Steven A. Cossé - Chief Executive Officer, President, Director and Member of Environmental, Health & Safety Committee Barry Jeffery - Director of Investor Relations Kevin G. Fitzgerald - Chief Financial Officer and Executive Vice President Roger W. Jenkins - Chief Operating Officer, Executive Vice President of Exploration & Production and President of Murphy Exploration & Production Company Mindy K. West - Vice President and Treasurer

Leo P. Mariani - RBC Capital Markets, LLC, Research Division Evan Calio - Morgan Stanley, Research Division Guy A. Baber - Simmons & Company International, Research Division Paul Sankey - Deutsche Bank AG, Research Division Arjun N. Murti - Goldman Sachs Group Inc., Research Division Paul Y. Cheng - Barclays Capital, Research Division Blake Fernandez - Howard Weil Incorporated, Research Division Pavel Molchanov - Raymond James & Associates, Inc., Research Division Raymond J. Deacon - Pritchard Capital Partners, LLC, Research Division Raymond J. Deacon - Brean Murray, Carret & Co., LLC, Research Division Mark Caruso

Good afternoon, and welcome to the Murphy Oil Corporation Second Quarter 2012 Earnings Conference Call. Today's event is being recorded. I'll turn the conference over to Mr. Steven Cossé, President and Chief Executive Officer. Steven A. Cossé: Good afternoon, everyone and thank you for joining us in our conference call today. With me here in El Dorado are Roger Jenkins, our Executive Vice President and Chief Operating officer; Kevin Fitzgerald, our Executive Vice President and Chief Financial Officer; John Eckart, who's our Senior VP and Controller; Mindy West, who's our Vice President and Treasurer; Barry Jeffery, Director of our Investor Relations; and Tammy Taylor, who's the Manager of Investor Relations. And Barry, you got some statement to make?

Thank you, Steve. Welcome, everyone. Today's call will follow our usual format. Kevin will begin by providing a review of second quarter 2012 results. Steve and Roger 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 obtained. A variety of factors exist that may cause actual results to differ. For further discussion of risk factors, see Murphy's 2011 annual report on Form 10-K filed with the SEC. Murphy takes no duty to publicly update or revise any of forward-looking statements. I'll now turn the call over to Kevin for his comments.

Thanks, Barry. Net income for the second quarter of 2012 was $295.4 million or $1.52 per diluted share. This compares to net income in the second quarter of 2011 of $311.6 million or $1.60 per diluted share. For the 6 months ending June 30, 2012, our net income was $585.5 million or $3.01 per diluted share compared to net income for the same period in 2011 of $580.5 million or $2.98 per diluted share. There were no unusual items of significance in the 2012 quarter or for the 2012 6-month period. However, the 2011 quarter did include $31.6 million at $0.16 per diluted share of income from discontinued operations related to the two U.S. refineries and associated marketing assets that were sold at the end of the third quarter of 2011. 2011 year-to-date results included income from those same discontinued operations of $62 million or $0.32 per diluted share and an after-tax gain of $13.1 million, $0.07 per diluted share from the sale of natural gas storage assets in Spain. Looking at income by segment. In the E&P segments, net income for the second quarter of 2012 was $230.1 million compared to net income in the second quarter of 2011 of $243.3 million. Lower E&P earnings for the 2012 quarter were primarily due to lower crude oil and North American natural gas price realizations. Crude oil and gas liquids production for the current quarter was approximately 104,000 barrels per day as compared to approximately 94,200 barrels per day in the corresponding 2011 quarter. The increase is mostly attributable to production at Kikeh and in the Eagle Ford Shale area of South Texas. Natural gas sales volumes averaged 507 million cubic feet per day in the second quarter of 2012 compared to 457 million cubic feet per day in the second…

Thanks, Steve. First in exploration today. Our 2012 exploration program is continuing on track for the year, with all of our wells being successful so far. We completed drilling of our Linnava exploration well on our Central Dohuk block, the Kurdistan region of Iraq and preparing to test the observed oil shows across 6 potential intervals, which total 278 meters of net pay in Jurassic and Triassic age of reservoirs. Over the next 6 weeks, we'll be conducting detailed core analysis and production testing. In the second quarter, drilling was completed on the Julong East sidetrack and the Jagus East 1 well in the CA-1 Block of Brunei. Each of these wells were discoveries. Last -- later this quarter, we'll spud the Opal [ph] Marine #1 well in the MPN block offshore Congo and test the 250 million barrels 10g [ph]carbonate target. In the Gulf of Mexico, we plan to spud a Miocene amplitude test and the Dalmatian South prospect in DeSoto Canyon 134 in August. In offshore Sabah, Malaysia this year, we anticipate drilling 3 additional exploration wells. We'll drill a Miocene-targeted structure on Block P and we'll drill 2 additional low-risk gas prospects as a follow-up on our 2 recent discoveries in the Rotan area of Block H, which is slated for floating LNG development. Petronas, the owner of the proposed floating LNG vessel, continues to progress the project in recent placement of FEED awards. Rounding out this year's program internationally, [indiscernible] with #1 well in Block WA-423-P in the Browse Basin offshore Australia, which is scheduled to spud in early quarter 4. We're back to work in the Gulf of Mexico. Our board recently sanctioned the Dalmatian development. This project was sanctioned as a 40 million barrel equivalent resource, which will be developed at a 70% working…

[Operator Instructions] Our first question comes from Leo Mariani with RBC.

I wonder if you could give us a little bit more color on the CapEx increase. You guys talked about moving higher to $4.1 billion. Does that include the Gulf of Mexico acquisition that you guys talked about there? And I guess just looking for the amount in terms of what you paid for that.

Yes, it would include that. It's wrapped up in there, Leo. This is Roger. Today is the closing for that sale. I'm really not at liberty to talk about it. I would say that it's a situation where we are the operator there and it's approved reserves that we're comfortable with and the comparable price to that was something that was attractive to us. We executed that deal. To answer your question, the purchase of that is included in the roll-up of that additional CapEx.

Okay. And you guys talked about 2,700 barrels a day being added, is that like a sort of a number for the rest of the year? Is that kind of a full year average? Any color you have around that will be helpful.

It must be a mistake maybe on my part. It was 2,100 barrel equivalent a day additional that's included in our guidance from that purchase.

That's an annual average number.

An annual average number.

Okay, got you. And just in terms of Kikeh, all the workover is done this year?

No, we'll continue on with the programs there. I mean, we're -- Kikeh, just to back up for a second, August 17 will be the fifth year of production there and so it's a long-term project for us. We have an ongoing program there of adding additional wells, working on wells that will one day need to be -- have a new completion and that we'll be working there through all of next year as well. So Kikeh, however, did have a good quarter and the way I look at it from call to call, Kikeh production is very flat without adding a well. And I think it's in good stand for our forecast that we have. We've maintained the forecast 2 calls in a row now at Kikeh.

All right. I guess in your ethylene business, you talked about it being very challenged here in the second quarter, which hurt results. Can you kind of quantify that in terms of like a cash flow-type of number in terms of how much you guys might have lost versus the previous quarter? Steven A. Cossé: We're searching for that now.

If you just want to go on the net income basis -- and this is Mindy talking, the ethanol business for the second quarter lost approximately $3 million, which is a little bit above what -- a little bit under what it lost in the fourth quarter where it lost between $4 million and $5 million. Fourth quarter was really the last good positive quarter it has had.

Got you. So it didn't really dramatically affect sort of the sequential results then is what you all are saying? It's been similarly weak for a while?

That's correct.

Okay. And I guess in terms of the retail spin out, sounds like you guys are still going through a decision there. Do you have any kind of key factors in your mind or kind of 1 or 2 things that would lead you to move one way or the other on that? Steven A. Cossé: Now before we get to the -- actually, before we get to the spin, no spin decision, you've got to understand this underperformance we saw in the first quarter. It improved in the second quarter, but still we felt like it's underperforming its capabilities and we really need to understand that and address what -- why that is.

Our next question comes from Evan Calio with Morgan Stanley.

Maybe just a follow-up on your last comment. I thought you had real strong margins in the quarter in retail. I mean, could you help us understand what you think the operational issues might be that you're seeking to? Steven A. Cossé: Well, let me say, first of, yes, we did have margins, but we -- on a relative basis, we sort of underperformed the competition. We really did and while others were gaining volume and margin, we weren't and we need to understand that.

I got you. And maybe also on the same kind of strategic side, I know it was regard the cash position as well as other potential receipts from the downstream sale. I know there was originally an intent to look for attractive assets to acquire to further diversify the production days. I mean is that still the plan as well as you see going forward? Steven A. Cossé: Yes, I'm thinking we're always in the hunt for attractive oil and gas asset, I'll say that. So yes, that remains unchanged.

Okay. Maybe just shifting to Canada. I know that you were reducing the spend in Canada in Tupper, yet your 2Q will volumes were flat. I thought you said 1 rig running. I mean was there a big, big well backlog? Or what am I kind of missing there?

Well, we didn't start our curtailment of gas in Tupper West and Tupper until July 1. So we won't see that until next quarter. That's actually one in the third quarter that's last production. Our rigs in Canada today are at Seal. We do have a rig in Tupper drilling today because we have to move some downspace-drilling before the wells deplete further. So we have some small activity in Tupper, but primarily our focus in Canada is in our Seal, the heavy oil asset.

Maybe just one last one if I could and it's related to Tupper. With more interest in securing gas in the Montney for potential O&G exports, I mean, do you see any opportunity there to either participate on emerging or new or export LNG project or monetize your position for -- to someone who does?

Right now, I wouldn't say we have an immediate plan of that, of course, we're taking back at some of the price recently paid for LNG and the recent acquisitions up there just northwest of us. I think as we go into this upcoming budget cycle and get ready for next year, the realization, where we're going to be on gas price and inability probably to invest in that business, we're more likely to take another look at that. Quite honestly, we're just not the size or the perceived size of some of these acquisitions. We probably are bigger than we have on our books for that, but we need to look at that probably. But to be frank with you, Evan, I don't think we have the Tcfs they're looking for right now, but we could probably dovetail into another one over some period of time.

Our next question comes from Guy Baber with Simmons & Company. Guy A. Baber - Simmons & Company International, Research Division: I had an exploration question on 2 of your potentially high impact prospects you're considering drilling later this year previously, and that's Cameroon and that's your hard-working interest block in Brunei. So can you share whether you have lined up the rigs? Do you need to drill these prospects and should we still be thinking about those as 2012 spud dates? And then can you share any info on potential size of those early prospects you're targeting there?

This is Guy, right? I'm sorry, is that your name, Guy with Simmons? Guy A. Baber - Simmons & Company International, Research Division: Yes.

First, in MPN, we've had a -- we've solidified really on our rig schedule. We have the Ocean Confidence rig in Western Africa. It's coming to us. To drill a required well, we must real this year at in MPN and we'll go back to another operator. We'll hit that rig around a year from now probably and which we are going to drill somewhere in Cameroon. We have different opportunities there. MPN is one of those. We will go through our budget process to decide where we put that. It's quite a large prospect and the definitely significant side, if you will. As far as the Brunei CA-2, where we're 30% working interest, we should go back there at the real -- near the end of the year and we're drilling some prospects there that are being pulled out of a list. We have many partners there to work with, but we're not operator of that block, but we should get back in drilling business at CA-2 right at the end of the year with probably one well and probably a well next year there as well. Guy A. Baber - Simmons & Company International, Research Division: Okay, great. And then I had one more just on financial priorities and I think you guys touched on this in the prepared remarks. But obviously, you have a conservative balance sheet here, a lot of cash, a lot of liquidity. But with a new CEO, I'm just wondering if the financial priorities for cash and for the balance sheet have changed at all. And if you could just outline for us what the priorities are there just with respect to excess cash and maybe just touch on dividend, CapEx, acquisitions as a means to drive growth and kind of how you rank those. Steven A. Cossé: This is Steve Cossé. We see no change in priorities. As you know, yesterday, we increased our dividend by $0.15. We have a pretty hefty CapEx program in front of us and I think that's going to pretty much keep us busy, as well as our cash flow and probably our cash as well. Kevin, do you have anything to add?

No, I think what you have to keep in mind is that -- a lot of the cash we have on the balance sheet is in foreign locations and it's there just because of tax efficiencies or inefficiencies, whatever -- the game that day. I mean, we look at bringing that money back when it is tax efficient. Since we have a strong balance sheet, I'm not forced to bring that money back. I can always just follow a little bit under the revolver or something like that. So it gives us a lot of flexibility and that will just continue. It's the same MO we've been operating number for several years.

Our next question comes from Paul Sankey with Deutsche Bank.

Listening carefully, it seems that you're essentially reiterating everything that was said at the Analyst Meeting in May, which I guess had a 5-year outlook for Murphy as presented by David Wood. We were surprised by the resignation, but it seems to me that, if I understand what you're saying, including your targets for volumes this year, every other elements of what you outlined at that Analyst Meeting essentially you standby with the possible exception of the retail spin where you seem to be saying that the operational competitiveness of the business needs to be looked at harder before you can make a decision on that. Is that fair? Steven A. Cossé: Yes, I think you summed it up very well.

Okay. Steve, for you, I believe you previously retired. Is this a long-term position that you see yourself holding as a CEO? Steven A. Cossé: Paul, I served at the discretion of the board and Mrs. Cossé and either have yet expressed any great dissatisfaction.

That's a very correct answer, Steve. So is there a time frame now that we can think about for the retail spin because it's actually one thing that's kind of different. Can you give us... Steven A. Cossé: As you know, we've got some work to do understand exactly its underperformance and Paul, I'd really like to stay clear of the timetable that undoubtedly will be wrong. We like to proceed with our work to get it done, proceed with the decision on spin or no spin and then announce it.

Our next question comes from Arjun Murti with Goldman Sachs.

Steve, maybe just a little bit of a follow-up to the last question. So you're not interim CEO. The board is not actively looking for a replacement. We should think about you as the ongoing CEO for Murphy? Steven A. Cossé: Yes.

And you mentioned the reiteration of the strategy, is it operational execution, maybe it's the retail thing? Or is it just being more aggressive in pursuing things that sparked wanting to make a change here? Steven A. Cossé: You're talking management change?

In the management change, yes, sir. Steven A. Cossé: Yes, let me address it this way. Let me tell you what it's not. It's not some great scandal that's going to break. There's no other shoe to drop. No other event of any significance to be announced. And I really think, Arjun, it's more -- it's accumulation of little things over time, probably communication being one and I think both sides were astute enough to see the trend and where this was going. And to realize that, "Hey, now is the time to change. Now is the time to part amicably and end it now before it got worse." So that's probably the best way I can express it. But again, I want to repeat that the management changes no -- absolutely no change in strategic direction.

Appreciate the candor. Just 2 quick production-oriented questions. I think you basically reaffirmed the guidance going forward. Is that true for '13, '14, '15, the production numbers outlined in the Analyst Meeting?

Yes, Arjun. This is Roger. That Analyst Meeting was my presentation and Paul a few minutes ago asked if that was where we're headed. I still assume that it is. Of course, we have to roll up our budget and we're ever mindful, Arjun, about your email on capital efficiency, and we'll be looking into that and rolling up our budget and see if we can maintain that level of growth. I'm not worried about the subsurface or ability to get to the targets that were shown at the AGM meeting. But the pace of that, as you know, can go up and down, especially when you're an Eagle Ford player. And so overall, that general direction is absolutely there, same direction, same presentation that I gave. And we are in the middle of our budget for next year and rolling through that process, but in general, heading in that direction.

I appreciate it. And then just very lastly, I know you addressed it in part in the prepared remarks but just Kikeh, maybe where do you think production will level out once you're through all the workovers, et cetera? Where do you feel Kikeh ends up oil production?

Kikeh is a very complicated field. We have 21 producing wells, 8 reservoirs. We've made 150 million barrels. We probably injected 200 million to 300 million barrels of water. It's going to reached, we think, around 75,000 gross at near year end and maintained that for some into '13 and then we'll need to reiterate with our budget, where that goes. We have a good handle though on the forecast. We've maintained the same forecast now for several months. We've had some operational problems on our rig, on our spar that was hurting getting the production higher. Those are getting better. Overall, I think it's in good shape, but I don't think we'll ever get Kikeh back to some 100,000 barrels a day and just let it ride for several years. I don't think that's where it's going. This is always an element of decline and I think to that nature as we get all these wells drilled. But I don't see anything going on in the operations of great concern, and we look to add a good bit of production here in the fourth quarter.

And it sounds like there's nothing to really meaningfully change your estimate of the reserves there. It's more some of the operating issues in the oil field, that's natural, the declines, obviously.

That's right. Yes, I would say that's a fair statement.

We'll take our next question from Paul Cheng with Barclays.

Several questions. On Kikeh, have you guys already replaced all the sand screen?

Paul, this is Roger. I've heard your voice for many years but never spoken to you, looking forward to it. Kikeh today, we have 4 wells that have expandable sand screens in them. They're making a cumulative probably around 19,000 barrels of gross of oil. When water is projected to hit those wells at various tons, we feel that those wells could fail. So we're in there now drilling twins to those wells to ultimately replace them, as new wells and better take points for the reservoir, the next 2, if you will, of those producers.

So that means that, Roger, is that you learned from the last mistake, so we are not going to see all the 7 that you have, say, "Oh, I mean the production is down because the sand screen failed." So now that you are going to [indiscernible] on that by drilling the additional well already.

Yes, that's true. I guess, the wells could fail now as we're in the middle of drilling the well [indiscernible]. A couple of them are more prolific than others. So naturally, we will replace the more prolific once first, right? So we're in the middle of doing that. We think we could still have a catastrophic failure there in the well and when we do it, it's hurtful to Murphy. But we're in a process of getting ahead of that and have 4 of those wells left and then we have some additional wells to complete our fuel development plan workovers, et cetera to any big major field with the ongoing multiple reservoirs and water injection that you'd find anywhere else in the world.

Okay, that's great. And Roger, you do you have average 30-day IP run rate that you can share in the Eagle Ford for the second quarter, and the well costs as well as what is the unit cash operating cost that now you're running in the Eagle Ford?

That's a lot of stuff there, Paul. Hang on there, just a second. In the Eagle Ford, one thing unique to Murphy is we're across 4 plays. So we're in Karnes. We're in a field we call Tilden, Northfield and Catarina, all in oil focus. All those are different levels of depth, at Eagle Ford, different cost structure. I would say our wells -- we're drilling and completing wells around $8 million in Karnes, maybe $8.4 million there, $8 million in Tilden and in the $7 million range in Catarina. Our drilling costs have reduced by 14% this year. Our OpEx there is probably a little high in the probably 20s, moving down long-term into the 10s. We have a lot of rental equipment because we have a lot of expansion in new areas where we're drilling and if we build facilities, we remove the rental equipment. We think we're trending down the OpEx. It will get into next year after that to improve. All in all, our -- I guess the other questions on EUR. I would we're -- EUR IP was your question?

The 30-day IP.

30-day IP in Karnes is probably 500 to 700 average for us. Let me turn it right here in just a second. I think we have the 4 fields. It's a lot to keep up with there. We're around, I would say, 300 to 400 in the Tilden area and 200 range in the Catarina area for 30-day IP. It'd be pretty normal. We really have pretty good performance there and the subsurface in the IP rates are really not a concern for us there.

Okay. And that maybe, I think it's both for Roger and Steve. This year with the $4.1 billion in the CapEx, you overspend your cash flow -- I mean, if we're including the dividend, you have to pay more than $1 billion. Yes, you have a very strong balance sheet, but how many years that you can continue not to overspend by $1 billion. So how should we look at in terms of the company strategy? Do you really want to continue that trying to hit the growth target by overspend that dramatically or that you think you need to scale back your CapEx back to live more within your mean? Steven A. Cossé: I think our projections show that if we fund our CapEx program over years, I don't think we get to a debt-to-cap ratio very, very high. It's very, very manageable and with our development projects and production coming onstream, it's -- it reduces over time fairly nicely. Kevin?

Yes, Paul, even with the -- what we're projecting for this year, we would end even with the additional capital, we would end the year with a debt-to-total cap in the low teens. And then Roger has got a pretty aggressive exploration schedule. I hope we'll have some success there and then we'll start to develop those. We've had development projects, which the Eagle Ford itself could be considered a big development project. We run debt up into the low 30s before. So if you've got a good project to do, that's why we keep the balance sheet the way it is, we've got to take advantage of those opportunities. That being said, a lot of that monies being spent at Eagle Ford and most stuff winding down as we get out to '14 and '15.

So Kevin, should we assume that the 5-year trend you present in your Analyst Meeting in terms of the CapEx, those, say, in the $3.5 billion to $4.5 billion for the next couple of years that still is -- what do you guys have in mind at this point?

Well, at this stage, I think that the number that we showed at the Annual Meeting are probably a good go-by. But like Roger was mentioning, we're in the middle of a budgeting process and a new 5-year planning rollout where we're looking -- Roger mentioned signing up quite a few new concessions and PFCs in different areas. We got to see how that fits in all along as you go out 3, 4, 5 years and so we're rolling out that plan. We'll have a much better feel as we get into October and November of how that's playing out. Probably, on the next call, have a little bit more color we can add there. The thing to remember is in the Eagle Ford, the beauty of the resource play, as you know, is that you can ramp them up and ramp them down a lot easier than you can with some big projects like the Kikeh or these oil projects that we have in Malaysia. So you just need to keep developing those and if oil prices would diminish or something, you can scale back in the resource plays. So we have a lot of flexibility and that's the reason we keep that balance sheet the way it is.

And then 2 final questions. One is for Steve. Steve, on the U.K. downstream sales, is there a timeline that you will decide say, "Okay, it's not really going to happen, so we're going to turn it into a terminal" or yes, I mean, that the price is not good and then we're going to keep it running as an ongoing entity. Is there any timeline that you can share? Steven A. Cossé: There's no specific time line, Paul. As I've said earlier, it's a tough, tough market to sell over time, as Mr. Icon [ph] noted here in the United States. But converting it to a terminal, I think it's probably the last thing we do and as long it's performing -- if the refineries is performing as it is now with margins and not particularly drag on earnings, I think we'll continue operating it until we do find a way to divest ourselves of it, but again, the terminal is probably the last thing we'll do.

I see. And final one, maybe either it's Barry or Roger that you can -- if you're kind enough to give us in terms of your third quarter production guidance, can you break out more in detail the oil and gas by regions?

Okay. Quickly, Paul here, we've got third quarter U.S. oil is about 28,000 barrels of oil a day and about 51 million cubic feet of gas. Canada is about 27,000 barrels of oil a day, 195 million gas. Malaysia is about...

Can you breakdown the Canadian oil into offshore, heavy and Syncrude?

Yes, heavy is about 7,000 oil. East Coast Canada Hibernia about 5,000 because turnover's on turnaround and sinker is about 14.5. Then we go to Malaysia, you've got 48.5 on oil, Kikeh, being about 42.5 of that. And you got Malaysia gas at about 202 million cubic feet with Sarawak being 155 of that. Those are the big ones.

And Congo?

Congo is like 2,000 barrels a day, Paul.

2,000. What's the corporate expense that you guys assumed in year EPS guidance?

Corporate charge was $23 million.

[Operator Instructions] Our next question comes from Blake Fernandez with Howard Weil.

Steve, welcome to the party. I had -- I hate to dig in too deep on the retail. I know you've covered the underperformance there, but I was hoping if you -- I'm just trying to understand. Is that more of a cost or operating issue or is that simply a function of losing market share, which could be related to maybe a slowdown of foot traffic at Walmart? Steven A. Cossé: Well, no, it can be all those things probably. Until we do the work, it's kind of hard to assess. I wish I could have some more clarity for you on that, but I don't right now, but would love to soon.

Okay. So it sounds like you're really in the initial stages of kind of evaluating that, all right. And then secondly, on the Kurdistan well, it's -- I understand it's early days. I know during your Analyst Day, this seemed like one of the larger prospects. You gave quite a large range of anywhere from 100 to, I guess, 1,500 million barrels. Can you give any color on the initial indications of where you may be falling in that range? And then maybe talk about when we might see first production and potential monetization of those barrels?

Blake, yes, I would say on a gross basis, all those ranges are still accurate that we had at that time. You see a lot of news come out of wells there, up and down. I think you kind of walk through a stage of gross net pay start and you start hearing about cumulative tests among many reservoirs, and you ultimately get into oil in plays. This is the fractured carbonate Middle East-type reservoir, so it's -- if you notice, the other folks that are slightly ahead of us in the play, it's a good while to get to reserves, so it's going to be good a while to get to the reserves as well. Plus we need to float-test this well and have no oil back to surface in the float test. We're in the middle of running the perforated guns on the first one. It will be about 6 weeks there and I anticipated that it would be a slow March there where we go, as I said, to pay cumulative testing in the [indiscernible] oil in plays. I know these things to determine if we have a discovery to the size. The monetization there is a long-term issue that's political. You saw where KRG was off-production for several months now. Today, they say they're going back on production into the Iraqi-Turkey pipeline system. There's a lot of discussion in KRG about pipelines to join that, major pipeline that has a lot of capacity. There's also a talk over the pipeline inside at KRG. But clearly, over time, those 2 regimes have to agree on a monetization until they do, won't be able to do so. We don't have this in our plan in any other growth plan that was shown. It's an exploration well and will remain so. The monetization is clear, but I still take a little solace in that super majors follow us in every day, so the insight of the large value and size of the structures along with the ability to ultimately monetize it among these 2 governments.

Our next question comes from Pavel Molchanov with Raymond James. Pavel Molchanov - Raymond James & Associates, Inc., Research Division: One high-level one, if I may. You mentioned your new entry into Vietnam. By my count, that's country #11 for you outside North America. Do you have any concerns that you may be getting a little bit stretched too thin just in a geographical sense?

No, not really. This is Roger. I thought it was ten, so you helped me out up to 11 there for me. We're a strong player in Southeast Asia, big office in Kuala Lumpur, also in Jakarta. We're used to working in that regions. We've been working there for a very long time to get these concessions. What we're trying to do in Vietnam is mimic, if you will, our success in Malaysia, but we start with the shallow water block and hopefully obtain some deepwater acreage and try to go into shallow deepwater like we were before. I don't see the country count getting much higher because we're continuing to work in the same places, but it is right at the cusp of where we probably want to go, but I'm not concerned with adding a new country in that particular region. Pavel Molchanov - Raymond James & Associates, Inc., Research Division: Okay. And then of the countries that you currently have in the portfolio, you're obviously not rolling in all of them, Suriname, I think comes to mind. Any of them that you're considering perhaps for an exit?

No, some of them still have commitments wells here and there. And we usually -- if we have commitments, so you have to do the commitment stage and then make a decision on leaving the block in Suriname. We're shooting seismic there this year. We're excited about that block. It's a lot of interest from farming nearby. So we're active there and active in the other countries that you had up for me and happy to have them all, but it's not going into a much longer list than you prescribed.

Our next question comes from Ray Deacon with Brean Murray.

I was wondering if I could ask a question about the Eagle Ford and Tilden results to date and how you would compare returns to what you've seen in Karnes.

This is Roger, Ray. I would say that Karnes, of course, is one of the sweet spot of Eagle Ford. We are seeing some -- in Tilden, the way we described it, Tilden is quite big. We have a North Tilden which has a shallower Eagle Ford, so you have well of lower IP. We haven't -- still economic, of course, but we haven't drilled a lot of wells in that area, but if you talk about the need of the Tilden area, which is near many of our competitors, I would say it has strong returns as well, slightly subordinate to Karnes, but in pretty good shape there. We also have -- I mean, you have shallower Eagle Ford naturally. You drill the wells $0.5 million faster, and we're happy about expanding out of Karnes and we've been doing well away from Karnes and that's one of the areas we're focused. If you look at our rig plans for the rest of the year where we carried 10 rigs, we'll have 3 at Karnes, 2 out in Catarina West and the 5 rigs in Tilden. And so most stuff in there in a small area. That's heavily competitive area, competitors all around us. So I see it to be a very nice growth area for us and also an area that we have a higher working interest in Karnes. Raymond J. Deacon - Brean Murray, Carret & Co., LLC, Research Division: Got it. And I guess 2 more quick ones. Do you see any opportunity to test the pure salt on your acreage? Do you think it's present? And how long before you expect to see some signs of success on the polymer injection at Seal?

Let me take the Seal first. We've done a polymer injection pilot and it's been very, very good. Now we're going with phasing in of 10 wells at a time and 20 wells in different phases. It will take maybe 8 or 9 months to see impact there, but it's doing very good in the pilot. Moving down to [indiscernible] back in the Eagle Ford, we do see opportunity for [indiscernible] players nearby [indiscernible] to have it. We may see another play there and we think we would have an opportunity to participate in it. We have planned next year working in [indiscernible]. This year, we going to try to drill the wells if we have enough time [indiscernible] for the time being.

The next question comes from Mark Caruso with Millenium Partners.

Steve, this question, more of a strategic question and a follow-up on the retail. One of the hurdles in the past when we talked about has been the cash flows and the dividend, and we've got a great dividend update last night and I want to kind of get your thoughts on that going forward. Is it better to keep everything integrated given the cash flows of retail? Can it be strong at times to help fund the dividend or can both entities pay dividends separately? And just want to see how that influences your thoughts. Steven A. Cossé: Well, let me say, first of all, I wouldn't prejudge the -- if we do decide to spin, I wouldn't prejudge that spin codes board on dividends, but I think the -- our capability to continue our capital expenditure program post-spin as well as the dividend are eminently sustainable.

It appears there are no further questions at this time. I would like to turn the conference over to Mr. Cossé for any additional or closing remarks. Steven A. Cossé: Thank you very much, everyone, for participating in the conference call. As you may have detected Roger and I are very, very new to this process and if we stumbled a bit, please forgive us. I hope we'll get better as we get on with the process. And once again, thank you all for participating. Thank you.

That concludes today's conference. Thank you for your participation.