Ladies and gentlemen, good afternoon. Welcome to the Murphy Oil Corporation First Quarter 2011 Earnings Conference Call. Please note today's conference is being recorded. And now I'd 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; and Barry Jeffery, Director of 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 first 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.

Thank you, Barry. Net income in the first quarter of 2011 was $268.9 million or $1.38 per diluted share. This compares to net income in the first quarter of 2010 of $148.9 million or $0.77 per diluted share. There were no unusual items of significance in either period, but the 2010 quarter did include $41.3 million or $0.21 per diluted share of after-tax losses on transactions denominated in foreign currencies compared to an after-tax loss of $1.1 million of similar transactions in the 2011 quarter. Taking a look at income by segment. In the E&P [exploration and production] segment, net income in the first quarter of 2011 was $260.4 million compared to net income in the first quarter of last year of $247 million. Higher E&P earnings for 2011 were primarily attributable to higher average crude oil sales prices, which were up about 34%, but higher natural gas sales volumes also contributed. Unfavorable variances in the current quarter include a lower crude oil sales volumes, higher exploration expenses and higher workover costs at the Kikeh field in Malaysia. Crude oil, condensate and gas liquids production for the quarter averaged approximately 113,300 barrels per day compared to approximately 139,000 barrels per day in 2010. The decrease was mostly attributable to a lower gross volume at Kikeh due to wells shut in awaiting workovers and in the Gulf of Mexico due to delays in permitting. Natural gas volumes, however, were a quarterly company record of 413 million cubic feet per day in the first quarter of 2011 compared to 343 million cubic feet in last year's quarter, an increase of over 20%. This increase was due to the startup of production at the Tupper West area in British Columbia and higher volumes at Tupper Main, offshore Malaysia and at the Mondo Northwest…

Kevin, thanks a lot. First quarter witnessed strong oil price moves with benchmark WTI [West Texas Intermediate] rising from $85 a barrel in January to $105 in late March. Dated Brent trended higher and sustained at least a $10 premium as WTI remained landlocked and regionalized. Global events such as the discontent in North Africa and the Middle East, as well as tragic events in Japan, all helped support global crude's rise. Most signs point to this being the new acceptable level. And as such, we have raised our price outlook to near $90 for the remainder of the year. Natural gas prices in North America continue to languish near $4, and we see this trend continuing through 2011, absent a better supply and demand balance. Business in the Gulf of Mexico remains challenged with a lack of permits. The level and type of recent issues, while noteworthy, don't highlight a clear and predictable path forward. We have one permit for a reentry at our Front Runner field and are hopeful others will come later in the year. Onshore U.S. and globally, our business remains very active. We have one exploration well currently drilling in Indonesia at the Lengkuas prospect and expect to be at final target by month end. We recently completed our first phase exploration in Suriname, where the Aracari well was plugged and abandoned. The bulk of our exploration work begins midyear, and we look forward to an active program with significant targets being tested in several countries. In our Upstream business, global production for the first quarter averaged 182,154 barrels equivalent per day, slightly below our first quarter guidance of 185,000 barrels of oil equivalent per day. This variance of 2,846 barrels oil equivalent per day is mainly attributable to start-up and commissioning delays with the…

[Operator Instructions] And our first caller is at Raymond James, Pavel Molchanov. Pavel Molchanov - Raymond James & Associates, Inc.: 2 quick ones, if I may. First, on Suriname, following the 2 dry holes, just curious kind of what the road map is going forward. Back to seismic? Or if you're giving up on it altogether.

Okay. Suriname, the first 2 wells both found reservoir where we thought they would find it. We did have oil shows above the reservoir in the first well, which gave us encouragement for the charge story. The second well found a, quite a limey or a carbonate reservoir package, which didn't have shows. So our questions in our mind today are, do we have a seal issue, an up-dip seal issue on the subprospects that we've drilled; and a question of trap integrity, so that they had trapped the hydrocarbon. So we're -- as I mentioned in my comments, we're going to rerank and rerisk here and look to see what our program should be next year. As far as being down on Suriname, it's very difficult when you're in the exploration business to get down and drilling dry holes because most programs drill more dry holes than successes. And I think you have to look at it as a program. We still see some fundamental support for exploring in Suriname, but we need some time to put these well results into context. Pavel Molchanov - Raymond James & Associates, Inc.: Okay, great. And then just follow-up on Kurdistan. Of course, we've seen a few of your competitors have some nice announcements that are recently -- just an update on that would be helpful.

Yes, we were -- the second block, we should be very close to announcing here. It's a nonoperated position. The first block that we announced, we're in the process of getting our seismic done this year. And I'm hopeful that we can get on and get a well drilled as soon as possible. The street address is very good. Other people and some results, particularly recently, have shown that, that area is quite prospective. So we're pretty excited about that. We see long-term some of the issues in Kurdistan being worked out in terms of getting export, but we think we're into that play at about the right time.

Let's move on to Howard Weil with -- I'm sorry at Howard Weil, Blake Fernandez.

David, you mentioned Kikeh and the recompletion work. I'm sorry if I missed this, but I'm just trying to get a feel. Do you have a sense of when we may get production back to kind of normalized levels, if you will?

Yes, let me take that and go a couple of ways here, Blake. Let me talk about Kikeh and where we're at and what we're doing. And then let's address the production, where we are today and where we're going to be at the end of the year, and then address this 200,000 number, if I could.

Yes, absolutely.

So if you bear with me, I'll kind of step you through some things that I think are important to note. Kikeh's produced about 120 million barrels. We have a lot of good information on the reservoirs and on the field and feel very, very strongly that it's a great field. The issue that we have had over the last 6 months is really to do with fines migration in our shallowest reservoir, and not all wells in that reservoir. What's happening is today, we have 3 wells in that shallow reservoir shut in. 3 wells are on the Dry Tree Unit and one is a subsea well, and I'll get back to that in a minute as to why I distinguished those 2. Those wells last year were producing at pretty nice rates. As they started to make these fines, we choked them back. One of the wells, we replaced the screen and had some pretty encouraging results. We subsequently did the same with the other 2 wells. What we found out was that those screens replacement were kind of a temporary fix. And so when we closed those 3 wells in, they were collectively making about 17,000 barrels a day. Back last year when they didn't have a fines issue, they were making 37,000 barrels a day. The other interesting thing to note is when the wells were shut in, 2 of the wells had a water cut very low, one was less than 2% and one was 4% and the other one was a little over 40%. And so we don't think it's a recovery from the well, we think it's an ability to manage these fines migrating through the screens and into the wellbore and then up into the surface equipment. And with some investigative work,…

No, that's perfect. Thank you -- thank you very much for the comprehensive answer. The second one -- and I'll just keep a quick one here. The Southern Alberta wells, do you have any details you'd like to share on the IP rates or EURs you're seeing?

Blake, really -- not really because we're still trying to lease, but I will tell you that, and I've said this before, if we can get wells that are better than 200 barrels a day to start, then I would regard that as being good. And I would say that the first 2 wells would get into that bucket. What we need to do, we see some performance from those wells from initial flow and then put a pump on and see how they produce. But kind of the keys for me looking at the play are: do we have water, which we don't. And the second thing, to see what kind of pressure is in the play. And I think where water is, is going to be patchy. So some parts of the geography's going to have water and some not. I think that's one risk factor. And the second one is some areas are going to have more overpressure than others. And so you would expect better rates in some areas than others. So I would say at this early stage, from what we've seen, it's encouraging. But it's not an Eagle Ford, I will say that.

Okay, perfect. I'll leave it there. Thank you.

Let's go on to Evan Calio with Morgan Stanley.

David, just a follow-up on your Kikeh comments, and thank you for those comments. I think you mentioned 3 wells shut in, you currently -- and I just wondered, was that incremental from last quarter? It was one well and then -- and just further, I mean could all the data that you've collected in the process here, I mean has that changed in any way, shape or form, either your view on the productive capacity of Kikeh? And I have a follow-on.

Yes, let me kind of weave that and kind of bring it all together. The shallow reservoir section is clearly not as compacted as the deeper reservoirs, which are performing well. And we drilled these wells at quite a steep angle through them. And so what we've experienced, and I think what we see here is that the fines material within that reservoir section does migrate if you don't stop it from getting into the wellbore initially with our expandable screens. Probably because they were packed off against that formation, they work quite well. And we did not get any fines into the wells until later in life. One of the questions that we had was the encroachment of water, part and parcel of this fines migration because in lots of cases, it is. But as I mentioned in my comments, we have a couple of wells where we're getting fines where the water cuts are 2% and 4%. And so we think it's more to do with the stability of the interface between the formation and the screen, and that's really where we're kind of focused on. And so that takes us into, do we think that the wells and the reserves and the et cetera, are going to be less than we thought. And the simple answer is no, we don't. We have enough productive history here and enough people looking at it, both internally and externally, to feel very comfortable about the field. In order to be more comfortable as to where the rate is going to go, we got to get this gravel pack technique working here in this particular reservoir. And then coming back, we'll be able to tell you, hey, it's worked, and this is how it's worked and better be able to judge what rates we're looking at. But exiting the year close to 90,000 barrels a day, we feel pretty good about that, of course. And we think the techniques that we're going to apply will work based on what we've seen so far.

Got it. Can you also give us an update -- your acreage position, any update in Eagle Ford or Alberta, Bakken? I know you mentioned that you're looking to accumulate, position more acreage there and kind of when you may be in a position on the Exshaw to share data with the Street, when do you expect that?

Yes, I think we need to run, other than to -- in answer to Blake's question, I'd rather not go any further there. I'd like to add some more acreage, but I would say I'm not so sure that I would add the acreage in the places that I was going to want to add the acreage prior to the well results. And really that's the whole purpose of drilling these 6 wells is to get comfortable as to what the risk factors are and where the trends are going. So we have north of 150,000 acres now in that play, and I see us being able to add some more. But in light of well information that we've got now and other wells that we're going to drill, it may change a little bit the direction of where we would pick up acreage. In terms of the Eagle Ford, it's another one of these resource plays for us where I like to add acreage all the time, produce all the time and drill all the time and keep getting smarter and smarter. The well results in Karnes are very good, and I'm very happy where we are. If I added up, just before this call, how much we could produce in Karnes, it's over 4,000 barrels a day net, but we're not producing that yet. An issue there is takeaway capacity. And we, like lots of other people in the play, don't have the piping yet in place to be able to do that. But the well result's pretty nice, and so I feel very bullish about that. And I think we're getting a better and better understanding. We do have dedicated takeaway capacity lined up now. We do have basically 1.5 frac crews dedicated to us. As I mentioned, we're ramping up our rig count this year, and I think that's very important for us to do that. And so I think we'll get past this bottleneck, if you will, in the Eagle Ford and do pretty nice. And by the end of the year, producing 9,000 to 11,000 barrels, I think is very, very doable. I think the well stock will be there. It will really be the issue of offtake, and we're working that hard.

And do you have any acreage update from the quarter?

We're in the -- approaching 250,000 acres bigger for Eagle Ford. I've kind of put it that way.

Moving on, let's go to Ray Deacon, Pritchard Capital Partners.

David, I was just curious, where do you think you can get your -- I know it's very early in the Alberta Bakken, but is $3 million to $4 million a reasonable level for wells there, do you think?

For well cost? The ones that we've been drilling now, we've had a lot of science, and we talked about this before and -- cutting cores, drilling them straight and vertical and then turning with a heel tie [ph]. That's not the most efficient way, but our guys have done a great job with the first couple of wells and they've gone really, really well. So I think if we line this out, so we just drilled the well horizontal, straight into the Bakken, I think well costs here should be quite attractive. So yes, I see a good way forward there.

Okay, great. Yes, and just a -- just curious, so you have -- in the Eagle Ford, do you have a dedicated frac crew? Is that going to cover kind of all your activity, or just Karnes, I guess? And I was just curious about what kind of cost inflation you're seeing too?

Yes, I should say, "Golly, I wish costs were lower." So I'll say that now. But yes, it's one dedicated crew and then effectively, half of another crew. And we clearly need to get our production up. And we're having such good results there in the Karnes area that having the crew stay there as long as we can and work off the backlog of wells -- I think we have 9 left to frac in that area, is what we want to do. And we're active in the Tilden area and we're active in Dimmit area. So as we move these crews, it's less efficient. So I'd like to keep them in the same place if possible.

Got it. Great, thanks. And I guess just any big picture thoughts on Canadian gas exports from the West Coast to Asia? Does that feel like it's getting more -- to be more of a near-term thing or...

I've still struggled with the idea that we have $100-plus oil and $4 gas just on a Btu basis and then we see what prices for gas are going, indexed to oil on the Pacific market. So I think export of gas from the U.S. and Canada is -- makes a lot of sense. I think the issue up on the west coast of Canada, as best as I can tell, is all about permitting and regulatory part and pipelining, all that stuff. But I think probably the business case is pretty solid. I think that there is probably a good case to be made, export of gas from the U.S. side, particularly in the Gulf Coast. And I think another business case, a solid case can be made there, too. I think that if I was to look at where we are today at $4 gas, we're probably going to move up, but I don't know when the time to move up. But I think export of gas is going to be a big part of that.

[Operator Instructions] Let's move on to Kate Minyard with JPMorgan.

Just a couple of quick questions. On the Eagle Ford, you've got 15 producing wells, can you update us with either a total cost or average cost per well across the 15?

Well, it varies quite a lot because some of the wells were drilled differently. So they were drilled with a science in mind and some were drilled straight as kind of "Let's see what we can drill them for and produce." But we're in the $3.5 million, $4 million drill and $4 million, $5 million frac complete number, Kate. I think those are probably pretty fair numbers.

Okay, and does the frac and complete include tie-in costs or are those minimal?

Yes, those are minimal, but they're in that number.

Okay, great. And then on the outlook to 2015, of the 300,000 barrels per day of production by 2015, how much of that is already sanctioned? And then what portion of the non-sanctioned part might be dependent on exploration success?

Yes, we have, through -- next week actually, in our Analyst Meeting here ahead of our AGM, really going focus in on that because I think it's important for people to appreciate the resource and reserve base that we have. Of the 300,000 number, a very small percent, so 10% or less, is requiring any exploration success. The bulk of it is on projects we already have, we've already discovered or getting ready to sanction or have acreage in resource plays here in the U.S. and Canada that we feel very comfortable about. So the whole goal, in my view and what I want people to come away from after next week -- without stealing Roger Jenkins' thunder, who runs that business, is pretty comfortable from going where we are to that number in 2015 and not relying on exploration to get us there, but have the option of exploration to add to that. And so that's kind of where we're at.

Okay, great. And then if I could just sneak a final one in. On the 14 stores that you've added year-to-date in the Retail business, what was the cost to add those? And what's the kind of breakout between kiosks and more of the kind of full-fledged convenience stores? And I'll leave it there.

It's a good question. I think the number's about $1.8 million on average. And if -- I'm shooting off the top of my head, which is dangerous here, but the bulk of those were express sites and not kiosk sites. I think 2 or 3 were kiosks and the rest were full size. [indiscernible] have stayed on top of that, Kate. That's the cost for the stores and then whatever the real estate is, is on top of that.

A question now from The Benchmark Company, Mark Gilman.

A couple of things. You've achieved some improved fiscal terms in the Congo. I wonder if you could give me some idea what that entails.

Well, Mark, looking at our fiscal terms, first of all, our threshold price changed dramatically. It was -- $26.50 was our index price. That has now gone to $48. So you should see a reduction of supplemental payments there, especially as we get into more of the profit phase versus the cost phase there. Also, our cost recovery threshold did change as well. So it should move our entitlement, which was for a 50% working interest in the low 30s, it will now move it up towards 40% with the new terms.

No change in profit splits, Mindy?

No, just a change in the cost recovery threshold. No change in the profit split.

Okay. Then David, could you repeat what the exit rates are in Azurite that you talked about? You were going a little too fast for me at that point.

Okay, Mark. Sorry, I didn't mean to speed. I figured you were writing it down as fast as I was saying it. Gross will be 22,000, currently at 14.5 [indiscernible].

And the net?

Net, when we leave the year, it will be about 8,200 net.

Okay. And David, let me go back to the Kikeh thing for just a sec. It sounds to me -- and forgive my lay interpretation and assessment, is that what we've got here is unexpected unconsolidated sands, which I guess from prior experience, does tend to lead to lower recovery factors. And I guess I'm a bit puzzled that in this instance, you don't believe that's true.

Mark, I don't know what your frame of kind of reference there is. What I'm saying is that with this particular shallow reservoir, the migration of these fines into the wellbore is causing us to choke them back, not because we can't make high rates and not because we don't think we can ultimately recover what we've got. It's the mechanical dealing with fine material up in our production equipment. As I mentioned in my comments, 2 of these wells have water cuts: one, less than 2%; one, 4%. So it's really difficult for me to see that we're going to have a reduced ultimate recovery here. What we first need to do was stop fines migration into the wellbore so that we can allow these wells to continue producing, and they've been producing very well in the past. So that's really the issue for us. I think, in my mind, I wouldn't make the jump that you've made into reduced recovery at all.

Okay. David, is there a location yet established for the CA-1 well in Brunei?

We're working with our partners there for CA-1 and for CA-2. And I don't think the final location has been approved by all partners for CA-1 or CA-2. We are talking on CA-2 about bringing that well into this year, which I regard as being very positive. But that's kind of work in progress with both, Mark.

Do you have any idea what relationship that CA-1 well might bear to the [indiscernible] discovery?

Mark, I don't know what the final location is. So I can't make any comment about geography on it.

Okay. Just one final one for me. I was just looking at the Sarawak gas price realizations and had been under the impression, David, that the fiscal arrangement on the gas there was something akin to a netback, yet in spite of rising prices for the Japan crude cocktail, better part of the last year and a half, the price -- your realization seems to have peaked out in the 550, 570 kind of range. Can help understand that?

The way that the formula works, without going into great details here, is that based on what is realized from the LNG export, we receive a factor of that realized price. And so a lot of it will depend on the types of contracts, the types of prices received, some of which includes spot cargoes. But it is tied to what is actually received, multiplied by a factor, that's what we can...

So there were no changes whatsoever in the formula or the mechanism?

No, sir.

With no further questions in the queue, I would like to turn the conference back over to the company for any additional or closing remarks.

I appreciate everybody being on the call today. Those of you that are coming to El Dorado here next week, we look forward to receiving you. And if you don't come, we look forward to talking to you again at next quarter's results. Thanks a lot, and have a good day.

This does conclude our audio conference for today. We appreciate your participation. Have a great day.