馬拉松石油 (MRO) 2012 Q3 法說會逐字稿

Welcome to Marathon Oil Corporation's third quarter 2012 earnings webcast and conference call. The synchronized slides that accompany this call can be found on our website at Marathonoil.com. On the call today are Clarence Cazalot, Chairman, President, and CEO, Janet Clark, Executive Vice President and CFO, and Dave Roberts, Executive Vice President and COO.

Slide 2 contains a discussion of forward looking statements and other information included in this presentation. Our remarks and answers to questions today will contain forward looking statements subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied by such statements. In accordance with Safe Harbor 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 to adjusted net income for the first three quarters of 2012, as well as preliminary balance sheet and cash flow information.

As described in our press release, we had a very good quarter operationally and financially, and as you see on slide 3, our third quarter 2012 adjusted net income increased 9% from the second quarter of 2012. As shown on slide 4, the third quarter saw improvements across all three segments. And as shown on slide 5, this earnings improvement was largely driven by an increase in liquid hydrocarbon sales of 26,000 barrels a day in the third quarter over the second quarter, both excluding Libya. The US, Canada, EG and Norway sales volumes were higher in the third quarter, largely as a result of growth in the US resource plays and the resumption of production after second quarter turnarounds internationally, offset by lower UK sales volumes as a result of planned turnarounds. In the appendix of this presentation, you will find a similar slide comparing actual third quarter to estimated fourth quarter sales volumes to help you model the Company's fourth quarter.

As shown on slide 6, the third quarter was another outstanding operating quarter for the E&P segment as reflected by a 17% increase in segment income. This increase was primarily a result of higher liquid hydrocarbon and natural gas sales volumes, partially offset by higher operating costs in DD&A associated with those additional volumes. Moving to slide 7, our US E&P earnings increased 57% in the third quarter versus the second quarter, largely a result of the performance of our resource plays driving higher liquid hydrocarbon and natural gas sales volumes. This was partially offset by higher operating cost and DD&A associated with the increased volume.

As shown on slide 8, total US E&P costs per BOE declined quarter over quarter. This was primarily as a result of lower expiration expenses and operating cost. Excluding the expiration expenses, costs per BOE in the US were down $0.34 quarter over quarter. Slide 9 graphically demonstrates the lower 48 on-shore production growth we have realized over the past several quarters with the production increase from second to third quarter of approximately 25%. We now expect to reach between 145,000 and 160,000 BOED in the fourth quarter 2012, 25,000 to 30,000 BOED higher than we previously estimated. This increase is the result of both better operational performance, particularly in the resource plays, and the previously announced Eagle Ford bolt-on-acquisitions. From the third quarter 2011 through the fourth quarter of this year, we expect an increase of over 93%. Importantly, oil volumes are expected to increase to 61% and NGLs to 11% of these production volumes.

Slide 10 shows the impact on international E&P earnings from the higher international liquid hydrocarbon and natural gas sales volumes, lower DD&A and other, plus higher price realizations. The third quarter saw continued solid performance from our international assets, and the execution of a gas sales agreement in Libya which resulted in additional international gas sales volumes of approximately 23 MMCFD. Slide 11 shows the international E&P cost structure per BOE by category over the past seven quarters. Compared to the second quarter of 2012, DD&A and other costs decreased in the third quarter, partially offset by an increase in field-level controllable cost and expiration expenses.

As shown on slide 12, quarter over quarter, our E&P segment production available for sale was 16% higher while sales volumes increased approximately 12%. Increased production available for sale from the continued ramp up in our US resource plays in the previously mentioned sales agreement in Libya were partially offset by decreased volumes in the UK as a result of planned turnarounds. Excluding the impact of the Libya gas sales agreement, there was a 1.2 million BOE overlift in the third quarter, which means the cumulative underlift at the end of the third quarter was approximately 4.6 million BOE.

Approximately 2 million BOE underlift in Libya, 1.9 million BOE in Alaska gas storage and an underlift position of 700,000 BOE in Europe, along with an overlift of approximately 100,000 BOE in EG. The Libya gas sales agreement created an additional 2.6 million BOE underlift, bringing the total underlift at the end of the third quarter to 7.2 million BOE. Slide 13 shows the approximately 24% growth in our E&P production available for sale, excluding Libya since the beginning of 2010. Slide 14 shows our oil sands mining segment income increased $14 million sequentially. This was as a result of higher synthetic crude oil sales volumes and better price realizations, partially offset by higher DD&A, operating costs and other items. Net synthetic crude oil sales increased 20% from 44,000 barrels per day in the second quarter to 53,000 barrels per day in the third quarter.

On slide 15, integrated gas segment income increased $26 million quarter over quarter to $39 million in the third quarter, primarily a result of higher L&G sales volumes and lower cost in the third quarter compared to the second quarter, which included turnaround costs. Lower methanol sales partially offset the higher L&G income. Slide 16 provides an analysis of year-to-date cash flows. Operating cash flow before changes in working capital was $3.3 billion, while working capital changes resulted in a $496 million use of cash. Cash capital expenditures year to date have been $3.5 billion with proceeds from dispositions totaling $193 million. While we had $806 million of outlays on acquisitions and paid dividends of $360 million. Net debt has increased $1.7 billion year to date, and the quarter-end cash balance was $671 million.

As shown on slide 17, at the end of the third quarter, 2012, our cash adjusted debt-to-total capital ratio was 25%. The corporate effective tax rate during the third quarter, excluding Libya, was 65%. Slide 18 summarizes derivative positions we entered into during the third quarter which relate to a portion of our forecast E&P crude oil sales. The terms of these positions are from October, 2012 through December, 2013. An unrealized pretax gain of $45 million, $29 million after tax, was recognized on these derivatives in the third quarter and excluded from segment income. I'd like to remind you that the appendix has a significant amount of forward-looking data for use in modeling the Company's fourth quarter and full-year results. We'll now move to slide 19, and I'll turn the call over to Clarence and Dave for some additional remarks.

Thank you, Howard. As you've just seen, we had an outstanding third quarter, both operationally and financially. And importantly, we have a great deal of momentum to continue performing at a high level. In just a moment, Dave Roberts is going to provide some detail on our key resource plays and enhanced exploration program that will clearly illustrate why we're excited about Marathon's future. But I want to first summarize the key messages I hope you'll take away from today's presentation.

Very importantly, I would expect that Marathon's ability to execute in our resource plays in terms of pace, performance, and bottom line results has been clearly demonstrated, and we will continue to target increasingly higher levels of performance versus our peers. We've built strong operated positions in three of the highest value resource plays in the world, and as Dave will show you, we have a much larger resource base and drilling inventory than was previously communicated. With such a deep, high-quality inventory, we will scale our growth to optimize value based on the commodity price and cost environment we see. We built an exploration portfolio with significant resource potential at lower risk in what we believe to be some of the most prospective basins in the world. And lastly, while much about Marathon has changed, what hasn't is our commitment to financial discipline, a strong balance sheet, and creating and delivering value for our shareholders. Let me now turn it to Dave for the proof points behind these key messages.

Thanks, Clarence. I just want to use slide 20 to highlight the first of Clarence's points, our building credibility and our ability to execute in US resource plays. We have outstanding acreage positions in each of our three key plays and are delivering on our promises. Currently producing approximately 60,000 barrels of oil equivalent per day net in the Eagle Ford and raising our target next year by more than 20% to 85,000 barrels of oil equivalent per day. In the Bakken, we're producing over 30,000 barrels of oil equivalent per day and raising next year's target to over 33,000 barrels of oil equivalent per day with only five rigs in our program. And at quarter's end, we were producing just over 12,000 barrels of oil equivalent a day in the Anadarko Woodford with the expectation that we can maintain this rate in the medium term with the two rigs we feature in this program.

Turning to slide 21, given the demonstrated growth performance we are seeing in our domestic unconventional businesses and the continued strong performance of our base assets, we have increased our 2012 production targets and are affirming a 6% to 8% growth rate for 2013. We are now confident that our previously promised 5% to 7% growth rate can extend to at least 2017. Our production and growth will continue to be liquids weighted while we retain further upside to US natural gas price recovery in the future.

Turning to slide 22, Howard has already discussed the dramatic production increases experienced in our lower 48 on-shore business, with growth rates expected of over 90% from last year's light quarter through year end 2012. Nowhere is this powerful growth story better illustrated than in our Eagle Ford business. Many questioned our ability to meet the operational challenges of the Eagle Ford, but our business has hit its stride running 18 drilling rigs and four fulltime frac crews and two more on a spot basis with fully competitive cycle time metrics, allowing us to triple the number of well completions per quarter from Q1 and to have dramatically increased production in each of the last two quarters.

While we believe we've taken great strides in answering the key proof point around operational excellence for our US resource business, I'd like to move to slide 23 in the proof point to another key question, was the Eagle Ford acreage as prospective as we thought when we entered the core of the play almost a year ago? These graphs offer some insights into our view that we are indeed in some of the best real estate in North America, if not the world, today. We are providing our detail well performance versus type curves, along with tabular data updating our expectations for wells in each play type for the two-phased regimes we are primarily targeting in our Eagle Ford programs. In short, our wells are performing as expected, and with down spacing anticipated, this is a field that will continue to grow and I believe outperform for our Company. And on slide 24, we highlight our best well test to date in the play.

As you know, we generally tend to be conservative with our flow-back procedures, and normally turn wells to sales on 14/64th inch to 16/64th inch choke sizes after test rates at lower chokes. We follow this procedure to avoid damaging our completions and to address any concerns with stress dependent permeability degradation. In the case of the Borough 2H well highlighted here, we were confident an aggressive test would not cause any long-term recovery issues, and we wanted to demonstrate the quality of our assets in a headline fashion. With what some might call a monster well, the Borough 2H tested for 24 hours on an approximately 0.5 inch choke at 6,275 barrels of oil equivalent per day with an oil condensate rate of over 4,600 barrels per day, and an NGL rate of almost 800 barrels per day. This is 100% Marathon working interest well, and we expect to test at least four other wells on larger than normal choke sizes in Q4 with oil rates expected in the 2,000 to 4,000 barrel-per-day range. I will say, however, that our practice will continue to be to get stabilized tests at moderate choke ranges with a focus on ultimate recovery as our guide.

Slide 25 addresses perhaps the most exciting opportunity in our entire unconventional resource base, increased well density to increase overall resource capture. Even with state-of-the-art completion activities, most unconventional reservoirs offer ultimate recoveries of less than 10% of oil in place, inviting the opportunity for down spacing to access untapped resources at closer and closer spacing. Shown here are the down spacing pilots we are engaged in across our Eagle Ford acreage position. We expect to complete all of these spacing pilots by early next year and to have our technical results in hand by mid- year 2013. We remain confident that the majority of our acreage will be developed on 80-acre spacing units with a significant amount of our positions developed on 60-acre and even 40-acre spacing units.

Slide 26 indicates what increased density drives into our business in terms of increased resource and increased well counts. At maximum density, we have a 40-year well rate life in this play with the potential to access well over 1 billion barrels of oil and natural gas. As we said when we made the Hill Corp. acquisition, the Eagle Ford is a company maker. Slide 27 illustrates how 1,500 miles north of the Eagle Ford, our Bakken business continues to deliver promise to the upside. Our view of the production potential of the asset has changed dramatically in the past five years while we have remained among the best in the basin in terms of drilling performance and cost control. Our step change to industry standard completion practices in the basin continues to yield positive results for growth with our net peak rate projections now reaching 50,000 barrels of oil equivalent per day for this asset.

And as we continue to focus on down spacing and Three Forks development in the Bakken, we can show, as slide 28 indicates, again, a 40-year well rate life at 320-acre spacing, which is still not as aggressive as many of our competitors in the basin believe may be possible. Marathon's current estimated recoverable resource has more than doubled in the past two years to nearly 500 million barrels of oil equivalent, and the Bakken promises to stand alongside the Eagle Ford as a major oil production for Marathon well into the future.

You know, the general view in our industry today is that if you miss the Bakken and the Eagle Ford, you miss the unconventional liquids wave in this country. At Marathon, we think you have to add the Oklahoma resource basins to that mix. Slide 29 shows our acreage position in the Anadarko Woodford play at 160,000 net acres together with an additional 100,000 net acres of exposure to well-known oil and gas-producing pays like the Mississippi lime and the granite wash. Though stacked in some areas, we believe we have a nearly billion-barrel resource play covering over a quarter of a million net acres. As slide 30 suggests, while ultimate development and spacing will be determined with further testing and certainly, this is an area that is more dependent on natural gas and natural gas liquids pricing recovery, again, we have a play with a 30-year well rate life in the heart of our US portfolio.

Turning to slide 31, while it's still early days in the Oklahoma resource basins, and you'll recall we cut our rig count to two in Oklahoma in response to commodity price pressure, we believe with reasonable price expectations we can expect to ramp up rig activity around the middle of the decade and to achieve a 25% annual compound growth by 2017. In short, we have exposure to three of the most valuable, most growth-oriented and longest running room plays in the United States today.

Turning to slide 32, I'd like to highlight the significant, yet very quiet repositioning we have undertaken in our exploration business. We're still focused on spending roughly $500 million per year on impact opportunities to create drill bit-led value or roughly 10% of our going concern CapEx, a substantial amount by any measure. At the same time, we've increased the number of play types and well opportunities we will see in a given calendar year. Our current mix is driven toward proven hydrocarbon basins, large running room potential, and a liquids bias. As you can see from the chart, we have access to some of the most exciting basins in the world today with scale.

Perhaps the most exciting aspects of our program is that as we have remade the business, our opportunity set didn't go into the next five-year plan. In fact, as we show on slide 34, we have up to 15 impact prospects that may be drilled in the next 15 months. Our exploration business is challenging our unconventional business as to which is the most real-time results oriented. So all in, we are poised as a Company to continue to demonstrate what we've promised, solid base assets operated at extraordinary reliability for production and financial performance, real growth oriented to liquids and assets we own and control, and exciting near-term exploration options to add to our overall growth or recognize in our overall value creation from the business.

I will use slide 34 to reinforce the messages that Clarence opened with earlier. In our business, execution is everything, from reliability in all our global assets to the daily delivery in our intense resource play activities. Importantly, our continued strength and operational excellence is now matched with a robust portfolio of opportunities, highlighted by a decade-deep suite of assets and three key lower 48 resource plays representing the potential for thousands of wells and over 2.5 billion barrels of resource.

Together with our base businesses, we have the opportunity to continue to grow our business at a projected 5% to 7% CAGR through 2017. And while volume growth is important, we will continue to manage the business for value-driven growth with a strong focus on returns and cash generation. To that point, an exciting breadth of near-term exploration opportunities gives us the chance to add impact value to our portfolio through development into new growth or other actions. This is without a doubt a great time to be at Marathon Oil Corporation. With that, I'll turn the call back to Howard.

Thanks, Dave. Before we open it up to questions, I'd like to remind you that so we can accommodate all the questions today, even though we've scheduled this call for a little bit longer than normal, that you limit yourself to two questions along with any clarifications to those questions. And with that, Dawn, I will turn it over to you so we can prompt for questions.

Thank you.

(Operator Instructions)

Our first question comes from Doug Leggate from Bank of America Merrill Lynch. Please go ahead.

Thanks. Good afternoon, everybody, and I appreciate all the information in the slide deck, that's really helpful. I'm going to take my full quota of two questions, I guess they're going to both be for Dave. But Dave, looking at the changes in the indicated rates for the wells, it looks like the condensate rate, the 30-day average has come down a little bit, the high GUR rate has gone up a little bit. But then when we look at the 60-day rate, it looks like they're holding up a little better, particularly on the condensate. I'm wondering if you can talk a little bit about what has changed there in terms of your choke management. And specific to that, this morning the EOG had their results, and they made a point to say that, you know what, it doesn't really matter, and they've gone for the more aggressive chokes. I wonder if you could address that and then I'll take a followup, please.

Yes, thanks, Doug. Thanks for the questions. It's been pretty interesting reading all the comments about choke management. One wouldn't think we'd spent that much time talking about it. But I think I would point out on the charts is we've given you actual well results.

And so previously, the type curves represented what we expected in the play, and we've been pretty clear that they were based on essentially running these wells at 16 chokes across the play type. And our practice is pretty straightforward. We bring wells on at 12, at 24 hours we flip them, or once they settle in, we flip them to 13, and then we go to 14. And generally we put our wells down the sales line at 14 or less. And so what we're trying to show here is the fact that our wells are holding up on a more predicted basis. We're giving you actual details of how we're actually running these wells, and I think importantly, the most important line on that chart is the EUR number. That number has been -- is consistent from what we said, and that's what we're saying, that these wells are performing exactly as we had anticipated.

You asked a second point. I think, we said from the beginning in this play, we're very interested in what our competitors are doing, and I think we've reacted very well to the range of competitors that we have in the Eagle Ford to make sure that we're engaged in best practice. And no reason to doubt what some of these competitors say about managing chokes down or managing chokes up. What I would say is we're going to continue to be focused on ultimate recovery in our wells. We think it's very early days in what we're trying to do in terms of understanding all the reservoir physics. But I think as importantly for us is just facilities optimization because there's no reason to build out facilities for a maximum rate when ultimately these -- we're going to be managing declines over time. And so having a discipline around the CapEx and building out facilities to meet expectations in the wells, as long as you get your EURs right, you're doing the best for your shareholders, and that's what we'd say about choke management.

Thanks, Dave, for that. My followup is kind of a related question. Obviously you've given as the Borough as well, I think you talked about a 0.5 inch choke. But what I'm really trying to understand is, as we look at your projections going forward, which you've obviously taken up for next year, what are your assumptions and what are the chances that you ultimately end up getting a little bit more aggressive in the way you flow these things? And if I could layer into that, you used to talk about 16 to 20 completions per quarter. Just help us understand what's underlying that increase in target for next year between the choke and the number of wells. I'll leave it there. Thanks.

Well, again, I think the choke issues are really going to be around how we build out our facilities and making sure that our facility match up with our production. I will tell you we are experimenting with moving more to a 16 to 18 range in the early days of choke sizes. But I wouldn't get too carried away with that. I think the key issue for us, the two things that are going to drive our performance, have driven them this year and are going to drive them into the future, is what we talked about in the opening, is our ability really to blow past adding this concept of adding at least 60 wells a quarter. We spud and TD'd 79 wells in the Eagle Ford last quarter, and that's the basis of our performance. We're basically in a view now where we're adding completions at a 65-well to 70-well per-quarter rate.

We still built an inventory of wells waiting to be completed of -- in the Circa 25 area. What we're looking at here is over the course of a year, we have driven down our cycle times sud to spud to 25, which we think is competitive with the areas that we play in the basin. And as importantly, we've driven our well costs down in the last month or so into this $8.6 million per well range that we had prognosed when we first got into this play. That's with bigger fracs, longer laterals, and we're still beating our cycle time expectation. The answer in terms of what we're doing in terms of driving production performance this year and into next year is all about execution. We have become as good as anybody in this basin in 12 short months, and we expect to be able to continue that performance into the out years.

Great. Thank you for the answers, Dave. I appreciate it.

Thank you. Our next question comes from Scott Hanold from RBC Capital Markets. Please go ahead.

Thanks. Good afternoon. I think you covered a lot of the performance in the Eagle Ford pretty thoroughly here, and just one question stepping back and looking at your obviously updated targets in both the Eagle Ford as well as the Wilson Basin. Is there anything from an infrastructure perspective, especially in the Eagle Ford, that could cause some lumpiness? And what does your capacity through the year look like and into, say, '14?

Well, I think the macro logistics, particularly in south Texas, are in pretty good shape. I -- my view is you've seen most of the lumpiness from us in rally the second quarter this year when our operating capacity on the drilling completion site got ahead of our infield infrastructure and construction capability. I think the rise that we've seen in the third quarter and continuing into the fourth is we're matched up very well now in terms of our construction capacity, in terms of building out infield infrastructure. And we're pretty much on top of getting the connections to the macro outlets. I think we had a two or three-day delay on one in the third quarter of this year. So, right now, we're hitting it on all cylinders and so that's the reason we've been able to increase our expectations for next year.

Okay, okay. Thanks for that. And stepping back and looking at the other area of the Oklahoma resource base opportunities that you all identified in. As you look forward in determining whether or not capital needs to go there, especially from the liquid areas like the Tonkawa, Cleveland, Marmaton, and even the Mississippi, how do you think about spending money there versus some of the international opportunities that you've acquired here the last 6 to 12 months?

Well, yes, great question, Scott. I think what we would say is that our international opportunities are largely exploration, and they're going to fit pretty comfortably within this $500 million a year that we have prognosed as we move forward. For instance, the real shift we've gotten into is probably lower working interests for more targets, which allows us to fit our CapEx around those opportunities. The real question about Oklahoma is going to be when price recovers relative to the commodity mix that we have there, then we'll have some choices about where we shift our capital largely in the United States. But right now we're pretty comfortable that we can wait on this. So, we think we're going to see recoveries, as we mentioned, in the middle this decade, 2015 or so, and then that will be queued up for us to really move after it in an aggressive fashion, and we'll probably have some headroom in our capital programs at that particular time.

In the -- a follow on to that, when you look at the Oklahoma resource opportunities there, are some of the shallower ones a little bit more oil prone, or are you not quite seeing that covering your acreage position?

Well, I think that's the general industry perception is that, for instance, the granite wash and the Mississippi are going to be a little bit more oil prone. We're going to do some work next year within the program that we already have to take a hard look at that, and that will inform our opinions as we go forward. We've got work to do there, but I think you're going-in assumptions is generally correct.

Okay, understood. Thanks.

Thank you. Our next question comes from Guy Baber from Simmons &Company. Please go ahead.

Thanks, guys, and especially thanks for all the helpful disclosure you guys had this quarter. I had a question on the Eagle Ford, but it was the only US basin within the presentation in which you didn't give new long-term production forecasts. Any reason behind that? Are you still comfortable with us thinking about that as 120,000 barrel-a-day-plus basin, by the 2016 timeframe or so? Just any color you can provide on the long-term ramp up there would be appreciated.

Yes, it's a great question, Guy, and it's a topic of a lot of discussion around here. There is no question in our mind that this oil field shakes out into getting to those 120,000, 125,000 barrel-a-day ranges that we talked about. I think what we're really focusing in on now is now that we've got our capability in hand and really have demonstrated externally, we're going to take a hard look at what the ultimate peak rate and plateau should be for this field in that range. I think there's a lot of expectations, we just blow past the 120,000. But I think what we're going to look at is what's the best value optimization pathway for us in terms of how the overall facilities work, how we get into our overall operating rhythm on a go-forward basis. We still think -- and I think this field's been demonstrated, it will do pretty much whatever we want it to do in terms of delivering the volumes that we've suggested. We're going to take a hard look at what's the way to make the most money out here.

Okay, great, and then my follow up is, in the Eagle Ford, it looked as if your crude oil volumes as a percentage of your total production fell to a lower level this quarter than it has been recently. I think it was below 65% or so from around 75% before. Just wondering if you could comment on that trend. Is that just reflective of higher activity in the condensate window, or is that a trend that we should expect to continue based upon what you're seeing in areas where you've stepped up activity? Just any comments there would be helpful.

Yes, as we kind of pointed out when we first got into this thing, we spent a great deal of time in the first two quarters of the year really focusing on the oil-prone areas, and a lot of that was just taking care of our lease position. As we've moved south into the higher energy areas, more gas, you're exactly right. We're basically seeing a 65% oil take and 17% NGL plus/minus on our current production. That's something else that we're really focusing in on making sure we optimize around. I don't think that it's going to degrade too much further from that because we're really going to focus, particularly in the commodity window we're moving into, to make sure that we maximize the oil revenues that we have an opportunity to take out of here. We'll continue to watch it, but now we have some flexibility in where we actually drill our wells, and we'll be able to probably stay in that neighborhood at least.

Okay, great, thanks.

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

Good afternoon, it's Feisel from Citi.

Hi.

Hi. On the -- in a press release you guys put out not long ago I think on October 24, you talked about how you guys are engaged in discussions with the potential of a sale of a portion of your interest in AOSP. Can you give us an update on that and give us an idea of what you would do with the proceeds from that asset sale, if it was consummated?

Yes Faisel, this is Clarence. And really, there's nothing to update at this point. I think as we've said, we've engaged in discussions with respect to a sale of a portion of our interest and really at this point in time, there's nothing to say. If and when we have a definitive agreement, certainly we'd be prepared to talk more about that at that time, particularly as to what we would do with the proceeds.

Okay, understood. And on this Borough's 2H well, what's the 30-day flowing rate? I think I missed that number. I don't know if you gave that number out or not.

We didn't give that. I don't think we've got the 30 days quite yet, Faisel.

Okay, got you. I'll get back in queue. Thanks.

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

Hi, good afternoon, everyone. Clarence, a bit more of a high-level question, given we've had a lot of detail -- very helpful detail on -- mostly on the US. I was just wondering, given the success that you've demonstrated by focusing back into the US or attacking the new opportunity in the US on shore, and I guess less spending internationally, how are you thinking about your spending going forward in terms of how you balance between perhaps accelerating your spending in the US and the extent to which you want to continue if you like the more legacy exploration program? That's the thrust of what I'm asking, thanks.

Yes, I think, Paul, I would say that it's our intent to remain a global company. You will not see us pull back our horns and become a purely US or North America company. And so today as we look at the international arena, the best opportunities we see are in exploration, as evidenced by the enhanced program and opportunity set Dave talked about earlier. I think in terms of accelerating the pace of our resource play pursuits as we indicated earlier, having the opportunity set we've now developed gives us the optionality around doing just that. But as I said in my comments, we'll do that depending upon the commodity price environment and cost environment that we see. And so I think we certainly, as Dave has indicated, will focus on value optimization. And value optimization today in the resource plays really means staying away from natural gas, decreasing to the extent possible our exposure to NGLs until we see that market come back, and instead focusing on the liquids, on crude oil and condensate. And perhaps that could have some impact on slightly lower rates, slightly lower volume. But again, as we've said, it really is about value optimization. You'll continue to see us seek the best opportunities for growth on a global basis, and I'd simply go back to the earlier part of the decade in the 2001/2002 timeframe where people had a view we were leaving the US to invest solely internationally. We built some tremendous legacy assets internationally that are big providers of our cash today, but we didn't abandon the US. Unfortunately we didn't, because we're back again now investing very significantly there. And of course, as Dave talks about, for example, some of the Oklahoma basins, a lot of that is legacy acreage that we've had for some time. We simply want to position ourselves in places where we know there's a great deal of resource and then we can turn our people, our capital, and our technology loose on creating value from that.

Yes, I understand. And then my followup is a double followup. It's related -- does this mean given that you've essentially upgraded your volume outlook, at least relatively near-term, that we shouldn't think about an attendant upgrade in CapEx? And secondly, I was wondering once the current disposal program is completed, would you -- would what you just said indicate that would be the end of that program, or would you be looking to reload for a second round of focus, if you like? Thanks, I'll leave it there.

Yes. I think in terms of the capital programs, Paul, still consistent with what we've talked about before, I think we've got some illustrations in our presentations that if you look at it, it's between $5 billion to $5.5 billion of CapEx per year. And with respect to future asset sales, I would simply ask you to look back at what we have done historically. And we've had an almost continuous program, if you will, of reviewing our portfolio, looking at how we can best optimize the value of that portfolio. And in many cases, it results in dispositions and then reinvestment of that into what we would see as more profitable growth. The bottom line is, we continue to review our asset base, and I would expect that you'll continue to see an asset sale program from us on an ongoing basis.

Thanks very much.

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

Hey, good afternoon, guys. And again, also thanks for all the data today. My first question, it's something of a followup on the last question, and I know it's early stage and the potential stake sale for AOSP. Can you discuss the driver for considering that sale? Is it more than high grading the portfolio here as you get larger and maybe some statement on the value of your shares, or an emerging and better investment opportunity to elsewhere? Is there more to read into that?

I would say, Evan, it's -- I don't want to speculate simply because, as I've said, we have not reached a decision. But I think as you think about the AOSP project, I would simply say what we've said all along, and we believe it is a world-class asset. It is a tremendous resource base with the opportunity to grow it well into the future. And technology is going to allow us to do that cheaper, in a more environmentally sustainable fashion. But again, at the same time, it is a large, nonoperated asset. It is, perhaps to your point, an asset we don't think the value of which is fully reflected in our stock price. As we look at that, is there an opportunity perhaps to capture value and either reinvest that in profitable growth, to strengthen our balance sheet, or return some cash to our shareholders? All of those are considerations as we look at that asset and other assets that we have on a continuous basis.

Yes, that's helpful. Maybe have a followup on the Eagle Ford. Just to confirm, 85,000 BOEs a day is net full-year guidance. And also on the downspacing potential, I know you've been testing that throughout the year, yet in highlighting that potential today, should we presume that you are encouraged by results which aren't necessarily early, but maybe not fully ripe for disclosure yet?

Yes Evan, I will confirm the 85,000, and trust me, we've thought long and hard about that because that's another big step up for us. But that's what we're going to do next year. And on the down spacing, as you know, we're a technically driven company. We're going to wait for the analysis, but I will tell you, we're -- I'm confident, as I said, that this thing is going to be downspaced. In certain areas you're going to see some pretty close wells.

That's great. Good call, guys.

Thank you.

(Operator Instructions)

Our next question comes from Paul Cheng from Barclays. Please go ahead.

Hey, guys. Good afternoon. Dave, can you just confirm for me whether you are already out from the HBP into oil pad drilling at this point?

No, Paul. We're -- I think we're consistently saying we're probably in the range of 75% through with that next year, probably by mid-year we'll be in the mode of being -- have all our HBP behind us in the Eagle Ford.

And wanted to ask that one of your competitors have indicate when they move from the HBP into the pad drilling, for several months initially, that have a -- probably where we saw a temporary delay in the rail completion and as a result, that production will become more back end loaded or [fracked] during that transition period. Should we assume that as you move out from the HBP into the pad drilling by middle of next year, that this could potentially have some temporary effect on your production?

Well, Paul, I think the issue is how many of your completions in a given quarter are tied up in a pad. Because your point is that you could have unevenness as you had to complete several wells before you could bring them on. I think what I would say against a well stock of -- in any given year of 250-plus wells a year that you're probably going to see some of those effects, but it's not going to be something where it's going to be problematic.

So, you do not expect it's going to have any meaningful impact to you?

Well, let's -- we can talk about meaningful off line if you want, Paul, but I think there is going to be some unevenness, but I don't think it's going to be something where you're going to see a quarter be washed out because we're engaged in pad drilling.

Okay, a final one. Can you remind how many weeks that you're going to run in 2013, and what is the number of crews?

Yes, right now, we're still focused on keeping 18 rigs running in the Eagle Ford. We -- our view is that we will keep our four dedicated crews. The two, quote-unquote spot crews that we're running. In addition to that, we'll run through at least the end of the year, and I would expect that at least one of those crews will feature heavily into 2013.

Thank you.

Thank you. Our next question comes from John Malone from Global Hunter Securities. Please go ahead.

Hi, good afternoon. A broad question on adding rigs. I think you mentioned, if I heard correctly, that you might be doing that later -- maybe later in mid-decade. What would it take to add rigs to bigger resource plays in the near term?

Well, John, it's a great question. I think the issue for us, as we said, is we want to live within our means as best as possible. And one of the things that we've already seen this year is we're gaining efficiency, and so we're spending a lot of capital to do what it is we need to do. And I think that the issue for us is we're going to continue to try to balance the business on making sure that we can pay our own way as much as possible in the programs we're in, given the price regime and cost regime we're in. So, the real thing that's going to have to change relative to Oklahoma and some of the others is if we have a shift in natural gas and natural gas liquids, and then we'll be able to make those plays look more competitive with some of the oil prone plays that we're working on.

Okay, and then on current standing equipment, obviously you've got a lot of drilling coming up in this exploration side. You've already had some success there. How do you see a development playing out? When do you think you can start to see production to the local market and then ramping up from there?

On the two nonoperated prospects that we already have discoveries on, we do expect to see smaller scale, Circa 10,000 barrels a day, early production systems in place in the first half of next year, likely the first quarter. But I'm giving myself a little room there, because we do have winter in that part of the world. I think that's going to do two things for us, as we said. It's going to help us test these reservoirs a little bit more effectively. They are complicated. And it's also going to give us the ability to test some of the fiscal issues that we're looking at. So, you'll have small-scale production next year. These are plays that in the event that we elect to go forward with development based on successful exploration, you could certainly see production in a five-year window.

Okay, thanks.

Thank you. Our next question comes from Pavel Molchanov from Raymond James. Please go ahead.

Thanks for taking the question. First one about your hedging program, tell me if I'm wrong, but it seems that your hedge book has increased quite a bit, just in absolute terms since the beginning of the year. Is that part of a trend, or more of a one-time item?

Well, we actually at the beginning of the year didn't have any significant hedges on our equity production. So, this was a decision that was made in August and executed at the end of August.

Okay. Any -- your bank's encouraging you to do that, or just part of your portfolio management?

No, as you know, we're a strong investment-grade Company, so we don't have any issues with regard to balance sheet protection per se. But when we looked at the markets late August, it appeared to us that prices were quite attractive relative to the potential for downside price deterioration, so we put the hedges in place. You might remember that back in 2010, I believe, we did the same kind of thing and opportunistically put hedges in place for about a year at a time, and as that turned out well, this one so far has turned out well for us.

All right. Appreciate it, guys.

Thank you.

(Operator Instructions)

We have Doug Leggate on line from Bank of America. Please go ahead.

Hi, guys. Sorry for reprompting, but I just had a couple of quick, more mundane questions, maybe for Janet. Just looking at the earnings, it struck us that there were some nonrecurring items in here that could have been stripped out. I just wanted to get your perspective on it. First of all, on the corporate charges, there was no tax offset as you normally have. And also on the write-off of the Eagle Ford acreage that you're selling, I'm just curious as to why they weren't stripped out, and if you could help us understand what was going on with the corporate tax offset.

Yes. The unproved property impairment ordinarily comes as part of exploration expense, and therefore, we don't treat it as a special item. Obviously, it is nonrecurring. It's noncash, and we wanted to call it to your attention and treat it as you will.

In terms of the taxes, there are lots of things going back and forth in that account, so -- which are offsetting. But as you know, with Fin 18, as we look at our effective tax rate for the year at the end of the third quarter, we can see that we needed to increase the effective tax rate slightly. But of course, that means we have to have the full catch up for the full year, and so that's what's offsetting it, the blend to close to zero. What happened is as we look at what we expect to achieve for the full year of 2012, we are outperforming relatively in the high-tax jurisdictions of the UK and Norway, particularly and actually underperforming a bit in some of the lower tax jurisdictions. jurisdictions, which drives the overall effective tax rate higher.

So, it's basically a true-up, Janet?

An effective tax rate catch up, exactly.

Okay, I reckon about $0.10. Do you think that's a about the order of magnitude as it would have been otherwise? $0.10 delta on the EPS?

It was about a 1% effective tax rate change.

Okay, for the full year, though?

Through the first -- through the third quarter.

Okay, my other one, if I may, is just very quickly for Dave. The disclosure on the exploration, Dave. This Diaba well, I'm not sure I'm pronouncing it correctly, in Gabon has not really got a lot of attention from you guys, at least. Can you give us color as to what your expectations are? Obviously, it's subsalt and it's in a fairly hot area. If you could give us any color on your expectations, and I'll leave it there, thanks.

Well, we generally leave that to the operator Total, and I'm sure you could raise that with them. But pretty clearly, that's one of the most exciting areas of the world. Gabon obviously sets up well because you have onshore and near-shore production, and so we would expect this to trend out in the deep water like we've seen in the other areas of West Africa. And we're anxiously awaiting the spud of this well in the first quarter of 2013.

All right. Thanks, folks.

We have Feisel Khan on the line from Citigroup. Please go ahead with your question.

Yes, thanks, just a couple follow-ups. Of the 18 rigs that you have got running in the Eagle Ford, where do you have these rigs spaced out? Is it mostly in Karnes County or Gonzalez, and where would you have most of the operation running now?

Well, I guess in terms of what our ultimate for the year is going to be, half of our activity is in Karnes County, and then another quarter is featured in DeWitt and Gonzalez, and then the rest are scattered around. The three core counties is where we do most of our work.

Okay, and if you can just give us an update or reminder where your capital spending projections are for the Eagle Ford and what the breakdown is between production and also infrastructure for 2012.

Yes, we're still talking -- all in, with the things that we're doing, in between the $1.5 billion, $2 billion for what we'll spend in the Eagle Ford for operating CapEx. And I would point you to on the order of magnitude of $200 million to $250 million in terms of facilities.

Okay, and then last question from me on Libya. The last two press releases, you've excluded that production from guidance. At what point in time do you bring this back in? And then if you could just elaborate a little bit more on this gas sale, how it works, we'd appreciate it -- I'd appreciate that.

In terms of guidance on Libya, until we have a good sense of what's going on the ground, have ex-pats located in Tripoli, have been out to the field so we can understand what is a sustainable rate and what -- better sense to have a forecast for that rate, we're going to keep that separate from the overall forecast. So, it's hard to say, given some of the recent hostilities there, when that time will be.

Okay, so there's no Company men on the ground, or ex- pats on the ground in Libya?

Not at this time. Dave?

Faisel, I'll take that one. I think the distinction is that we have people on occasion rotating into Tripoli because we believe the security situation there supports that. We do not have ex-pats on the ground near the producing assets, which are in the, quote, unquote, deep desert. I think that's one of the areas that we're going to have to sort before we move forward. Now, with respect to the gas contract, basically, the way people should think about that is we will show an increase in production relative to the gas contract of about a little over 2,000 barrels equivalent per day, 14 million cubic feet until April when the second phase of the fair project comes on, and then that number will jump to 30 million cubic feet a day for us until we make it up. So, it's over a period of about two years that we'll make up that shortfall.

Sorry, go ahead. Sorry.

Just the underage, the underlift.

Okay, understood. Thanks for the time. Appreciate it.

Thank you. We have John Malone on line, from Global Hunter Securities. Please go ahead with your question.

Yes, just going on Faisel's question on where rigs are located. In Oklahoma, where are you drilling currently, where are you focusing?

The rigs are running in the Knox area and to the south of the Anadarko Woodford. But they'll bounce back and forth between what we call the [Cana], which is just to the north of that. And next year we'll probably branch out into some of the areas we've talked about.

Okay. And then can you elaborate a bit on Innsbruck, just where it stands right now, what their hopes still are?

Yes, I think as we indicated in the release, we're near the bottom of the hole, and we've gone through a series of objective zones. They have been less than encouraging. We've probably got, depending on what the well will allow us to do, potentially between two days and a week to go before we get to the bottom of the hole and the last possible objective, and then we'll obviously update people on what we came to.

Okay, thanks.

Thank you. I will now turn the call over to Howard Thill. Please go ahead.

All right, Dawn. Thank you, and thank you, everyone, for joining us and your questions on this call, and we look forward is to seeing you in the future. If you have additional questions, please don't hesitate to contact myself or Chris Phillips. Thank you, have a good day.

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