Murphy Oil Corp (MUR) 2005 Q4 法說會逐字稿

Good afternoon, ladies and gentlemen. And welcome to the Murphy Oil Corporation fourth quarter earnings release conference call. At this time all participants are in a listen-only mode. [OPERATOR INSTRUCTIONS] As a reminder, this conference is being recorded today, Thursday, February 2nd, 2006. I would now like to turn the conference over to Mr. Claiborne Deming, President and Chief Executive Officer. Please go ahead, sir.

Thank you. I'm joined by John Eckart, our Controller, Kevin Fitzgerald, and Treasurer, and Dory Stiles, from our Investor Relations department. I will turn it over to Kevin at this time.

Thanks, Claiborne. I would like to welcome everybody to the call. We'll follow our usual format for today's call. John will begin with a brief review of the fourth quarter, Claiborne will follow with an operations update, and then we'll take your questions. Please keep in mind that some of the comments made during this call will be considered forward-looking statements. As such, no assurances can be given these events will occur, or that the projections will be attained. There are a variety of factors that may cause actual results to differ. Many of these have been identified in Murphy's January 1997 Form 8-K filed with the SEC. With that said, I'll turn it over to John.

Thank you very much, Kevin. I will start by commenting on net income totals for the fourth quarter of '05 that amounted to $154.6 million. That's $0.82 a share, compared to fourth quarter '04, where we made $134.5 million, $0.72 a share, and that prior year included $0.01 from discontinued operations. The fourth quarter of each year included some income tax adjustments. 2004 included benefits of about $21 million, mostly from the settlement of prior period U.S. tax matters. About half of this benefit was in the corporate area, and the bulk of the rest of it is in E&P segment. In 2004, however, we had net tax charges, including a $27.5 million expense for withholding tax on a dividend paid to the parent company by a Canadian subsidiary. In the fourth quarter of '05, it included costs associated with hurricane of about $33 million. These amounts include additional insurance costs, post hurricanes Katrina and Rita, plus uninsured repair costs and ongoing payroll and other costs at the Meraux refinery plant while it is down for repairs. We expect to incur additional costs in 2006, some of which will likely not be recoverable from insurance. And I want to spend a minute talking about our property insurance coverage.

We have 2 layers of coverage for our property damage at Meraux. The primary coverage is with a company called Oil Insurance Limited, more commonly called O.I.L. As a company, O.I.L. has a $1 billion limit on a loss for a single event, and they have informed us, and other insured companies, that they have exceeded the $1 billion limit on Katrina, and therefore we should expect to recover no more than 50% on Katrina claims. Above O.I.L. we have commercial coverage for the Meraux refinery. This policy appears, however, to have limits on claims for flood damages at a $50 million level. Estimates of the cost to repair Meraux, we've had a couple of different estimates made, and they've come in as high as $200 million for the repairs. If these repair costs are this high, and O.I.L. pays 50%, we could face up to a $50 million out of pocket expense, most of which we would expect to incur in the first quarter of '06, but possibly some could fall into the second quarter of '06. Why in 2006 instead of 2005 would we have these costs? Essentially, the accounting rules do not permit to us accrue expense costs for repairs in advance of them being incurred, and so those will be 2006 costs if they're not covered by insurance.

Let me talk for a minute about segment results. Our E&P results in the fourth quarter of '05 were $128 million. That's down 24 million from the 152 we made last year in the fourth quarter. Our refining and marketing made 31 million, slightly up from the fourth quarter of '04. And our corporate net costs were about $5.5 million of net after tax costs, versus 51 million in the fourth quarter of '04. E&P is down due to higher dry hole costs, and higher 3-D seismic costs. Dry holes were $62 million in the '05 quarter, versus 10 million in the '04 quarter. With most of the increase in '05 due to drilling, unsuccessful drilling, offshore peninsular Malaysia and in the Republic of Conga. Also the tax benefits in this E&P segment were lower in 2005 than in '04, because in 2004 we had significant benefits in Malaysia of $31 million, for recognition of expected realization of deferred tax assets for Block K.

In the fourth quarter of '05, oil and gas prices were higher, so we benefited from those. They partially offset the dry holes. But our production was down, following Katrina and Rita. We were off about 14,000 barrels a day of oil, and about 40 million cubic feet a day of gas in the Gulf. In Ecuador, we made up about 663,000 barrels of the shortfall that we did not receive in the second half of '04, as we got a settlement with our operator, and we're still working on settlement with the 2 other non-operators in Block 16.

R&M, our refining and marketing profits were up about $1 million. The U.K. was stronger by about 2 million, and the U.S. was down slightly. Our results in retail business were strong, but no production from the Meraux refinery in the fourth quarter, and higher repair and insurance costs more than offset the higher retail results. Corporate activities, as I previously mentioned, are a much smaller after tax cost in the '05 period. We had about $10 million in income tax benefits, while the 2004 had tax charges mostly related to the withholding tax on the Canadian dividend, previously mentioned. 2004 also had large foreign exchange losses while 2005 did not. And 2005 also had less interest cost, due to lower average borrowing and more of our interest being capitalized into development projects. And with that, I would like to turn it back over to Claiborne for his comments.

Thank you. I will now cover production, upstream developments, upcoming exploration wells, and then downstream. In production, Gulf production is back up to 37,000 barrel equivalents a day. Tahoe did not come back as well as we would have liked, and a recompletion should take place at this field at midyear. Seventeen Hands, where we have a three-eighths interest, comes on in April or May, at between 40 to 60 million cubic feet a day. Otherwise, there is no particular issues.

In developments, Kikeh remains on schedule for second half 2007 startup. There's no new news at Kakap, Kamunsu, Kenarong, Pertang, or Thunder Hawk. Given recent dry holes in the Congo, we are hard at reviewing Azurite to determine if we will seek sanction to develop at mid-year. In drilling in the U.S., we are on location at Thunder Hawk # 2, in Mississippi Canyon Block 734. Once done, we will then move to the Thunderbird prospect at Mississippi Canyon Block 819, where we have a three-eighths interest, to drill a wildcat, and then move to the Thunder Ridge prospect in Mississippi Canyon Block 736, where we also have a three-eighths interest for another Miocene wildcat. All of these locate around Thunder Horse in the Boarshead Basin. After Thunder Ridge, we will either move back to Thunder Hawk to drill development wells, or to Green Canyon to drill additional Miocene wildcats.

In the Congo, we clearly had disappointing results. It happens, but it's modestly unusual, to make a discovery, followed by 4 dry holes. We are now 1 for 5 in the Basin, and have to better appreciate timing of traps, versus charge, before we can proceed. There's plenty of structure and there's plenty of reservoir. In any event, we have 1.8 million largely unexplored acres, and 8 years left on the term of the 2 leases. We'll get back to work.

In Malaysia and peninsular Malaysia similarly, we were unsuccessful in this drilling campaign. We drilled 4-way dip structures in a prolific basin, after shooting the first ever 3-D on the acreage. Unfortunately, we found oil charge but poor reservoir. We took cores and will look to see if the reservoir can be stimulated, [Labeer] in particular, but felt it realistic to take dry hole charges in the meantime. In Sarawak, we continue to successfully drill natural gas prospects in the southern part of Block 309, where we have 85% interest, most recently Marapu and [Sorenda]. We are moving up to Block 311, where we also have an 85% interest, to drill a large 10,000-acre plus prospect called [Mahkota], followed by a nearby prospect, called [Maharani]. In addition, an oil prospect named [Permas], will also be drilled in Block 311.

In Sabah, we renewed Block K, now 1 million acres, and signed a new Block P, formerly part of Block K and also 1 million acres, on January 24th. The areas around Kikeh and Kakap Kamunsu were retained at 80%, and the balance of Block K is at 60%. The new Block P is now 60% Murphy, and still operated by us. We plan 2 deepwater Sabah wells, the first, [Shrumbuh], which will be drilled on Block H, where we have an 80% interest, located right on the Block P boundary, and [Rohu], which is Block P, and south and east of Shrumbuh, near Block G.

And downstream, at Meraux, we have right at 1,000 contractors on site. Startup will commence beginning of the second quarter. Its superior margins are around break-even. Milford Haven is modestly profitable, with most of the margin at retail right now. U.S. retail margins, after a nicely profitable fourth quarter and year, have suffered in the first quarter, as wholesale gasoline prices sharply followed crude prices up.

As most of you know, a Class was certified earlier this week in the lawsuit concerning the spill from Meraux after Katrina. The area certified covers about 2 square miles, versus what we think the impacted area is, of about 1 square mile. The judge made it clear that damage from the oil spill would have to be proved before awards would be made, even if you are in the Class area. We have settled so far with a bit over 2,000 residences impacted by the spill, and the new area has up to 6,000 residences, including the 2,000. As per our 8-K filing, we continue to believe that we are adequately insured, and there is no material adverse impact on the Company.

In closing, obviously, Peninsula Malaysia and Congo were disappointing drilling efforts. Just as clearly, our business model exposes us to just this type of event, and we would be less than candid to say, over the lapse of time, this would it not happen. It can happen and did it. Conversely, our experience has been that if you drill in prolific basins, with the best technology and with the most experienced people pulling the trigger, then material discoveries occur. We have a very full drilling schedule for the balance of the year, and are exposed to multihundred million barrel opportunities. We'll take questions now.

Thank you, sir. Ladies and gentlemen, at this time we will begin the question-and-answer session. [OPERATOR INSTRUCTIONS] Nikki Decker, Bear Stearns.

Good afternoon, gentlemen. My question is on the Sabah acreage. Why were you only awarded a part of the acreage, of your original acreage? And why Block P? It occurs to me that it's not really adjacent to anything. Although, Claiborne, I guess your comment indicated that it is adjacent to Block H. But what specifically about Block P made that the Block -- the acreage that was awarded to you?

Okay. To start out why not the whole block, because it is an intensely competitive and changed world in the last year. And getting acreage is much harder, renewing acreage is much harder. And that's just the way the world is. And we are extremely pleased to have gotten what we got, at the interest that we got. If you're coming in for the first time into Malaysia, and got this acreage, you would be over the top. And so I think that is the way to look at it. And that's certainly the way that I look at it.

Why Block P? The northern part of the block has not been -- of the old Block K, has not been extensively drilled. And we, because we had previously owned , had shot a lot of 3-D seismic over the whole block, and had concluded that that part of the block had a better opportunity to get sand deposition close to -- probably not quite as significant as the southern part of the block where Kikeh is, but certainly more than in the middle part of the block. And so we think that the northern part of the block has got a fair amount of prospectivity and has identified pretty large structures. And so we think that we've acquired potentially significant acreage. The drill bit will tell us, and we'll know some news here in the first 6 months of the year, but certainly something that we're looking forward to drilling.

And, Claiborne, just to follow up. The other 2 pieces of the old Block K are -- will they be awarded to somebody else? Or will the government sort of hang on to this acreage for now?

I don't know, but my general appreciation is that they'll probably put them on the market.

Okay. Thanks a lot.

Arjun Murti, Goldman Sachs.

Thanks. Claiborne, this may be partly a follow-up to the last question. On Block H you all have drilled, I think, a couple of wells which weren't successful. Can you talk about what it is you've learned that's making you re-encouraged to go after this latest prospect, and does some of the Shell success, which I think is in that area, tie into that?

Arjun, the first well we drilled on H was [Minkus], in the middle of the block, and it was a big structure. But [wildcatty max], dry hole. We went over and drilled [Penoga], which is closer to the acreage we're going to drill now. Nice structure, good amplitude. The amplitude ended up being a facies change, and not sand. We are -- these 2 prospects,[Trumbu] and Rohu, and Rohu in particular, are on trend with reported, well, disclosed discoveries that Shell's made in Block G. So we think that the risk of sand is -- not being present is probably pretty small. Big structures, clearly they're pretty nice amplitudes, that conform to structure, and so just the way we would risk it a bit, I think you've got a greater opportunity for gas here than you would down on the southern part of the block near Kikeh and Kakap Kamunsu. But I think that there's also a very reasonable chance for oil, which was certainly discovered, we think,south of us, or [inaudible]. And so, big structures, good amplitudes, on trend, prolific basin. We think we're in a sand fairway. I think that gives us some confidence.

Claiborne, after these first two wells in deepwater Malaysia, should we expect more wells in the first half, or your usual hiatus, and you'll come back in the second half and do more exploration?

We're going to take the Rover and drill development wells into the -- probably the back end of the third quarter. And then we have an opportunity to take it off of Kikeh, and drill some more exploration wells. So we'll see what happens here, and we'll review it, and then once we get off Kikeh for 1 or 2 wells in the third quarter, we'll pursue some more wildcats, I would suspect.

And then just finally, any plans to follow up on any of the syn bed discoveries, like [Sinungan] and some of the others?

Not now, not now. But we have them, and we have them at the 80% interest. And we certainly -- or most of them at the 80% interest, and we certainly have them in our portfolio. I think is a good way to say it. And we'll drill these 2. We'll probably drill a few more wildcats in Kikeh and P&H. And then we'll probably turn our eyes to those.

Great. Thank you very much.

Steve Enger, Petrie Parkman & Co.

Hi, guys. Couple more things on exploration. Claiborne, I think you're drilling another well in Peninsular Malaysia now. What's the play there vis-a-vis the other 4 that haven't worked?

Steve, it's nearer Pertang and Kenarong, and its more equivalent to those. The other 2 were unrelated to Kenarong and Pertang, and they were more 4-way dips in the middle of a basin, especially the 312, to go for what really has traditionally worked in the basin. And this is playing off the success we had at Kenarong and Pertang. It's called [Janira].

Okay And any expectation on fluid content, oil and gas, both, or -- ?

It's got shots for both.

Okay. Reserve replacement, Claiborne, can you give us any qualitative assessment at this point? I know there was a comment by another company about Hibernia that maybe was pretty optimistic. Do you think there's a big increment there? And how do you see that overall?

It's going to be a weak year. The only big discovery was Asarite early in the year. And we're going to have to look really hard at development options there. We've got Kikeh out there, we've got Kakap out there, we've got Kenarong, Pertang out there, we've got Thunder Hawk out there, we've got [inaudible] out there. So there's this -- and then a number successes in Sarawak. So we've just got this extremely large backlog.

'06 should be real good?

Well, you know, given the way the world works, old Claiborne is in no hurry to book reserves, and that's just the way the world's worked out. And so the rules are pretty specific when you book, and there's no incentive at all to try to be a hero. So I just decided a year, year and a half ago, just to book it when they're ready to be booked. So if we had something last year we had discovered, and which was sanctioned in the year, when I think that Asarite had that possibility. But it's not. It's going to have to be studied harder and decided at mid-year by our board. And there's no big lumps out there. Now, Hibernia, Terra Nova have a lot of upside for us. Right now at Hibernia, we booked our share of that 675 million barrels. We reckon most likely, is about 1.1 billion recoverable. You know, you can grow that. Terra Nova, we've booked our share of 266. We'd say the most likely ultimate is around 366. And there's room for that to grow. I'm not so sure we'll book much of that this year, but we haven't made all those decisions yet, either. But that's kind of the order of magnitude.

Still a lot of up side. Okay. And one last kind of technical thing on the Shrumbu and Roju wells. It seems to me the key as you go outboard is that you do have sand. So if Shell has found sand, isn't that still a significant risk as you go outboard? Because it seems like the significant sand deposition has kind of gotten out right to the edge of some of those blocks?

It is, it's real significant, Steve. But we have some good news there. And you have to harken back to our first dry hole in Malaysia, Bagang, which is right in this area. And significantly further outboard than in particular Roju. Had lots of sand. And we reckoned at the time it had a lot of gas charge, and we figured could it have more gas charge if we really wanted to explore it deeper. If you recall on that well, we parted a riser after we had seen about half of what we wanted to see. And we had to take about a 2 month vacation while we got that repaired, our contractor did. So we never fully explored it. What we did see, had a lot of sand with gas charge.

Okay. Do you have some evidence that sand has made it out that far away from the -- ?

Yes. It's a risk. Clearly, in the Kikeh area, it's -- once you got outside of Kikeh, Kikeh Kacheel, that clearly ended up being a problem. And I think that's still a risk here, but it's probably mitigated by the fact that we have a lot of control, or at least 1 well bore with control outboard that's got a lot of sand in it.

Okay. All right. Thanks a lot.

Jennifer Rowland, JP Morgan.

Thanks. First I have a follow-up on the reserve replacement. Any indication yet on what you might decide to do with Front Runner?

Jennifer what we said last time, is we're moving some reserves from proved to probable, until we can get our hands on it. So that's what we're going to do in the short term. I don't have a number before you to give you, but that's going to be our first move. We've got some plans to do some recompletions this year. Need to see how that works. It's a reservoir continuity problem. And so we need to see if we can access some bigger reservoirs. A lot of reservoirs up hole from where we're currently producing. We need to finish producing where we are now, and then get up hole, which we'd like to do, but we can't do it until the MMS lets us deplete what we're currently doing, just for good oil field practice purposes. And so in the course of the year, we'll have more news on it.

Okay. And then the Pertang and Kenarong development plan, when should we hear about that?

We filed an area development plan in October of last year, and what the PETRONAS, who is our ultimate buyer, monopoly buyer of the gas, advised us that there's an '08, '09 window for sales. And so that's what we're currently shooting for, something around that particular window. So there's no change there from what I said at the last conference call.

Okay. And then just lastly, do you have any guidance for '06 CapEx?

No, we haven't released that yet, but we will. We will. It'll be, I think we ended up this year 1.3. A little over 1.3. And we'll be north of that. 1.5 is a safe number, but we'll give you more specifics.

Okay. Great. Thank you.

Gene Gillespie, Howard Weil.

Claiborne, in view of the fact that you're going to have to give up the rig that's currently on the Asurite appraisal, and rig availability is tight in west Africa, what's the next move in the Congo?

Well, I kind of want to give the rig up. For awhile, you can only beat that dead horse -- no, all kidding aside. There are -- we've got a couple of plays. We need to understand our Miocene channel play a little bit better. We obviously drilled prospects close to Asurite, on the theory that we'll have a hub there, even if it wouldn't fill the spilled prospects nearby, we'd tie back to Asurite. So we limited ourselves to the -- I don't know what the circumference was, but say 10 miles away, roughly. And so we need to understand that we identified initially 20 plus prospect on the southern block. The others, better, and do we understand them better. That's clearly a 6 month project. So I could see at the end of the year starting to look for rigs. And what we found is that there are rigs of opportunity out there, if you want them. Now, you have to pay up. And say you're looking at $300,000 a day, I would guess, plus or minus to get them, but that's just the market.

The northern block, we shot some 2-D, kind of densely spaced 2-D last year, and it's a different play up there. It's called an Albian rapted play, which is presalt, and it's got some come-on. We rated it riskier at the outset, 1 in 6, not 1 in 3, but there's some big fields up there that pay in that particular sand. And then there's a sub-salt play. But those wells start getting really expensive. At today's rig rates, to drill a sub-salt well up in that northern block is probably a 30 to $40 million endeavor. And that would cause you some pause there. So I'm not so sure we'll do the deeper play, but if that shallower play, we might. And that's only in 200 meters of water on the northern block. So, this is a long explanation to say that there's more rigs available at that water depth, in that part of the world than for deep water. So that may be an area that we pursue. But we need to do a bit more mapping.

Anything to talk about in the Floyd Shale?

No.

Thank you.

Mark Gilman, Benchmark Group.

Claiborne, good afternoon.

Hey, Mark.

Can you give us a little bit of an update on where the Thunder Hawk well drilling is currently, and where we go from here, depending upon results?

Mark, tide hole, no. But once it's done, we're going to, as I suggested earlier, we're going to drill 2 wildcats, 1 at Thunderbird, and 1 at Thunder Ridge, all in the Boarshead Basin, and see what we can do. Same group owns them. And their one, Thunderbird is probably the same size as Thunder -- yes, Thunder Hawk. Thunder Ridge has got a bit more scope on it. A bit riskier. There's a trap leak risk there, a bit more, but good scope.

I guess speaking Claiborne specifically in terms of sanctioning Thunder Hawk, and is it fair to say that that's in some way contingent upon the results of Thunderbird or Thunder Ridge?

No. Our current view is that we'll be in a position to sanction it this year. If we had success there, would that influence how we go? More likely than not, it would.

Okay. Can -- anything you can say about unitization with respect to Kakap Kamunsu?

No.

Any discussions underway?

Oh, heavens. I can say that. Of course.

Okay. 1 final one if I could. The 3-D seismic that apparently you're shooting currently off eastern Canada, is that the Laurentian?

Yes, that's farmed out to do. But, yes. That's correct.

You farmed out your interest?

Yes, it's part of a deal that we made -- you're taxing me here -- about a year ago. And we had some companies come in and drill some 3-D for us. I think I'm right. I'm getting some looks that say that maybe I'm not. But I know that we had a company that came in, and it was BHP that farmed into the acreage about a year ago, to earn some of our position. And they did part of it by shooting 3-D, I think. I think. If I'm wrong, I'll correct it, but that's my current view.

Okay. Thanks a lot, Claiborne.

Bruce Lanni, A.G. Edwards.

Just a couple quick questions on the downstream, then 1on the Congo. Meraux refinery, it's going to more or less be a cold start. So what do you expect as far as the ramp-up to full capacity at Meraux, as far as the timing goes?

Oh, boy, that's a good question, or a hard question. I think that you'll see the alky the last to come up, because it's got the most work to do. Will start coming up in early April. You'll see everything ready, save the hydrocracker, which may be a week or 10 days later on the alky, which is maybe a week or 10 days or 2 weeks after the hydrocracker. So you'll see us coming up the whole month of April. I would think that's a reasonable expectation.

Okay. That sounds about right. And as far as on the marketing side right now, yes, obviously margins have come in fairly sharply. Are you guys still in the positive as far as the retail goes?

Yes. But it was a cruel January. But we're certainly in positive margins. But it was about as ugly as the fourth quarter was good for awhile.

Sure. No, I saw that. Then the Congo Asurite. Is it still possible that can be a stand-alone development project?

Yes, it is. The issue that we're going to have to fight, internally, is there's been a ton of inflation in development projects in the last year. And the things you would use to develop it, which are likely FPSOs, and maybe a dry tree unit, are expensive. And so, whereas before I would have thought, yes, that's doable, now I think we're going to have to be a bit more creative. So we'll have to fight that one internally before we decide to go to our Board to recommend it. And that's how it's structured inside, because there will be some proponents in our Company who want to develop it. And I'll have to say, gee is this the right way for us to spend our money? And if they convince me, then I'll try to convince our board.

No, I fully understand.That makes sense. When you talk about the inflation, is there a way that you can kind of gauge to tell us what range you saw last year between inflation, service cost increases, material costs, all that? Did it hit you by about 10%? 20%? Do you have a range you can give us?

Well, I mean, to the extent you have to drill development wells, which, of course, you would, rigs which were $150,000 a day, are 375 to 400 in some instances. So you can double or triple, two and a half times what you were going to do. And for example at Kikeh, the drilling piece, development wells is half of all the costs in the field. Wouldn't be quite that much at Asurite, because it's a smaller field. But that is [inaudible]. FPSOs, steel's gone up, not to the extent that drilling rig costs have gone up, but they've gone up 40%, 30%. I'd have to get a guy smarter than me in our Company to tell me, but certainly that order of magnitude. And so between drilling costs going up, and fabrication costs, we've got an issue. And I'd be less than candid if I didn't forewarn people. And we always wanted additional fields, by the way. But with the cost increase and no nearby additional fields, we just to have struggle with it.

Fully understandable. Well, thanks a lot.

Ken Carroll, Johnson Rice & Company.

Just a quick question. Kind of detail your guidance of 115,000 barrel equivalents a day for Q1. How do we get to that number? If you look at your Q4 of a little over 103,000 barrel equivalents a day, add back in the hurricane volumes, it gets you more to the 120, 125 range. But what's pulling us down to 115 in Q1? Is it the Tahoe issue that's part of it?

Ken, I don't really have a comparison to give you, but I can give you a quick rundown of what we're seeing for the first quarter.

That would be great. Thanks.

Gas side, U.S. gas 55, Canada about 10, and the U.K. about 10. On oil, U.S., you got about 27,000. Canadian heavy about 15. East coast of Canada about 22. Crude 10. U.K. 8. Ecuador 8.5 to 9, and Malaysia, 11. That should get you roughly to 115.

I'm sorry, I missed the Malaysia number there, Kevin.

11.

11. Got you. Okay, great. Thanks, guys.

That should get you closer to 115.

Okay.

John Herrlin, Merrill Lynch.

Couple quick ones. With a lot of the dry holes you discussed more or less not having the right kind of reservoir or sand issues, are you going to have to, or have you contemplated changing your seismic acquisition model at all?

John, in Peninsular Malaysia, actually we're going to shoot some more seismic. And we've put that on hold until we can better understand. We were really taken aback, I have to tell you, by what happened, and didn't really anticipate it. So we -- .

Is it a parameter issue, or is it just the lack of control and the fact that you're wildcatting?

There's pretty good control, and there are some tight wells in the basin. We just didn't assume that we'd find so many. Especially the first one, Labeer, looked outstanding, I have to tell you, and then it slowly unfolded as being pretty tight. And we side tracked it and still found tight sands. But it's large and it's oil charged. And that one needs probably some more attention in particular. We don't know if it's related to depth where you get tighter. We don't think it is. We don't know if it's a temperature issue. We don't know -- we're scratching our heads. Sorry.

What about the Congo?

Congo isn't reservoir. The reservoir is gorgeous, the structure is gorgeous. It's charge.

Okay. That's fine. 2 other quick ones. Equipment, no real issues in terms of access. You want to lay off the Congo rig, but you're fine in Malaysia and the Gulf of Mexico?

Correct. We have 2 deep water rigs under long term contract.

Okay. And then lastly, Gulf of Mexico, a lot of leases are getting relinquished. Are you going to get more aggressive in the next bid rounds, or same as always?

Boy, I think you'll see some big numbers coming up. I don't know what we'll do, but certainly the industry is flush, and our history has been when we're flush, people spend that money on leases.

Okay. That's fair. Thank you very much.

John Beres, Dow Jones.

Thanks very much. Just wanted to ask you 2 questions related to Meraux. Just now that the Class has been certified by the court, how is that -- where does that leave you as far as your settlement program? Can you still settle with people, or approach them, or how would that work? And then the second question is, what are the prospects for reaching maybe a -- kind of a global settlement or trying to resolve the issue more quickly?

John, the settlement program, which has been really successful, is shut down, because all those people are now deemed to be represented by a Class Action lawyer. And there are a number of unhappy people out there who had -- we have had to deal with. There will be a period where you can opt out of the Class, and so there -- if someone decides to opt out, then there would be an opportunity for them to come talk to us. Otherwise they can't. And as to your second question, no comment.

Okay. Thanks.

Mark Gilman, Benchmark Group.

Hey, Claiborne, on a more positive note, give us an idea what the heavy oil program up in Canada is like this year and, where you might see things by year end.

You know, Mark, I knew you'd cycle back, so I checked on that Laurentian Channel seismic and we did spend about $1.5 million up there on seismic, in our seismic program for the fourth quarter. We got carried on part of it, as my memory is now coming back to me, but smarter people than me were looking at numbers, telling me that we spent about $1.5 million. So that's that. On heavy oil in Canada, Seal's doing great. It's drilling out, and it's where we hoped it would be. Net backs aren't as good as we'd like, but it's nicely profitable. I don't know what our forecast for the end of the year is. Right around 16, 17,000 barrels a day, something like that, net to the Company. 17.

How much are you spending up there this year, Claiborne?

Don't know. We're looking. I'd have to revert -- 30, $40 million, something like that.

Yes.

So we'll -- between Seal operated and non-operated, about 50 or 60, between development and drilling. Around that number.

And this is all conventional?

Yes, yes. I mean, that's the beauty of it and why we bought it. It's all conventional, high productivity wells, all horizontal. It's a lot of scope. We have, I don't know, 90 leases, I mean 90 sections, something like that, maybe more.

Great. Thanks a lot, Claiborne.

Paul Cheng, Lehman Brothers.

Very good. Just a real quick one. In the first quarter, production number looked 115 seems a bit low. Is that going to make it a little bit more challenging for to you meet your full year 2006 forecast of 120? What's the risk there?

I think there's some risk at it, Paul. I need to see how Front Runner works, and we need to see how Tahoe works. Tahoe, right now, is at 13 million cubic feet a day. It was doing 50 million before the storm. And we've got 30% of it. And there's a workover planned at midyear. Need to see how that works. Seventeen Hands comes on. Syncrude expansion comes on, and Seal grows. So we have 3 areas -- distinct areas of growth. But there is some risk in some of these older Gulf deals. And so it's too early to change it, because my sense of it is that we'll possibly make it, but I do have a little bit more tenderness there than I would have a couple months ago. Not huge.

Okay. When we looking at your exploration program, you're still going to focus a lot on Malaysia and Congo, looked like that you may pause awhile there to reassess where you want to drill on the drilling side before you push ahead again. If we look out for the next, say, 12 to 18 months, is there any particular new region that may be on the horizon, that you guys would be more interested in maybe venturing into?

Yes, but just by definition you can't talk about them. And we always have 2 or 3 that we're working. And -- but it's certainly something, just because of the nature of the business, competitive situation, that you typically don't disclose. But, yes, it's fair to say that we are.

And in the Gulf of Mexico, deepwater, are you guys still pretty committed? I guess that's -- the success rate in that, the cost is high, the success rate is not necessarily the best in the world. Is it really as attractive as a basin that, from what you guys can see?

You know, if you look at the play that we're really making, Paul, which is the expanded Miocene, we're 1 for 2. Which is Thunder Hawk worked and -- what was the one with the dry hole we drilled, farmed in on? I'm going blank. We drilled the dry hole last year, an expanded Miocene well with Chevron. So we're 1 for 2. The Pleistocene play that we had a lot of success with, we clearly stayed too long. And I've done my mia culpa on that, and said that we -- yes, Makalu. I'm sorry, Makalu was the dry hole. But this play is different. It's a fabulous play. Rock is great. Really long columns and typically lots of fill, lots of charge. And it's -- a lot of is it subsalt, which presents challenges. But also the good news is that it's underexplored. And so once you do a lot of subsurface control, then you can come up with your seismic that helps you image where you think that the field structures ought to be. Really have a pretty good shot, and they're big. They're certainly big.

Now, we're pushing it a bit over in Green Canyon where we've amassed most of our acreage. But I'm relatively optimistic that we've got competitive prospects to drill, and so I'm -- I'd say we're 50%, and that's not bad In that particular play. So, yes, I'm pretty fired up about it. The Knotty Head discovery is near a lot of acreage that we had. We bid on that block. We were number 2. Bid a lot of money, got outbid, so I think we understand it. And those things are hugely value creative. Hugely value creative. So, yes, I'm pretty keen on it.

Okay. Very good. Thank you.

Gene Gillespie, Howard Weil.

Just as a follow-up, Claiborne, the Knotty Head discovery should make [exactable] subsalt look pretty good.

Close. Close.

In terms of the 2 blocks, Block K was segmented into 4 blocks, and you've got the original piece of K and P. Of the 2 that were not awarded to date, are you going to compete for both or either of those?

Gee, if we were, I wouldn't tell you.

That's good enough.

And if we weren't, I wouldn't tell you, so that covers both of them.

Good. Thank you. You're very informative.

Likewise, brother.

Steve Enger, Petrie Parkman & Co.

I don't know if I want to follow that one or not.

Put a little levity in today.

Funny how you forget the names of the dry holes, huh, Claiborne?

What's that?

Funny how you forget the names of the dry holes.

Oh, heavens. It's part of what's called sanity.

I did want to follow up on the comments that you made in general on the deep Miocene play and your positioning. You guys have talked about having some real focus in the Thunder Hawk area, and I think you've got a couple maybe of smaller gas prospects that you've laid out as part of the potential Gulf of Mexico plan for '06. Question is, with some of the industry discoveries in Big Foot also added to that list in the Miocene, are you more excited about your position there, and how does that play out in terms of tangible drilling activities? Might you get to any more of those later in 2006?

Our plan is to do that. The Victory is available at either after Thunder Ridge goes over and drills the Miocene prospect in Green Canyon, yet to be decided. Or it goes and drills some development wells at Thunder Hawk. We have 1 or 2 slots on another deep water rig that we get at midyear, which I could also see likely going somewhere and drilling some Miocene prospects. And then have yet come up with another slot or 2 on another rig that we could get at the end of the year. So we've got the Victory for 3 years, basically, and that's going to be kind of the workhorse for us. But we'll supplement that from time to time with rigs of opportunity. And we need to drill the program. It's probably going to be a 2 year drill. There are going to be 150 to 300 million, I think, size. A lot of couple 4 way dips. They've got come-on.

Yes. So do you think you maybe drill 2 or 3 wildcats in 2006?

I think you'll see at least 1, Steve. I won't say for sure, because these things have a tendency to slip. But I would give you a pretty high probability of 1, and a likelihood of 2. I'd like to see them drilled.

Yes. Does that mean that some of the acreage you have in the lower tertiary is sort of on the back burner as you're pursuing this deep Miocene play?

Yes, and we've never pursued that very hard. We bought acreage just to have it covered. But other companies got there before we did, and have better positions. And there's a modest bit of ambiguity about where that play is going to go.

Great. Thanks.

Mark Gilman, Benchmark Group.

Claiborne, 2 things regarding Malaysia on the production side. What happened with the supplemental payment in the fourth quarter? Looks like it dropped down very substantially. Is my arithmetic correct?

Mark, it did. It was 6.3 million, about 6.78 a barrel, and that was due to increased CapEx. So that was less unutilized cost oil. So since we spent more money, we got more cost oil, so there was less to go over to the profit oil, to be effective by that calculation.

Okay, Kevin. Thanks. I am going to pretend that I understand that.

Maybe it was always much more eloquent. I've been suffering from flashbacks all week.

is there another -- either did it occur in the fourth quarter or is it expected any time in '06, another change in the profit split that we may be on the verge of?

At West Pat?

Yes.

I think it goes up at 1.5, 2, 2.5. Am I making that up? And so I could see where there could be 1 if oil prices stay up, Mark, but we're spending a bit of money there, too, as Kevin was alluding to.

Okay. But 1 did not occur in the fourth quarter, and you haven't factored it into the fourth quarter outlook?

We have it factored into our outlook, yes. So obviously we've looked at it and don't think that's the case. But intuitively, I could see where that might occur if it's at this 1.5, 2, 2.5% -- or times cost recovery. Is that really what the scheme is? I think it is. Might happen later in the year. We'll let you know.

Okay. Thanks.

[OPERATOR INSTRUCTIONS] As there are no further questions at this time, I'd like to turn the call back to management for additional remarks.

Thank you very much. No, I'm fresh out. So I appreciate your patience and forbearance, and thank you.

Thank you. Ladies and gentlemen, this concludes the Murphy Oil Corporation fourth quarter earnings release conference call. If you would like to listen to a replay of today's conference call, please dial 1-800-405-2236, with access number 11050887 followed by the pound sign. Again, if you would like to listen to a replay of today's call, please dial 1-800-405-2236 with access number 11050887 followed by the pound sign. Again, thank you for your participation today. You may now disconnect.