Good day, ladies and gentlemen, and welcome to the Murphy Oil Corporation Third Quarter 2011 Earnings Conference Call. Today's call is being recorded. I'd now like to turn the call over to David Wood, President and Chief Executive Officer. Please go ahead, sir.

Thanks, operator. Good afternoon, everyone, and thank you for joining us on our call today. With me are Kevin Fitzgerald, Senior Vice President and Chief Financial Officer; John Eckart, Vice President and Controller; Mindy West, Vice President and Treasurer; Barry Jeffery, Director of Investor Relations; and Tammy Taylor, Assistant Manager, Investor Relations. I'll now turn the call over to Barry.

Thank you, David. Welcome, everyone, and thank you for joining us. Today's call will follow our usual format. Kevin will begin by providing a review of third quarter 2011 results. David will then follow with an operational update, after which questions will be taken. Please keep in mind that some of the comments made during this call will be considered forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. As such, no assurances can be given that these events will occur or that the projections will be attained. A variety of factors exist that may cause actual results to differ. For further discussion of risk factors, see Murphy's 2010 Annual Report on Form 10-K filed with the SEC. Murphy takes no duty to publicly update or revise any forward-looking statements. I will now turn the call over to Kevin for his comments.

Thanks, Barry. Net income in the third quarter of 2011 was $406.1 million or $2.09 per diluted share, that compares to net income in the third quarter of 2010 of $202.8 million or $1.05 per diluted share. For the 9 months ending September 30, 2011, we had net income of $986.6 million or $5.07 per diluted share, compared to net income of $624 million for the 9 months ended September 30, 2010, or $3.24 per diluted share. Beginning in the third quarter of this year, operations related to the Superior and Meraux refineries, which were sold on September 30 and October 1, respectively, have been reported as discontinued operations. Excluding these results, income from continuing operations totaled $335.7 million or $1.73 per diluted share in the third quarter of 2011, compared to $197.4 million or $1.02 per diluted share in the third quarter of last year. For the 9 months period ended September 30, income from continuing operations totaled $854.2 million or $4.39 per diluted share in 2011, and $630.1 million or $3.27 per diluted share for 2010. Looking at income from continuing operations by segment. In the E&P segment, we had net income in the third quarter of 2011 of $261.9 million, compared to net income of $186.7 million in the third quarter of last year. Higher earnings for the 2011 quarter were primarily due to higher crude oil and Sarawak natural gas price realizations, partially offset by higher exploration expenses. The current quarter also saw a net benefit of $11.1 million from income tax matters. Crude oil and liquids prices averaged $95.95 per barrel in the third quarter of '11 versus $65.45 last year. North American natural gas prices averaged $4.20 per MCF this year, compared to $4.24 last year. On Sarawak, third quarter 2011 natural gas price…

Thanks, Kevin. WTI crude prices recently settled back into the current $85 to $90 range after exhibiting weakness in the third quarter. Dated Brent, the marker for 80% of our production continued to outpace WTI with the spread averaging just under $24 for the quarter. The recent contraction in the WTI-Brent spread is likely to remain through year end and doesn't appear to have a single course. North American natural gas prices suffered through the summer shoulder season, averaging near $4 in MMBtu for the quarter and more recently dropping to the $3.50 range ahead of the start of the winter heating season. Consistent with our pricing strategy, we have sold approximately half of our monthly gas production for this year. Our exploration program restarted late in the third quarter with the non-operated wells being spudded in the Gulf of Mexico and Brunei. In the Gulf, drilling of the Deep Blue sidetrack continues. We have found some oil pay but plans are to finish the drilling phase and move toward further evaluation. In Brunei, the first well in the CA-2 block was expensed as a dry hole. The objective section being largely devoid of reservoirs. The rig has moved and spud Meranti #1, the second CA-2 prospect. Drilling operations at the first well in Block CA-1 are still ongoing. Both Brunei blocks have multiple prospects featuring very large structures with the biggest risk related to this play associated with mass transit deposits that erode and influence reservoir distribution. Through the next few months, we will see a number of other impact wells started with Iraq early in the new year, as well as the testing of deeper targets offshore Republic of Congo. Drilling in Block H Malaysia will start up in the fourth quarter of this year and be timed…

[Operator Instructions] We'll go first to Blake Fernandez with Howard Weil.

Two questions for you, if I could. The first is on the exploration side. Given the discovery that Tullow had in French Guiana, I'm curious if that changes your view or the prospect opportunities that you may have in Suriname?

Okay. Blake, we entered that play recognizing that the margin had the type of opportunity that Tullow had found success in French Guiana. And we tried to -- different prospects, and they didn't work or really updip Seal issues, which we knew going in were the main risk. We're back looking again on our current acreage, and we're back looking at other acreage in the play to see where to go next. So I'm not discouraged, dry holes happen in our business. But I am encouraged that the play has been shown to work by somebody else. And so we were there, and I think now our exploration guys have just got to find out is there other things for us to do on our block or are there other pieces of acreage that we would like to have, and so that process is ongoing.

Okay, great. And then, the second question was on the production side. You've lowered the exit rate by a couple of thousand barrels a day, although it sounds like you're fairly optimistic on the workover wells in Malaysia. I'm just trying to get a sense where did the -- where did the, I guess, the shortfall, if you will, come from? And can you give us a sense of what volumes may look like in Malaysia overall into next year once all of the workover wells are on and producing?

Yes, Blake, it's a good question. The simple answer is that we got a little bit behind on one well at Kikeh where we had a poor cement job and we lost some timing, and then we did not factor in downtime in Schiehallion and Syncrude to the level that actually took place. So October was a bit of a delayed month for us, and that's really where the problem lay, which is why we're a little off here in the fourth quarter. Third quarter was good. I was very happy with where we were in our new processes and our ability to predict. As we look at Kikeh, and I'll just kind of jump into Kikeh, I think, probably other questions will probably be answered by this. We're currently just under 63,000 barrels a day today. We said at the last call that we had 6 wells to bring on by the end of the year. We brought 1 on. As I look in front of us, we've got 3 wells ready to come on within the next week. And if we haven't had the delay that I mentioned earlier, they will be on today, and so I think that's really the issue. And so by the end of the year, we see ourselves being at the 80 number, and so we feel really comfortable about it. We've had good results from the well that we brought on for some period of time with the sand fines migration. This gravel pack technique has worked well. The jobs to do the same on the 3 wells that we're getting ready to bring on here in the next week have also gone well, and so we expect those wells to perform as expected. And so we feel, overall, very good about where Kikeh is going. If I look at where we're going to go from today to the end of the year, we've got actually 48 wells to come on between now and the end of the year, so that drives that exit rate at the end of the year. We've got 19 at Tupper, 11 at Seal, the 5 at Kikeh I mentioned, 11 at Eagle Ford, 1 at West Pat and 1 at Front Runner. And so that drives the curve and -- Barry, why don't you break down the pieces there? You may give a little more granularity to it.

Sure. Blake, this is Barry. Current production today is right around 190,000 barrels a day. So to get to the 218,000 exit rate, basically you've got the Kikeh workover program bringing on 9,000 barrels a day. And our resource plays here in North America, they're all ramping up with additional wells coming on. So you've got Tupper West, 5,000 BOEs a day. You've got Eagle Ford at 2,500 BOEs a day, and you've got Seal at 1,500 barrels a day. So those are the resource plays. And our non-operated Canadian projects at Terra Nova, Hibernia and East Coast, we've got another 3,000 barrels a day coming on there with less downtime maintenance this quarter. And the same can be said for Syncrude about 3,500 barrels a day there with less maintenance downtime. And finally, in the Gulf of Mexico, we've brought on A7 at Front Runner, so at 1,500 barrels a day there. And then finally, the U.K with Schiehallion and Amethyst coming off their maintenance programs and back on, that's 2,000 a day. So that gets you from the 190,000 to the 218,000.

Next up, we have Evan Calio with Morgan Stanley.

My first question is on Kikeh realizations, they're now either higher in the quarter maybe a function of tapest [ph] differentials but also probably a partial function of cost recovery through the PSC. And so kind of given the spend levels, how could you kind of guide us through your elevated realization in Kikeh in 2012 would be helpful.

Evan, I'll take that call -- that question. This is Mindy. Our actual price for realizations that we got in Malaysian oil side was just under $120 a barrel this quarter. That differs from last quarter, it was $125 in the second quarter. Our supplemental payment, however, was lower this quarter versus last quarter because due to our workover programs, more of our barrels are being recovered as cost barrels and therefore are not subject to that supplemental payment. And our overall realization or entitlement has been in the high 60s versus the low 60s, and we didn't expect that to continue into this quarter as our workover program continued but probably should level out from next year and be closer to where we have been previously, so entitlement in the lower 60s.

Okay, great. That's very helpful. Also on the realization side, the Sarawak gas volumes and the realizations were both higher. I know there's been recent articles discussing a sharp increase in Malaysian natural gas demand year-to-date. I mean, does that accelerate your potential expansion plans? Or how does that influence that pricing formula? Is there any -- I presume it's partially a component of Pac basin and LNG pricing.

It's a function of LNG prices. We can't discuss particulars about the formula, and there is a little bit of lag to the formula as different cargoes get priced in but, yes, it's due to the strengthening of the overall price for LNG globally with a lag built in.

Evan, it's a -- it's a very good project for us. We've been averaging north of $250 million a day there, good operational results, have found additional resource to bring on to be able to extend the plateau there or if we're asked to be able to produce more. So we have great flexibility there. And the fact that gas price has got an oil-weighted index, clearly, as oil prices have moved up, gas prices have moved up. I think this time last year, we were talking $5.70 and now we're in the $7.40 range. So that's what happened over the last 12 months.

I mean, the production levels are somewhat a function of demand, so you could produce at a higher rate than you did this quarter?

Well, we're producing pretty steady state. If we're asked by Petronas to produce more once we do a little bit of change around, we certainly could do that. So it's not a resource or deliverability issue per se, but we budget around this 250, 260 level.

Okay. And maybe lastly, if I could. Just given the -- you touched on this in your opening comments, but given the natural gas prices, how should we think about your Montney expansion here? I mean, are you going to grow to fill the new gas plant, or potentially just run third-party volumes and shift some capital to other -- more liquid portions of your portfolio?

Evan, it's kind of the key question for us. We believe we have a very nice resource up there with good oil and costs around 350, but it's just smart, I think, to hold that program flat. So if you look at our budget next year and the year after, we don't really show any growth there. We have the technical capability and the desire to do that, but absent any gas price support, we'll not. So we'll be averaging about 230 next year and the year after, absent any price improvement. And so that gets us to filling the plant, say, for some third-party production that we already have going through, so that's kind of where we're trying to get to.

Next, we'll go to John Herrlin with Societe Generale.

Some quick ones. With Kikeh, what were the workover costs? And were they all absorbed by the PSC? Or did you have some direct costs?

All costs get put through the PSC, John, so -- And as far as exact costs, I'll have somebody here dig a number for you. So go ahead to your next question while...

Okay. Sure. In terms of the new concessions in Cameroon or Vietnam, are you looking at abyssal plain type of targets in Cameroon, and what about Vietnam?

Cameroon is a turbidite play. It's a foreman by us to accompany part of the acreage. It doesn't have access right now. We've just actually, yesterday, got our agreements done. We think that it's a highly prospective for oil in an area that has worked for the people for a play that's worked for other people. So we're very pleased to be there. Vietnam is in deeper water off the East Coast. We think it's largely untested play. But with our knowledge in the South China Sea, which is pretty good knowledge, we think it's quite perspective. And so, I see these first blocks in Vietnam be a first of the few. And I'd like to see us grow our footprint there because I think there is other opportunities to explore.

Okay, great. With the Eagle Ford, what are your well cost running?

Eagle Ford costs vary by area. But let me look at my little cheat sheet here, so that I don't give you an incorrect number. Drilling runs between a little over 3 to a little over 5; and completion cost, a little over 4 to a little over 5, that's kind of what they've been running. In some areas, we're down at 12,000 foot to the Eagle Ford. In some areas, we're shallow at 6,000. So that's the reason why there's a wide range.

How long are the laterals? And how many stages are you using for the fracs?

Usually 15 or 16 is the number of fracs. And we'll usually go 3,500 to a full 1,000 foot, that kind of range.

Okay. Last one for me, if you think in the future you might break out your North American unconventional plays in your disclosures?

Break out so...

At Eagle Ford, just list the production, so we can watch it.

Oh, believe me, I'm watching the production. We've got some pretty nice growth for Eagle Ford, so we'll end the year a little over 9,800 barrels net. In '12, we should exit a little over 20. In '13, we should exit a little over 36.

That's why I like it disclosed.

2014, a little over 50. So that, I think, gives you a sense as to where we're going with that program.

[Operator Instructions] We'll go to Pavel Molchanov with Raymond James. Pavel Molchanov - Raymond James & Associates, Inc., Research Division: A few things guys. First on the Eagle Ford, can you just update us on the acreage position, and whether you're still adding acreage either through just additional bolt-on deals or anything else?

Yes, Pavel, we like to. It's getting pretty pricey in the oily plays. But we're just a little under 240,000 net acres in the play. And as we see opportunities to add, which tend to be small, we'll do that. Pavel Molchanov - Raymond James & Associates, Inc., Research Division: Okay. Any particular target or just entirely opportunistic?

It's pretty frothy there, and so I would say opportunistic there's some cases small pieces of acreage and some, some larger deals to be done. And so we're in the game, we're active. But I don't have one that's right in front that I can say we're going to do it today. But we're looking to grow that footprint. Pavel Molchanov - Raymond James & Associates, Inc., Research Division: And then lastly, with regard to the U.K. refinery sale, how has the level of interest from potential buyers been compared to your 2 domestic plants?

I'd say today, we've got 3 or 4 folks that are talking to us about the refinery and quite a bit more than that, that are interested in our retail business. And so the question is and, of course, end of the year, well, December is a very difficult month to do anything anyway, which is why I have suggested that maybe it's going to be more of a first quarter next year kind of business. And then, we always have the option with Milford Haven of looking at the -- trying to get into a terminal, which is something that we've thought about and have that option as well. So I think it's a 2012 decision on all of that.

Next up, we have Mark Gilman with The Benchmark Company.

Let me see if I understand what you were saying in terms of Tupper West correctly. Are you deferring Tupper West Phase 2?

We don't have to make that decision until next year. So if gas prices stay the same, I would say that it's more than likely that we would not do it. But we don't have to make that decision today.

Okay. What working interest numbers should we be applying to your gross Eagle Ford volumes as you discussed them or quote them?

When I give you net, it's net. But our working interest varies from 90s down to something in the 50s throughout. But what I tried to do, Mark, is to give you a net production number.

Yes, but when you quoted where -- where you are currently, David, and this was similar to, oh, I think, the comments were made in the prior call, you talked about it on a gross basis.

No, I gave net today, Mark. That was -- so let me give that again...

Yes, let's try that again if we could, please?

Yes, so we're looking to exit here -- so at about 9,800 barrels a day net, equivalent net. So the 90...

So the numbers that I -- the 93 75 that you quoted earlier in your prepared remarks, I believe, was a gross figure. Was it not?

That's gross today. The 98 figure is the end of the year exit net.

Okay. What's the net on -- what is the net on the 93 75 and the 9.4 million feet a day?

It is 6,951 barrels of oil equivalent per day net.

Okay. Can we talk a bit about the Cameroon for just a second? Is this the same play as the -- I probably am going to mispronounce this, but the Sapele discoveries that you're looking at there?

Yes, I think, I mispronounce things too, Mark, I think they call it Sapele, and it's quite similar to that. So yes, you're right.

And David, I want to see if I can understand correctly the Suriname situation. It was my understanding that the 2 wells you drilled there were separate play types and were -- and only one of which was analogous to the -- to Tullow's French Guiana discovery. Is that accurate?

Well, I don't have any data around Tullow's discovery, Mark. So all I got is data on mine and what's been publicly said about Tullow's discovery. But what we were looking at in the 2 wells we tested was to drill fans that were very near or within the Turonian source rock interval, and that's what we did. And as my understanding from what's been publicly said is that was the equivalent interval in age that Tullow were testing. So in that regard, I would say, they were similar. As far as geometry, et cetera, I only know what the issues were with ours, and we believe our updip Seal was not present in both cases. We did have oil shows as we reported in this section and believe that the leakiness of the trap was the primary risk for us.

Okay. Can I just move to Seal for a sec and what you're seeing in terms of a polymer pilot?

Mark, it's going very well. The voidage is very good, and the incremental rates basically were taking wells and doubling the rates, so they've gone up from 50 to 80 barrels to 2x there. And so that's all very positive, and we will go through next year with a beyond pilot and have an actual development in an area. So that's very positive. We've also had a couple of multilateral wells come on. These are 6 laterals built from 1 vertical borehole and have over 400 barrels a day from those wells, which is very positive. So there's a lot of things associated with our Seal work that are very attractive for us, and we like what we see.

When do you think you might be in a position to sanction the major polymer project?

We're going to break it down and probably do 3 or 4 or 5 areas with the polymer. And as soon as they get on my desk, I will approve them, so I expect the first one to be next year, Mark. The other thing that we're working on, which I think is important for folks to remember is that the thermal component of EUR, we believe, will work nicely at Seal and through the course of next year, that will be something that we will be working on. Of course, we have to go through a series of approvals to do that, but that's got some nice upside for us.

David, who is the operator on CA-2?

CA-2 is Petronas.

And the second well, I think, what you referenced in your prepared remarks, is that a different play type from the first well?

No, it's a similar age section. It is a separate 4-way dip structure, a little further outboard than the first one, it's called Meranti. I referred in my remarks to these mass transit deposits, we've seen these along the Sabah margin, they're basically shallow water sediments or shelf sediments that are redistributed into the deepwater, and they either wipe out the reservoir that's already there or they influence the deposition of reservoir that takes place. And so the first well that we've drilled in CA-2 saw a thick section of these MTDs. They generally are not reservoir quality themselves. And so that is one of the risks going in that we are aware of. And so understanding the MTDs and where the MTDs are not is a critical element, I think, in exploration in all of Brunei.

We'll go to Katherine Minyard with JP Morgan. Katherine Lucas Minyard - JP Morgan Chase & Co, Research Division: Just a couple of quick questions. As we think about your production growth to 300,000 barrel equivalent per day through the middle of the decade or in 2015, I know we've got a few projects or some of those volumes that will need to come from additional project sanctionings, what might we be looking for over the next, say, 12 to 15 months or so in terms of milestones in terms of sanctionings that would kind of bridge some of that delta?

Well, really, the first thing is the projects that we sanctioned this year that start to come on in 2013 are going to have as big an impact as any, and we sanctioned 7 this year, Siakap North in deepwater Malaysia, Serendah, Patricia, South Acis, Permas and Enbau in Sarawak, and then Schiehallion redevelopment and that will be a little later, that will be 2016. But those deals were new deals to be brought on. Next year, Dalmatian, potentially Tupper West Phase 2 if we get some gas price assistance. And then what we were just talking about earlier, which is Seal, will all add in the 2014 kind of range. So those are some of the milestones that we're looking at. And then we have some things that we're working that we hope to bring forward to the course of next year as well. So it's those this year and next year that I think really will drive that 2015 target. And what I'm not including in there is our Eagle Ford, which for me is just kind of an ongoing development of the footprint that we've already got, so it will add on top of that. Katherine Lucas Minyard - JP Morgan Chase & Co, Research Division: Okay. All right. And then I apologize if you guys already addressed this, but I'm just -- I'm looking at your exit rate for the year of 218,000 and then your 200,000 barrel equivalent per day as your full year guidance for 2012, am I missing a big maintenance project or a big maintenance undertaking, or something that kind of results in that drop from the exit rate to full year next year?

No, Katherine. It's kind of like my golf game. In any one given shot, I can make a good shot but you've got to put all 18 holes together to get the full picture. 218,000 barrel equivalent a day at the end of the month doesn't reflect normal downtimes, normal workovers, et cetera. The 200,000 is the average for next year. And so you should compare that number, I think, to the 185,000 or the number close to 185,000 for this year. And to me, that's the year-on-year number and then compare that to the 230,000 number or 225,000 number that we're talking about for 2013 on average. I think that's really the comparison that I would point you at. Katherine Lucas Minyard - JP Morgan Chase & Co, Research Division: Okay. All right. Great. And then if I can just squeeze one final one here. Just thinking about your cash balance and clearly, you guys have maintained a pretty strong balance sheet, and you're looking at debt to cap in the low-single digits by the end of the current year, if I got Kevin's remarks correct. Are there any other potential uses of cash? I mean, clearly, developments are one of them, you've got the dividend. But should we be thinking about looking for anything like, for example, funding maybe some underfunded pension liabilities or any other uses of cash that we might be looking to see? Or are you going to try and kind of retain that strong cash position?

Yes, we don't have any underfunded pension liabilities, and we do have an exceptionally good balance sheet here. We have all things kind of on the table, Kat, and that's the way I would look at it. We clearly are prepared for success in our exploration game for developments. We would like to acquire some things that will help bolster our growth and asset base in our upstream business. And so, we're working that actively now and other things that will help our overall business we're actively looking at. So it's a nice position to be in, and we feel good having executed on the refinery sale that allows us to be in this position so.

A call from Blake Fernandez with Howard Weil.

Guys, sorry to reprompt in, but I had one more question for you on the Western Canadian gas prices. I know Shell is exploring the potential for LNG export from the West Coast. Just curious have you had any discussions with them? And is that something that you think is on the horizon that you could participate in?

Blake, I'm happy to sell gas to anybody for more money. So if there's an opportunity to do that, we would look at that and have looked at it. I think LNG export from Canada is a little way down the line, and there is a lot of gas that's there. But as I've talked before, I actually think there's probably a better opportunity for some gas price appreciation in Canada because of that versus the U.S. So I think we're positioned but I don't know that it will be a '12 piece of business or '13 piece of business. It probably is beyond that.

Let's take a call from Joe Citarrella with Goldman Sachs.

In terms of assets, I think, you mentioned in the past that you don't believe you're getting enough credit for namely the retail marketing business and Syncrude. Any update there on how you're thinking about realizing those values going forward, where you stand on the potential for the retail marketing business to be on its own, and how at this stage are you thinking about Syncrude in the context of your E&P portfolio?

Yes, Syncrude, I think, is a great asset. And if you generally believe in increasing prices longer term, given the long life of resource there, it's a nice thing to have. So I don't feel very motivated to do anything with that other than keep it and enjoy it. As far as the retail business goes, I've said that it's, in my view, reached critical mass. It is a great business, has got good results as we've talked about. I think it has a very, very bright future. But I also think that it's something that we, as Murphy Oil Corporation, necessarily don't get full value for. And as I've commented, I think at some point in time, we will look very hard at seeing whether we want to make that a separate business or not. And that isn't a 2011 decision, but I will say that I will look very hard in 2012 at that business, and bringing that forward is a possible thing for us to do so.

That's very helpful, that's helpful. And quickly, apologies if I missed this, but in that 200,000 BOE a day number for 2012, how much of that is Kikeh?

Kikeh will be near 80 on a gross basis -- gross basis, that's not net.

Got it. And the net basis in that number?

It would be somewhere...

The entitlement is in the low 60s specifically.

Yes.

We have a call from Paul Sankey with Deutsche Bank.

David, I was wondering, and you've been very clear about the 300 target for 2015 for sometime now. I was wondering, for example, at the time of the Analyst Meeting, was 200 your anticipated rate for 2012? Or is that now a lower number than you would have thought midyear?

Paul, I don't have the number in front of me, but I believe it's lower because of what has taken place at Kikeh, and yes, I think, it's lower because of that. But I believe that the work at Kikeh has shown that we can address the problems and now get some stability there. And I think going forward, I think, we're in good shape.

Yes, I see. I mean, I guess, the issue is that there's an implied acceleration kind of later in the period we can infer sort of a 2014 number from your -- I think you said 225 for '13, didn't you?

Yes.

Yes, so if we go -- obviously, if we go to 300 by '15, the kind of treadmill is going to get quicker in the '13 to '15 time frame, but your confidence in Kikeh and your sanctioning ability is making you stick with the 300?

Yes. We have moved forward some of the projects that I mentioned that we sanctioned this year, Paul, which helped that. We also are climbing the curve faster on Eagle Ford than we had before. We have more rigs now, and that's really a rig function. So we have made compensation within the rest of our program to be able to meet that target. And I think the important thing here is that we're not looking for things that we don't have to make that contribution. Now we talked a little bit about dry gas and gas prices, and I think if we pulled out Tupper Phase 2, we'd probably take out 30,000 BOEs equivalent out of that number. But we're working to make up that production with more liquids production to accelerate Seal, to accelerate Eagle Ford. So all of those things are kind of working around here, so that we can kind of move towards that target. So there is some flexibility in there, which you would expect from a program with many different things in it.

I mean, the level of detail, David, suggests that you're happy with the portfolio as it stands and that you can clearly get there organically. Would we then infer the acquisitions are unlikely from you?

No, I think it's always good to make additions to your portfolio. As we've talked about before I have -- I really want to be focused on returns for BOE produced, and you kind of have to have new things keep coming into your program to help you drive that, be it through exploration, be it through acquisitions, be it through growing programs. So I'm happy where we are today, but tomorrow, I would like to keep growing what we're doing and get better at what we're doing. And so -- but today and on track to get to this number, Paul, I feel pretty good about it.

David, a separate follow-up, if I could. The retail, you were talking about the retail and the potential long term for that part of your business. I was wondering whether you see it remaining within Murphy as such or whether that could become a separate company?

We've had a -- I think, it's a good topical question, Paul. In the past, we had a timber business that we spun to our shareholders. And that the business even though it's external business is a difficult environment I think has done well. And so I think our shareholders are getting rewarded for really creating this retail business. It's a great way to go. I do believe it's a different business with different drivers than an E&P business. And so I would say one logical step, one thing for us to consider seriously is that we would spin that to our shareholders. And so, as I addressed the question that was asked earlier that is something that is not a 2011 look but certainly will be looked at pretty heavily in 2012.

We have Gene Gillespie with the Gillespie Consulting Group.

Listen, in terms of investment options going forward, is repurchase of your stock at all on the radar?

It is on the radar, Gene. It gets looked at like a whole bunch of other things so, yes.

We have a question again from Mark Gilman.

David, the prospects that you're looking at in Cameroon and in Vietnam, stratigraphic or structural?

The play in Cameroon is turbidite fan off the margins so primarily stratigraphic, and Vietnam has both elements to it.

I had thought for some comments, either you, Sam or both May -- back at the May Analyst Meeting that going forward the focus would be almost strictly on structural type prospects?

Yes, I think he was talking about as an overall weighting, Mark, and not on kind of in total. And so I think picking up both Vietnam and Cameroon is entirely in context with where Sam was going.

CA-2, same question.

CA-2 has mainly structural prospects to it, but there are stratigraphic opportunities there that we'll have to evaluate as we go down the drilling program, both there in CA-1 and in CA-2. And so, we don't rule that out as being an important element, given what I said about MTDs and how they influence reservoirs.

That was all the questions we have for today.

Operator, thanks a lot, and everyone, we appreciate you dialing in. And we look forward to our next call and talk about the fourth quarter. Thank you.

Once again, that does conclude our conference call for today. We thank you for your participation.