prices, both crude and NGL, and continued high cost, 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.

Perfect. Thanks.

John Malone from Global Hunter Securities.

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

John, this is Dave. I think the critical issues is we 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 of 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.

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

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

And then another question. 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?

I think it's both. These unconventional plays all share similar characteristics. Because we are drilling horizontal wells, and putting fairly 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 have not found the right mix of costs and completion versus the type of wells that we're actually able to deliver in the GJ 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 are looking at that program, or do something else altogether.

Elliott Javanmardi of Capital One.

Just a question on the Oil Sands Mining pricing realizations that we are seeing. I'm seeing a downward trend over the past three quarters. I 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.

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 looked at as a syncrude basket because of what we have in terms of our upgrading capability there. And it's comparing very favorably, again, to WTI. And our expectation is that that relationship is going to be maintained.

Okay. Thank you for that color. And finally, last question, a headliner overall-looking question. How would you respond to some investors who would say you haven't attracted multiples from the standpoint that it is lower EBIT to EBITDA compared to some of your peers? And when you are 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 US? How would you respond to that in regards to Marathon's strategy going forward in international exploration?

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 are looking, where we see very significant potential, has the potential to create significant value for us. And, again, as we have 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 what we see, it really is not conflicting. We see it as complementary. 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 I said earlier, allocating about 10% of our budget a year -- it fluctuates a little bit -- we think, to exploration, makes very good sense and is a key part of our strategy.

Excellent. Thank you for that.

Pavel Molchanov from Raymond James.

Similar actually to the question from a previous caller. Given that you clearly have a pretty high tax rate, that you are 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?

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 below ground to make big finds. We then couple that, obviously, with all the above ground 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 are 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 unique relative to new production sharing contracts 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 are 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.

And I would just add that we look at all of our investments on an after-tax basis. 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.

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

No, not at this time.

Ed Westlake from Credit Suisse.

Just a follow on to the previous question. 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?

Ed, I think the only guidance we'd give is around what we have already talked about. We have 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 have 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 have talked about before, or potentially exceeding them, by the end of next year. So we're pressing it.

Thanks.

Paul Cheng from Barclays.

A real quick one. Dave, on page 19 of your presentation, you are 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?

No, Paul. We don't have anything like that. No. We don't think about business that way.

I see. Okay.

I think what I would say is, consistent with meetings that I have been in, and Lance has just said this, we are very confident in the type curves that we have seen. And we'll provide updated information as we get it. We don't expect them to change materially. And that's the best way to think about an average, is the type of wells we are bringing on versus those type curves.

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

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

Thank you for participating in the Marathon Oil Corporation second-quarter 2012 earnings conference call. This concludes the conference for today. You may all disconnect at this time.