Thank you very much for joining, ladies and gentlemen, and welcome to the Murphy Oil Corporation Second Quarter 2011 Earnings Conference Call. Today's call is being recorded. I would now like to turn the call over to Mr. David Wood, President and Chief Executive Officer. Please go ahead, sir.

Thank you, 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 will 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 second 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. Our net income for the second quarter of 2011 was $311.6 million or $1.60 per diluted share. That compares to net income for the second quarter of last year of $272.3 million or $1.41 per diluted share. For the 6 months ending June of 2011, we had net income of $580.5 million or $2.98 per diluted share. That compares to net income for the 6 months of last year of $421.2 million, $2.18 per diluted share. The 2011 quarter and year-to-date results included an after-tax gain of $13.1 million or $0.07 per diluted share from the sale of natural gas storage assets in Spain. There were no unusual items of real significance in the 2010 quarter or for the 2010 6-month period. Looking at income by segment. In the E&P segment for the second quarter of 2011, we had income of $243.3 million and compares to net income of the second quarter of last year of $219.1 million. Higher E&P earnings for the 2011 quarter were primarily attributable to higher crude oil and natural gas price realizations. Crude oil and gas liquids production for the current quarter was approximately 94,200 barrels per day as compared to approximately 132,000 barrels per day in the corresponding 2010 quarter, with the decrease mostly attributable to lower production at Kikeh, where several wells were shut in awaiting rig workovers. Natural gas sales volumes were a company record, 457 million cubic feet a day in the second quarter of 2011 compared to 348 million cubic feet a day in the second quarter of last year. This increase was attributable to the continued ramp-up of production at Tupper in British Columbia and higher production from fields offshore in Sarawak, Malaysia. In R&M segment, net income for the second quarter of 2011 was $91.7 million compared to the net income in the second quarter of last year of $83.8 million. Earnings increase in the 2011 quarter was attributable to operations in the U.S., where we experienced improved refining and retail margins. Additionally, both U.S. refineries ran well during the quarter, processing a company record of just 170,500 barrels of crude oil per day. In the corporate segment, net charges for the -- in the 2011 second quarter were $23.4 million compared to net charges of $30.6 million in the second quarter of last year. The lower charge is primarily related to favorable impact on transactions denominated in foreign currencies. As of June 30, 2011, Murphy's long-term debt amounted to just under $1.2 billion, approximately 11.8% of total capital employed. During the quarter, the $350 million 10-year bond maturing May 1 of next year was reclassified at the current maturity. Cash and short-term investments at the end of June totaled a little over $1.3 billion. And with that, I'll turn it over to Dave.

Thanks, Kevin. Second quarter crude oil prices peaked in late April, with WTI approaching $115 a barrel before backing off into the $90 range by the end of June. Dated Brent continued to outpace WTI, with the spread surpassing $20 in June and averaging $15 for the quarter, as WTI remained somewhat landlocked and regionalized. Concerns over a slowing U.S. economic recovery coupled with a lower demand led to the commodity selloff. The IEA's decision to release 60 million barrels of crude and products to the market from strategic petroleum reserves had a momentary effect on prices even as they had already started to fall. That impact seems to have passed, and we continue to forecast $95 WTI for the remainder of the year. North American natural gas prices remained rangebound near $4, and we see this trend continuing throughout 2011. Consistent with our plans, we have managed to sell approximately half of our Tupper gas production for the remainder of the year at $4.90, helping to bolster returns from that business. In the Gulf of Mexico, the permitting process remains uncertain. We did obtain a single reentry permit for a well at Front Runner last quarter and have just received a second permit there. Efforts to gain additional permits at Thunder Hawk are ongoing but unlikely to be timely enough for us to see work there this year. Our exploration program is off to a slow start in 2011 with now only 2 wells having reached TD. [ph] The second exploration well, this one drilled on the Lengkuas prospect in the Semai II block offshore West Papua Indonesia, found the primary objective -- Jurassic sands. Logging showed them to be hydrocarbon bearing, but wireline MDTs were unable to confirm this. We have expensed this as a dry hole but…

[Operator Instructions] And we will go first to Evan Calio of Morgan Stanley.

David, can you walk us through the 220,000 barrel a day Q4 exit rate guidance? I know it's almost 30% higher than 2Q and 3Q, and maybe run asset-by-asset to get to that current exit growth rate. I mean, I'd presume the primary element is Kikeh, but it must include a host of other lifts.

Yes, Evan, it does. Let me kind of get you there. So from the 164,000 number to get to the 220,000, I'll run down kind of an order of increase here. Kikeh will be just under 29,000 barrels at -- and there, we've got basically 6 wells: 2 new subsurface wells and -- 2 new subsea wells and 4 workovers. And I'll talk about Kikeh in -- at the end of this so that it kind of gets everybody up to date. Tupper and Tupper West led, about 9,500 barrels a day. We've got some 13 additional wells coming on. Eagle Ford, a little over 6,000 barrels a day. We have new wells coming on there. And just under -- right under 4,000 barrels a day at Seal. We have some additional wells coming on there. And then there's less downtime at Terra Nova and Syncrude or again, just under 4,000. The U.K. and Hibernia, again, less downtime, 2,800 in the U.K. and 1,600 in Hibernia. And so when you add all that up with a little bit of oil production from South Alberta, you end up at the 220,000 exit rate.

And then on the -- you had given a walk-through. But Kikeh, I mean, I guess just with the first recompletion finished and 2 rigs doing workovers, what gives you the confidence that you can reach those levels, particularly in light of some -- a string of production disappointments from Kikeh and even from just 90 days ago?

Yes. Let me kind of -- I'm sure this question is probably -- have -- other people have too. So let me kind of walk through Kikeh. Today, Kikeh's producing 58,206 barrels of oil and 72.6 million cubic feet.

That's gross?

Yes, these are gross numbers on here. And we currently have 3 of the shallow horizon wells shut in. And in addition, there's a fourth well that is really curtailed, because it has a mechanical -- a near-surface mechanical problem. And in total, those 4 wells were producing 29,000 barrels of oil immediately prior to their problems. And so all of those wells will be worked over this year, plus we have 2 new subsea wells to be brought on. And you got to remember that Kikeh is not fully developed yet, and we still have wells as part of the field development plan to be drilled. Right now, we have one rig, it's at Semai, working in the field on one of the shut-in wells. And a second well will come and be put on spar and operation in late August. And so our goal is to reach 80,000 barrels of oil a day in November. And the actual year end rate will depend on well timing, and we've just assumed that it will be at that 80,000 barrel a day rate. So let me recap just -- I want to make sure that people understand from what we talked about last time on the call and this call is the -- is kind of what the changes are. Essentially, last call, we had a fourth shallow horizon producer that was shut in due to fines production as a precaution. We have worked over one well. It's been on production for a couple of months. It's making over 7,000 barrels a day and has no issue. So that open hole gravel pack is working nicely. Unfortunately, at the time -- in the same timeframe but not related, we had a well that was producing over 10,000 barrels a day that developed a mechanical problem. And we have -- we have it choked back, so it's making a small amount now. And so that well has to be worked over. So we, in effect, took a step forward and a step back during the time that we were conducting that workover operation. And so what gets us from where we are today to the 80,000 barrels a day is basically 6 wells: the 4 wells that are being worked over; 3 with the recompletion gravel packs; 1 a mechanical well; and then 2 new subsurface wells, subsea wells that will be done as part of the original field development plan for Kikeh.

And with the fourth shallow well that you mentioned that you shut in because it began producing the fine sands, does that mean that -- I mean, do you anticipate having to recomplete most of the Kikeh wells? Or -- because it's been -- kind of went from 1 to 3 to 4 here. How should we think about that?

Yes. Last time we spoke, there was 3, and there has been 1more. And these are related to the shallow horizons. We've not seen the issue with the deeper horizons, Evan. So we're going forward with these 4 wells and recomplete.

And how many other wells are on the shallow horizon that are not shut in and not yet producing sands?

One, probably one. Now 2 of the new -- just to be clear, 2 of the new wells that we're drilling are going to be in the shallow horizon. But clearly, given our experience here, we'll just go ahead and either crack pack or gravel pack them at the beginning without going through the expandable screen steps. So as I said, the whole field is not fully developed. These 2 new wells, which are going to be in the shallow horizons, we'll complete differently than we originally did with the others.

And now, we will go to Joe Citarrella with Goldman Sachs.

My question is on the Eagle Ford. You mentioned that results have been exceeding your expectations. I'm wondering if you can update us a little bit more on your non-Karnes Country acreage in particular, specifically thinking the Tilden area. Last, I think, we've heard, you're expecting results there to be fairly similar to Karnes. First, is there any change to your thought process there? And second, it would also be great to get just general thoughts on what drives your confidence in the well results and IPs you're expecting across your position in the play.

Yes, Joe. We're concentrating our development in the Karnes area, because we sanctioned that area first. So we have more data there, more productive history there. And what we've seen is as we've brought these wells on -- and we don't open them up wide now. We tend to choke them back. And what we've seen as we've had these wells on for longer periods of time, is well performance when you choke the wells back is better. So we actually beat the tight curve quite handily. These wells tend to be relatively flat. We're a little younger in our program in the Tilden area, but we see nice well results there also. And I think overall, that whole swath that runs down from Karnes into Tilden are going to be somewhat similar and probably part of the sweet spot of the overall play. And so we've been very, very pleased. We have taken the opportunity here to pick up some additional acreage. We're now closer to 250,000 acres in the play. That's something that we've said all along, that we want to identify opportunities. And so those areas are the ones that we're looking at to add to the play. So I'd rather not get into specifics of individual wells, because we have that as a strategy, but I will tell you that well results are nicely beating our expectations.

That's helpful. And then just on that point, on the additional acreage acquisitions, are those sort of bolt-ons to some of your existing areas? Or any indication what counties or what areas those additional acres are in?

Yes. They are in the oil play, and they are around areas that we are already active. And beyond that, I'll just be mum.

Now moving on, we will go take a question from Paul Sankey with Deutsche Bank.

The dry hole that you had in the quarter, can you talk a little bit about the overall expense of that, David? I think it was -- it seems very high, and I wondered why it had been drilled for so long. And very specifically, I just wondered if there's any additional expense to you in Q3. But if you could just talk a little bit more in general terms about went on, that would be helpful.

Yes. The Lengkuas well came in pretty much as prognosed. It just took longer to get there. We had extra strings of pipe set, and we had a section that was very difficult to drill and took much longer. So gross cost for the well was close to $200 million. It was significantly higher than when we started. That rig has now moved off, and so it's gone to somebody else. So I think we're done as far as our cost go. The well did have pretty decent oil and gas shows. We did log what we -- a log analyst would say looked like pay on log. [ph] We couldn't get a sample, a wireline sample. We think the zone is tight, but that was not definitive. So I view that as being something to follow on. It's certainly a dry hole, but I think there's a glint of future promise and more work needed on that well and more work needed on the block. So that's kind of where we are. We're trying to take all the data that we've got and reevaluate and high grade where we want to go next on that one.

Right. And so there's no further expense for the July period?

There's just a further $1 million net to Murphy expense. That will be in the third quarter.

Understood. David, in the exploration portfolio, I assume -- clearly, not in Iraq, but I assume there's nothing else of that scale of risk reward, if you like, in the next year-or-so program that you talked about.

No. I wouldn't say that. If you look here, we've got -- and so it's going to depend, when wells start to when they finish, as to whether they're in this year or not. But if I kind of look at the 18-months exploration program, we should probably spud 10 wells between now and the end of the year. If I look at the most notable, clearly in Brunei, both in the CA-2 and the CA-1 block, these are big, high-potential oil type prospects. We have a couple of blocks in Iraq and Kurdistan, one in Central Dohuk, where we've just finished 2D seismic, and I'm making drilling plans there. And then one within a non-operated block in Bharanam [ph] and which should spud a well right at the end of the year. And then we're going to do some drilling in Malaysia, probably in Block H, and we're working on our timing now. So I think we have a number of pretty good-sized prospects to be started this year. As I look into next year, I see things carrying on in Brunei, pretty active program in both blocks. I see a sub-salt well in Congo, which we're waiting on the rig to come back. The Ocean Confidence, that is off working for somebody else, should be back to us about the end of the year. We have a sub-salt well in there for a very big nice target. So I think the quality of the program is -- as we've talked about before, I think we've had a little bit of time slide here to the right, but this is pretty attractive, mainly in oil-based prospects within the program.

And I guess the exploration track record, looking back, has had its knocks. What makes you more confident, going forward, that you should continue pursuing an exploration strategy this aggressive given the struggles that you've had over the past few years?

Yes. I've been doing this for 30-something years, and you go in streaks and patches. I think one thing you have to recognize, that these are programs. And we spend about the same amount of money here each year, and I'm comfortable with that level of spend. Where we've been working on is the quality of prospects we've been drilling. The unfortunate thing for us is these last 6 months, we haven't been drilling many wells. And so we tend to go through the highs and lows of individual wells and less focused on the quality of the program. I think as we start to get into a more active part of the second half of this year and next year, with the quality of prospects that we've got in basins that have already been proven, I feel very, very good about the program that we've got. So I think exploration for us is -- it's part and parcel of our growth story, but today, it's not the only part of our growth story. 2, 3 years ago, we didn't have a resource program like we do today. And going forward, our resource program is very good and very important. I'm really excited about what we've seen at Seal. I'm very happy with where we are with Tupper. Of course, I'd like higher gas prices. But I'm very happy subsurface. And I think Eagle Ford is a home run for us. Looking at our Eagle Ford position now, we probably have 2,500 locations, probably have 500-plus million barrels and probably 4 TCF there, recoverable, and feel real comfortable with that. And so I think that provides a very nice balance, and perhaps missed by many, in our overall program. So the balance there, the predictability from that, I think, overall, helps us a lot.

Great. The final question for me. You mentioned that you had -- I think you said restructured regarding your target setting, if you like, and you've now given some very specific targets for this year. What did you mean by restructuring? And what is the difference between this new sets of targets and the methodology and the confidence you have in them against the prior system?

Yes. In all things, when you don't do things right once, you can look at it. And when you don't do it right the second time, you got to change something. So we have lots of smart capable folks in our organization, and -- that want to succeed and want to deliver. So we've changed the emphasis, changed some of the processes, changed some of the ways that we look at things. And the end result of that is this revised production guidance for this year. And so I feel very good about the buy-in, and I feel very good about where we're at. But the proof is going to be in the pudding going forward. But I think that -- I think we're off to a good start. If I look at production today -- or here we are in July, as a month to kind of be a gauge, we've been on a per-barrel day 161,000 to as high as 184,000. And this last week, we've averaged 177,000 barrels of oil equivalent a day. Against the target we set for the quarter, I think that's in the right direction. So the things that we've done and the things that we've seen so far here, and almost the first month gone of this quarter, I think, is directionally correct. So -- but the proof will be as we go forward. I don't think it's an issue of the quality of the resources so much. I think it's how we've been going about the process. That's why I feel very good about the 300,000-barrel target by 2015, which is from things that we already have. So -- but we'll have this call at the third quarter, and Paul, I'm happy for you to ask me again.

And moving on, we will take a question from Blake Fernandez with Howard Weil.

David, a real quick one with regard to Evan's question on Kikeh. I know you gave a comprehensive answer. I just wanted to confirm, if I could, that still no concerns with regard to the reservoir or ultimate recovery?

These issues that we've been dealing with are to do with these fines migration and to this one mechanical issue. So we've not seen anything that would cause us to change any of that. Like in this first well that had a workover, it's been producing without incidents here for 2 months -- I think kind of supports that. We still have some other wells to drill in the field, as I mentioned when I was addressing Evan's question. So I mean we're still working along, drilling wells and drilling out the field.

Okay. That's great. Secondly, with regard to third quarter guidance, I thought maybe it would have been a bit higher. I'm trying to gauge, do you have any hurricane risk factored into that number?

This is Barry, Blake. In terms of the guidance number here, if you look at the production forecast at 173,000, I think Dave did a good job of showing you where we're at today and getting comfortable with where that is. So they've got their regular conservatism in for Gulf of Mexico. But if you need any specifics in terms of where the number is itself, you've got some higher workover costs in terms of OpEx that are going to bring some extra OpEx here, about $30 million. That's about $0.15 a share. And then you've got some U.K. tax impact, so there's some catch-up. And then third quarter view of the U.K. tax, that's about $15 million or $0.08 a share. And then you've got some downstream earnings that are lower by about $30 million or $0.15 a share. So that kind of takes you from where we were in Q2 to where we're forecasting, the $1.10 midrange here in Q3.

Okay, great. Last question for you. David, I know in the past, you had kind of maintained a very flexible balance sheet with the idea that if you had some success in the high impact exploration front, you wanted to have some dry powder to develop that. Obviously, unfortunately, that hasn't really come to fruition. So I'm just curious, has the appetite for M&A increased now?

I think we've been looking at M&A all along, and if we can find some things that fit, we will do it. I mean, we've picked up some additional Eagle Ford acreage here, and that fits. I would like to, as we've talked about before, add something meaty to our program, and so we have an effort underway to do that. I do believe that we will be successful in exploration, and maybe in something on the cheap that I'm looking at that I may rank differently than others, but that's the nature of exploration. But yes, we're a looker, and hopefully, we'll be a buyer.

Moving on, we will go to Pavel Molchanov with Raymond James. Pavel Molchanov - Raymond James & Associates, Inc.: Is it fair to say that the sale of the U.K. assets has proven more challenging than the sale of your domestic refineries?

Pavel, no, I wouldn't say that. I think what we've seen here in the U.S. -- I'll give my comments. We've seen the crack spreads improve throughout the year. And so when you're negotiating to sell something in that environment, things tend to take a little longer. And here, recently, we've actually seen more players come to the table because of that external situation. And of course, whenever you do that, things take longer. In the U.K. specifically, we had hoped to be able to do that as one package. But we've realized now that we need to look and talk to companies, and there's several interested for each individual package. And so that's really the change, from our perspective. Pavel Molchanov - Raymond James & Associates, Inc.: Okay. And just as a follow-up on that, you've said at the beginning of your downstream divestiture program that you intend to keep the U.S. retail assets for the time being. Have you had any parties that are inquiring about purchasing that perhaps in conjunction with Louisiana or separately?

We really like our U.S. retail, and I've talked before about how we like that business and want to grow that business. And at some point in time, not now, we'll look to see how that future of that business would be. But there's people who approach us about buying all sorts of things that we have, and I'm not particularly a motivated seller. So I'm happy to keep the retail business, a great business, growing well and has a very, very bright future. So I'm selling the refineries here in the U.S. I'm selling the stuff in the U.K., and that's the plan.

[Operator Instructions] We will go to Evan with Morgan Stanley again.

Yes, just a couple of follow-ups, guys. Do you guys have a rig lined up to commence block CA-2 exploration? Is that a handoff of the Total rig?

No. It'll be a different rig, but it's not finalized yet, Evan. But it's kind of looking at a early fourth quarter spud would be my guess. So don't tie me down to that but -- getting hold of rigs, but that's kind of the timeline we're looking at.

Is anything lined up for the 2 Congo wells also planned this year?

Well, what we're looking at is the Ocean Confidence, which we took out of the Gulf and sent to Africa. It's using -- being used by somebody else. We want to get that rig back, and we're really excited about this sub-salt prospects that we have, and that rig would be ideal. So when that rig comes back to us, that's when we'll drill, and it's probably going to be the end of this year.

Is that -- isn't there another -- doesn't that person have another slot option for that rig, maybe, to come back later than you expect?

It's possible. But for our planning purposes here, we're assuming that we're going to get it by the end of the year.

Okay. Any -- do you share any pre-drill estimates? I know you shared in the past on the -- at least on your kind of more near-term prospects on a P50 basis?

No. You can end up with some really big numbers. Some people counsel me to say I should say everything's just 100 million barrels and be safe that way, but we don't run that way. I think the big prospects, clearly, on a gross basis are going to be in Brunei and sub-salt Congo and in Iraq, in both Central Dohuk and the Bharanam [ph] block. I mean, these are all very big oily prospects and multi-hundred-million barrel individually. So I would categorize them that way.

Good, good. And just a follow-up on Blake's question. I mean, any color on the use of proceeds for just the first refining sale? I mean, you're going to have -- I guess, late 3Q, early 4Q, you get the proceeds from that sale. Any debt paydown or what the kind of immediate -- the uses might be?

What I'd like to do is get the second one done, and I don't feel in any rush to spend the money. Mindy will tell me that she'll take the money from us and pay down some debt, and I'm happy for her to do that. But I think we've got a program here to identify things that we want to buy. And hopefully, in the next year, we'll be able to close on some of those. So I don't feel in a rush -- that we have to rush to spend the proceeds.

There's been a lot of activity also with the juniors in Canada and kind of unnamed major partners. Any comments on how your footprint or attractiveness of terms you're seeing for land positions kind of in and around your Exshaw/Upper Bakken stuff?

I would say, as far as the Exshaw goes, I'm reasonably pleased at the very beginning of a play. I don't think we know where the sweet spots are yet. Hence we've stepped up our program this year from 6 wells to 8 wells. We've got a couple of wells that kind of fit what we thought they should be. We've got one well that we're looking at. We've got another well to bring on, and we got a drill [ph] in another part of our acreage footprint that we don't know anything about yet. So early days, some encouragement. We clearly need to get our cost down. I would still pick up acreage up there, but I think we need to get a little technically smarter to understand where the sweet spots are going to be. The other areas around Tupper, around Seal, around Eagle Ford -- our strategy all along is as our knowledge grows and as opportunities arise and as we find them, we will add acreage. So I'm actively trying to get more acreage in all of those plays.

And you also, I think, made reference to a new, kind of unconventional play. But when should we expect to kind of hear maybe the identity of that? Or did I miss -- just miss hearing that?

No. You deliberately didn't miss it, because I didn't say it. What we like to do is get into some of these plays relatively early and relatively inexpensively. And this is one of those, we think. It is very early days. We're below, in terms of acreage acquired, what I think is critical mass. And for us, that's about 150,000 acres. So we don't have that amount of acreage accumulated yet. Once we get to that level, then I think we'll be perhaps comfortable to talk about it. And so that will be either this year or early next year, I think, is kind of where we get to. But it just demonstrates, Evan, that what we want to have is we want to have a certain value and amount of resource play in our program. And adding another play further out in time helps us have that continuum. And so that's what we're trying to do.

And moving on, we'll go to Lyn Donn [ph] with Bloomberg News.

I just had a couple of questions on the Meraux refinery. I know that the company had said a little earlier that the flooding did not affect the production there at all. Just wanted to confirm that, also see if the maintenance schedule before the SSCU [ph] and the Achalasian [ph] unit over there is still on for January.

No. We did not get any impact from flooding, which I think we've talked about before. And I don't have anything in front of me that has any different schedule than what you talked about with, so...

Moving on, we will go to Monroe Helm with Barrow Hanley.

I'm just wondering, when you get out to the 300,000 barrel a day target, what would that imply for Kikeh's gross production at that point in time?

In 2015, Monroe, Kikeh will be much smaller than it is now. And actually, Eagle Ford will be larger than Kikeh. The Block K production, which will include Kikeh plus Siakap North plus Kakap, is really what we'll be looking at. So there'll be more production actually coming from Siakap North and Kakap, and Kikeh will just be a part of that. And as we've talked about before, we're looking to keep that production on a net basis from Block K, which includes all those 3 fields, as flat as possible. So it should, overall, for that block, be flat to where it is now or where it's going to be this year. But it won't just be from the Kikeh field.

Okay. Since you talked about the increased importance of the Eagle Ford at that point in time, can you kind of fill in the blanks as to what the other 80,000 barrels a day is, from the 220,000 you expect to be at the end of this year?

I don't have anything right in front of me that steps you up there. But Monroe, I can get -- if you call in to Barry, he'll -- we've done -- we've talked about that before at the AGM. I don't want to mis-talk here. I don't have my curve in front of me. But if you give Barry a call, he'll break it down for you.

Okay. But any event, it doesn't include any exploration success at this...

No. No, Monroe, it does not, and that's why we feel pretty good about where we're going. And so if you were to ask the question, "So what risks are there in that number?" then I would say gas price. If gas prices were $4 or less by 2013 or '14, I may be not so enthusiastic to allow gas to grow very much. But other than that, I think the acreage footprint's in place, and I think we have the opportunities to get there. And exploration would just be a nice plus on top of that.

[Operator Instructions] And we'll go to Mark Gilman with The Benchmark Company.

David, I thought I heard the word, when you were going through the upstream, reorganization, which in my mind implies personnel. Were there any personnel changes that you've been making recently as part of this change in process?

We've moved some people around. It's part of career development for folks and part of trying to make our business better. We have a lot of smart capable people here, Mark, and we're just trying to make sure we're doing the best that we can here. And so that's what it is. We have now kind of a North American piece of business. We've operationally done a great job in developing our Tupper resource. We want to bring some smarts and expertise from that learning curve down to Eagle Ford. That's one case. We think that how you frac wells and how you drill wells has a degree of universality, and so we have some talented folks in our company and want to get them involved in other projects.

Okay. David, I believe in the last call, we talked about the level to which, on a gross basis, Eagle -- Kikeh would recover that a 90,000 a day figure was utilized. Am I comparing apples and oranges by comparing that 90,000 to the 80,000?

The 90,000 was the exit rate at the end of the year so end of December. The number I gave you was a November rate. And I said that the assumption was I would hold flat and not have any additional wells come on and contribute by the end of the year. And so it's an apples-apples, because I'm not looking at the same timeline, Mark. The real issue, going forward, with new people and new processes, is to make sure that we're comfortable with the targets that we're setting. And timing of wells, is clearly end-of-year thing, can get you a number one way or the other. So real comfortable at the 80,000 number in November. I don't quite know where we'll be at December.

Okay. What happened with the fourth well at Azurite? And what do you think has plateaued? Now it's increasingly looking like plateau might have been achieved already, and it's in decline.

Azurite's been a little bit of a surprise subsurface. This last well, we did this -- let me get this right. We did a sidetrack and the pay looked good, had to another sidetrack to make sure it was in connection with a water injection well. And when we got the well on, we didn't see the performance that we expected. And so now we're in the process of reevaluating that. We believe that the oil in place number isn't the question. It's the connectivity between water injection and the producer. I think that's the issue. So it's a question for us today, and we're working it today.

So it's a recovery factor issue?

Well, I can't answer that, Mark, until we get to understand why, based on our -- up to drilling the well work, we thought we were drilling a well in the right place related connectivity-wise to a water injector that we thought was in the right place. We just have some more work to do there.

David, you referenced in your comments takeaway capacity constraints in the Eagle Ford. Are you addressing that through choking the wells back? Or how was -- is there a capacity number in place that would suggest capacity currently is greater than the 7,200 you're producing?

Oh, I think we've got full wells that are producers that we don't have on. So unconstrained, I think we could produce more. We have a number of field batteries being developed. We have a number of pipelines. This is not a "all flow into one place" sort of development. And so I think that the offtake capacity is going to have to be improved through this year and into next year for us and for a number of other players to start removing some of the bottlenecks. And so we got some growing pains, and I think the infrastructure in the areas that we're developing have some growing pains. But I'm pleased to see that there's commitments being made for new offtake arrangements and pipelines. So I think all this will be worked out here, certainly into next year.

David, of the exploration program in place, are any of the prospects stratigraphic as opposed to structural?

Let me see. Probably the one in South Barito in Indonesia is, and everything else that we're dealing with is a bump.

I'm sorry, everything else is...

A bump. Structural.

Okay. And just a final word for me on the U.K. tax. I'm a little bit confused as to what the $15 million charge in the third quarter is. Is the -- is that a deferred tax remeasurement? Is it the prior period impact? Or is it the current period impact? Kevin, maybe you can clarify that for me?

This is John. It is a -- it is an adjustment of our deferred tax liabilities going forward due to the 12% increase in rate, Mark.

Well, don't you have to book a prior period, given that the effective date is March?

Oh, you're talking about adjusting prior period numbers?

Well, no. The effective date of the increase, John, is March.

That's correct.

You haven't been accruing it, I don't think. Have you?

No. No, but you book it as -- when it's enacted, Mark. And it was enacted in July. So you take your adjustment when it's enacted officially by the U.S. -- U.K. government, and that happened in July.

Mark, the $15 million gets us up-to-date through September.

So it includes both deferred tax remeasurement and the prior period?

Yes. I mean, the $15 million includes the impacts from March 24. Don't hold me to that date. I believe that was the day. But it does include some impacts of that 12% increase on pretax earnings from March 24 forward.

Okay, but it does not include...

[indiscernible] a deferred tax liability adjustment.

Okay. But it does not include the normal third quarter impact.

No.

Was that a no? I'm sorry, I didn't hear you.

That's a no.

And moving on, we will go to Paul Sankey with Deutsche Bank.

David, there's been a direct press speculation about a potential merger or takeover by Husky with you guys. Are you in any whole company negotiations for Murphy to either merge or sell itself to Husky or anyone else?

Paul, we don't make any comments on market rumors.

[Operator Instructions] And it appears that we have no further questions at this time.

Operator, thanks very much. I appreciate everybody calling in and look forward to our third quarter call later in the year. Thank you.

Thank you very much. Well, again, ladies and gentlemen, that does conclude today's conference.