Murphy Oil Corp (MUR) 2004 Q4 法說會逐字稿

Good afternoon, ladies and gentlemen, and welcome to the Murphy Oil Corporation's conference call. At this time all participants are in a listen-only mode. Following today's presentation instructions will be given for the question-and-answer session. If anyone needs assistance at any time during the conference, please press the star, followed by the 0 on your touch-tone phone and as a reminder this conference is being recorded today Thursday February 3, of 2005. I would now like to turn the conference over to Mr. Claiborne Deming, President and CEO of Murphy Oil. Please go ahead, sir.

Thank you. I'm joined by John Eckart, Controller, Kevin Fitzgerald, Treasurer, and Mindy West, Director of Shareholders Relations. I will turn it over to Mindy at this point.

Thank you Claiborne. I would also like to welcome everyone to the call. Today we will follow our standard format. John will begin giving a brief review of fourth quarter results and year-end 2004 results and then Claiborne will follow with an operational update then we will 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 that 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. And with that said I will turn it over to John.

Thank you, Mindy, and good day to everyone. Net income in the fourth quarter of 2004 amounted to $134.5 million, which is a $1.44 a share. That compares very favorably to our fourth quarter 2003 results at 58.7 million or $0.63 a share. Each of those periods included a bit more than $2 million of profit for discontinued operations so when you exclude the discontinued operations it equates to $131.8 million for the '04 period or $1.41 a share, versus 56.4 million in the fourth quarter of '03, which is $0.61 a share. At this point let me comment briefly what the numbers are for the full year of 2004. Our net income was $701 million, $7.51 a share in 2003 was 294 million, $3.17 a share. That also includes discontinued operations. They amounted to $205 million of discontinued profits in the 2004 period, primarily that was $171 million gain on the sale of most of our Western Canadian conventional oil and gas assets that occurred in the second quarter of 2004. So, therefore, continuing operations amount to 496 million this year and 278 million last year. An increase of $218 million and $2.31 a share.

Let me comment briefly on a few items that perhaps warrant further comment in the fourth quarter of '04. Those include the following. In the E&P section we recognized $31 million tax benefit that related to our Block K Malaysia operations. Due to the fact that we expect future tax deductions related to past exploration expenses that were booked. This primarily includes, of course, dry hole costs and seismic costs that have been expensed in the past. In the corporate area we incurred $10 million of net costs in this quarter that we just finished related to foreign exchange. As the U.S. dollar balance is held by our Canadian and U.K. subsidiaries were unfavorably affected by a weaker dollar versus those local currencies of the Canadian dollar and the pound sterling and euro.

Also in corporate the Company's Canadian subsidiary dividended $550 million to the parent Murphy Oil corporation in the fourth quarter 2004. We used that cash to pay down most of our debt other than our long-term notes. Some non recourse debt that's no non interest bearing at Hibernia. However, we had to pay a 5 percent withholding tax on that dividend so we incurred a $27.5 million charge and that was recorded as an expense in the fourth quarter of '04. By type of business then, if you look at the continuing operating results our E&P business in the fourth quarter of '04 made almost $153 million versus 82 last year in the same quarter. Our downstream made $30 million versus a loss of 12 last year and our corporate costs went up from $12 million net cost in '03 to $51 million in '04. In the E&P section it was up $71 million. Obviously that was favorably impacted by a combination of higher oil and gas prices. The tax benefit that I've already mentioned of 31 million in Malaysia and also slightly lower exploration expenses.

We did have slightly lower oil and gas sales volumes from continuing operations. Our oil was down about 4,000 barrels a day due to the fact that we had no sales at Block 16 in Ecuador and our gas was down -- production was down about 21 million a day primarily related to Hurricane Ivan effects. We had one particular field that produced 17 million last year that didn't produce at all this year. In the fourth quarter, and it's coming back up in the first quarter. The U.S. income tax rates in the E&P section are a bit lower than you might normally expect as we had some one-time state tax benefits that were recorded in the fourth quarter. Downstream results improved by $43 million, primarily because of much stronger refining and retail marketing profits in the U.S. in the current quarter. The fourth quarter '03 was unfavorably affected by lower crude throughputs as that was a period following the fire that occurred in the second quarter of '03. Corporate net costs are as I mentioned before are higher by 38 million. That's again the two impact of the withholding tax on the Canadian dividend, 27 million in higher foreign exchange losses. Finally, at the end of the year, 12/31/04, our long term debt amounted to $613 million, stockholders equity was 2.65 billion and therefore our debt as a percentage of total capital employed was 18.8 percent. And with that I'd like to turn it over to Claiborne's for his comments.

Thanks, John. I'll review development projects, production, current and forecast, exploratory drilling and downstream activities and I'll start with the development projects. At Medusa the A1 well came back on stream January 11, after a workover and the field now has all 6 wells up is and is currently producing 40,000 plus barrel equivalents a day. At Habanero the field has both wells back up as of mid-December and is currently producing right at 27,000 barrel equivalents a day. At Front Runner the first well came on stream December 4, and is producing 13,000 barrel equivalents a day and the second well is planned to start up at the end of February or the beginning of March. At Kikeh we recently announced the rewarding of contract to FDSO contract to MISC a technical partner. SBM, this is one of four large contracts that will ultimately cover field development and further contract award announcements will be forthcoming.

At Kenarong we flow tested the Kenarong number 2 well at 9 million cubic feet a day with 180 barrels of condensate per day. If completed as a horizontal, which is what we anticipate in the development, the rate is calculated to be around 30 or 40 million cubic feet per day and 6 to 800 barrels a day per well. Kenarong number 3 found 140 feet of gas pay and 20 feet of oil pay. We reckon we have right at 40 million barrels of oil and condensate and 500 BCF of gas at Kenarong. Nearby Pertang has around 500 plus BCF of gas so far. We intend to submit a field development plan at Kenarong for both oil and gas development in the first half of the year which will trigger a negotiation for gas contract with Petrols.

Turning to production in Block 16 Ecuador we have completed our new tie-ins and started back-producing on December 22. We will have normal listings in January, February, and March. We have a 1.5 million barrel underlift position that we hope to resolve this quarter. Terra Nova came back up December 17, after a 27-day shut-in after an oil spill. And the start-up was a bit rocky. We really got back up January 1, and we're now producing right at 140,000 barrels per day. Our production target for '05 is as previously disclosed 130,000 barrel equivalents a day. Exploratory drilling at South Dachshund where we have a 50 percent interest and Lloyd Ridge Blocks 1 and 2 we encountered around 70 feet of pay in both the original hole and the sidetrack. If the down thrown fault block works, and certainly some of the risk has been taken out, we should have between 2 and 300 BCF in this discovery.

At MacaLou, where we have a 10 percent interest, it's located in Mississippi Canyon Block 937, this is a subsalt middle miocene play, we're at intermediate depth. At Thunderhawk where we have a 37.5 percent interest in operate, which is a Mississippi Canyon Block 734, and it's located about a mile from the discovery well, it's also a subsalt middle miocene play we're also at drilling intermediate depth. In Malaysia offshore Sabah we announced a dry hole yesterday at Penaga in Block H. In essence we had poorly developed sands which was a surprise, and we obviously still have a lot to learn in this part of the basin. Meanwhile we move the rig back to the Kakap discovery to drill a down-dip appraisal well which we plan to flow test. After that the rig moves to Jangas, which is a nearby exploratory well and then we'll -- the schedule shows we'll move back to Senangin and drill on that structure, Senangin number 2, then we'll drill Kerici which also in the same area, which is another wildcat.

At Sarawak offshore we're finishing up the Bellum well where we made another large natural gas discovery and we'll now move to Rompin which is in the northern part of SK 311 to drill an oil prospect which is located near the north Axis field. In peninsula Malaysia we anticipate picking up a rig in the second quarter and depending upon the outcome of some 3-D seismic which we got in last week that we just shot, once we interpret that and it comes out like we anticipate that it will we'll test a low relief structure, looking for oil near the center of the basin. In Conga, the republic of Congo has previously announced, we drilled 150 feet plus column of oil pay in Azurite Marine number 1. And we're located in 4200 feet of water. Preliminarily we believe we have around 100 million barrels plus of crude oil. We've moved the rig currently are moving it 18 kilometers to a second prospect called Saphir Marine which will take around 40 days to drill and is approximately the same prospect size as Azurite, and after Saphir the rig then moves 9 kilometers east of Azurite to drill the Onyx marine prospect, which is also roughly the same prospect size as Azurite.

Obviously we are off to a promising start and we are quickly following up to test surrounding prospects. Our goal naturally is to create another significant core operating area for Murphy. Downstream at Meraux our crude charge is 120,000 barrels a day, and margins are around $2.50 a barrel. The new sulphur plants up. The ROSE unit started commissioning at the end of the year. Fees should go in this weekend. Superior we enjoyed a strong December when heavy light differentials blew out. January is weak. We're reporting about a $2 barrel gross margin loss. Milford Haven had a spectacular '04 and we earned around $28 million but right now it's break-even. At Wal-Mart we have 770 sites in operation. We enjoyed a real strong fourth quarter and year. January's been weak due to a $0.30 per gallon increase in wholesale prices over the last month but current margin is 8.5 cents per gallon. With that I'll take your questions.

Thank you, sir. Ladies and gentlemen, at this time we'll begin the question-and-answer session. If you have a question please press the star followed by the 1 on your push-button phone. If you would like to decline from the polling process press the star followed by the 2. You will hear a three tone prompt acknowledging your selection. Your questions will be polled in the order that they are received. If you are using speaker equipment you'll need to lift the handset before pressing the numbers. One moment please for the first question. Once again, ladies and gentlemen, if you would like to ask a question at today's conference please press the star followed by the 1 on your touch-tone phone at this time. If you are using speaker equipment you'll need to lift the handset before pressing the numbers. Our first question comes from Mark Gilman with the Benchmark Company.

Claiborne and folks, good afternoon.

Hey, how you doing, Mark?

Pretty good. Couple things if I could. Claiborne, on the Azurite well frankly it's a little unusual for you guys and frankly others in the industry to put a reserve number after one well, particularly in a channel sand kind of environment where the imaging tends in general not to be all that great, and 150 million feet says this is one real big structure if that pays uniform, you know, over the aerial extent. Could you comment a little bit?

Yes. It's 150 feet of pay, and what we're saying is 100 million barrels is what we preliminarily think that we have. You can map the channels pretty clearly, Mark. It's two separate sand packages. I don't think we'll be off that much. I think that's roughly what we think. It's a four-way dip, it channels over it. You can see it pretty clearly. So, yes, I mean, I'm not uncomfortable there.

Okay. The Malaysian tax situation I guess I'm a little bit confused. Certainly I understand recording the deferred tax benefit on the expectation of future income. Will you be doing this going forward, and if so why wouldn't you have done it with respect to the fourth quarter where if you take that benefit out, it looks as if the tax rate on Malaysia was very high?

Mark, we anticipate booking the benefits in the future at 38 percent on Block K. This is all deferred tax accounting rules where you look at the probability of the utilization of those tax benefits in the future. Keep in mind this is only Block K. So Block H, when we have a dry hole at Penaga we have not determined that those deductions are utilizable because that's a different ring fence, and PM 311, 312, same issue, and the same answer. So you have to look at it in buckets, and the ring-fenced area that we're dealing with here on this recognition is Block K only.

Okay. John, can I assume that the benefits associated with the -- any Block K expenses in the fourth quarter were included in the 31.9 million? Is that the way you did it?

Yes, it is, all the way. Inception to date on Block K in terms of what had been expensed through the exploration expense category.

One other one if you could just, Claiborne, help me out with my memory a little bit which, you know, at this point is certainly fading. This was the second well on block H? I wasn't aware of the first one, or I don't recall the first one.

Yes, it was two years ago, Mark, and when you drill them you happen to remember them. It was called Denkis and it was in the middle of the block. It was a pretty four-way dip. No real step-out. Looking for the Kebabagan sands. Didn't work. And this one similarly, looking for the same sands, the oil sands at pay a Kebabagan, just had poor sand development. Which was a surprise to us, we thought we'd have sand and we thought the risk would be natural gas pay, which is what we found at Bagang which was nearby, but we didn't have as good a sand development as we have would liked.

What does this mean in terms of your thoughts on H going forward?

I think we've got two more years. We've obviously got to do some recalibration. We've got some thinking to do here on where's the next well. Likely we'll drill another well or two there. It's too big of a block, too much potential to quit, but clearly we got some -- we -- we were stumped.

Okay. Thanks a lot, Claiborne.

Okay.

Thank you your next question comes from Arjun Murti with Goldman Sachs.

Thanks. It's Arjin just just to follow up on Congo I think in the press release you described the sands as excellent reservoir quality. Can you provide any color in terms precocity, permeability, oil quality or at least what you see as the analogs? I know Chevron has some nearby discoveries. Totell has made some finds here.

I can't give you a precocity and perm, Arjin. Oil quality is low to mid 30s. Two sands, one in particular that was the -- that has the majority of the pay. You can map them, as I was describing to Mark, pretty clearly over the structure and we'll come back later and drill a down dip well. We feel pretty comfortable with it.

I mean if you look at what Chevron's got and go with Block 14 which is nearby is that the starting point?

Yes, certainly that and Exxon's discovery outboard are the two nearest analogs for what we have. But when you say starting point, I'm not exactly sure what you're saying. They have channel sands like we have channel sands and they've got structures like we've got structures, to the best that I understand what in particular, Chevron drilled, and so ours is analogous to what there's is and the two follow-ons, Saphir and Onyx are two. In fact Saphir and I'll condemn it by saying this, shares the same channel as Chevron had in their prospect. You can just map these channels this is an ancient Congo river. And you can see this particular channel going out so we share that with them. Now, whether it's a trap, I don't know, because the issue in these is sands pretty predictable, and structure, of course, you can see, but it's do they leak. So that's, of course, we don't know. And seismic doesn't tell you. We haven't gotten smart enough yet to know seismic is going to tell us if there's hydrocarbons or not. You see amplitudes, but it's predictive of sand and not hydrocarbons.

One on Kakap. I know you, I believe, commented in the past that that could move towards development. Will the next well do it, or do you think will you have to drill more at Kakap?

Well, we share it with another company, and we're just delineating our piece of it better. We'll have to unitize at some point, and so we're just understanding what's on our block. We need a flow test, and we'll do that. We need to find where the water is, so we'll do that. Just get data. But, yes, it's a nice field. It's a nice field. There's no question about that.

Terrific. Thank you.

Our next question comes from Ken Beer with Johnson Rice.

Hey there, Claiborne how are you?

Hey, Ken. Fine.

Let me go back to Block H for a moment just a follow up to your comments there, with those two wells dry holes and you've got two more years there, what happens at the end of two years, do you have to give the whole block back, or if you have another well that has discovery you have to give kind of all but the development area of, you know, what you find? I guess the same is true with K, is that correct?

Yes. It depends on what you discovered, and you ring fence it, and that's what you retain unless you get a renewal, and so that becomes the issue.

Okay. So you'd ring-fence around H, and you've got until -- for two years. What's the timetable there? I've actually forgotten that. I know you've got a lot of ring fenced or at least a couple of ring fences, one done and one pending but what's the timetable on the rest of K?

The block expires a year from now.

Okay.

And when you say you ring fence H, you just ring fence discoveries that you make within H.

I understand. Sounds like same with K, like you would ring fence Kikeh, obviously, and Kakap, and whatever you discover this year you can ring fence that. What's the process, then, to try to renew on K and/or H? What would the process be? Would you expect similar terms, or would you expect it to be yanked? What's the thought behind kind of how you would approach?

Typically if you are an aggressive explorer on a block and have proven to PETRONAS then you've done a good job of being a steward, looking after what's on the block, drilling wells, et cetera, you typically get a shot at renewal so we anticipate that. We'll apply for renewal over the course of the year and we'll recommend a work program that we'll submit with our renewal request. Then we'll sit down with them and talk to them and I trust come to an agreement. Typically you do.

Would the expectation be pretty similar terms or exactly similar, or do you just roll it over?

No, I would hate to presume this because there's -- certainly there's discussions coming up so let's just say that we'll sit down and we'll talk with them.

Fair enough. Thanks so much.

Yes, sir.

Thank you. Ladies and gentlemen, if there are any additional questions, please press the star followed by the 1 at this time. As a reminder, if you're using speaker equipment you will need to lift the handset before pressing the numbers. One moment, please, for our next question. Our next question comes from Steve Enger with Petrie Parkman.

A few things. First, the fourth quarter DD&A and op costs look like they've moved up meaningfully. What's your visibility on the first quarter of '05 and full year '05 on those metrics? Do you think they're going to stay at those high levels or do you see them coming down?

Steve, I'm trying to think anecdotally. Terra Nova is giving us trouble. Reserves are the same but we're just spending more money there and so that is becoming a $12 a barrel DD&A barrel for us. It started about 8, so that's influencing things. On the operating side, we should have real good numbers at Front Runner which should help us out. We had a bad December at Syncrude which might be influencing your numbers. it was $20 a barrel. They had some incentive pay that they made and then there were some other catch-up payments that they made. So that may be influencing you. Habanero was high because it was down, so that is distorted.

Same on Medusa, some things are going to persist and some that won't the way it sounds?

Yes, Medusa is what it is and it's about 5.5 and 5.5 on operating costs and DD&A, something like that.

Do you happen to know on Front Runner what the DD&A and op costs metrics are since that's going to be such a big piece?

We should be about $8 DD&A and about $2 on operating costs. Something like that. I'd say it's a $10 barrel.

Thanks. On Ecuador, Claiborne when you said you're going to resolve that this quarter do you mean you expect to actually get payments or are you still negotiating? How's that going to play out?

Well, I would hope that we would receive cash. Or some type of resolution, barrels or cash. It's 1.5 million barrel underlift position that we finally bookended -- we know when it started, now we know when it ended and we know what we'll do so we're now producing under a new transportation arrangement we're paying substantially less per barrel on the tariff. Now we just need to go back and talk with our three partners and say, how you guys want to pay us

Good luck on that.

Thank you.

Kenarong, what do you see is the range of potential start-up timing there now with some good news on the appraisals?

It's function -- it's a function of negotiating a gas contract and it's -- and that's really the -- going to be the driver, Steve. Oil was going to be an important piece of it but we need both to make it work. And so we need to sit down and see what we can negotiate. That will be the primary driver, what type of price can we get. There's always in the line right going by us. We have plenty of gas. It's the right type of gas, low Co2 gas. We've got plenty of oil and condensate to be material. So all the ingredients are there but it will be a negotiation.

Sounds pretty straightforward though from that standpoint.

Yes. It sounds it but it's negotiating gas contracts anywhere in the world is difficult.

Easy for me to say. Do you think you could flow first gas there before the end of '06 or is that not possible?

I doubt it.

So '07 is probably the earliest?

Yes, sir.

Final one for me. I think you're going to take a break after Onyx in the Congo. How do you see your work plan there progressing over the balance of the year?

Of course, a lot of it is going to depend upon how the next two wells drill out. What we need to do, is we need to drill three prospects we need to then look at our signs and do a lot of work. So far so good, but naturally we're going to drill some dry holes at this thing. We're certainly going to see what we can do the first three. The rig has got to go in to get some work done in the shipyard. That's why we're stopping, by the way. Subject to rig availability our faults are that we'll pick up a rig at mid-year and come back and hopefully do significant appraisal work. If we're lucky, and we have to have some additional success for a joint development amongst a number of fields, we try to start working towards development towards the end of the year, beginning of next year.

Your thoughts are you would focus on this little pod of -- this little area assuming you have some further success rather than moving to some of the other wildcat opportunities?

Yes, exactly. This is a place that clearly pays, and you just have to get a trap that works for you that doesn't leak and if you do, so far, it works, and ours works nearby companies have had success. We just need to follow up op that. But if we continue having success this could be extremely meaningful to our Company.

Great. Thanks.

Thank you. Our next question is from Fred Leuffer with Bear Stearns. Please go ahead with your question.

Hi, Claiborne, it's Nikki. Wondering, in the Gulf of Mexico, you've talked about some prospects in eastern Gulf of Mexico in the past. Can you just run through your drilling plan as you see it the year?

Yes. The one that is problematic is Dalmatian, which we farmed out, and it's just a function of getting government approvals, and we don't drive it. The Company that we farmed out to does. It's quite a good looking prospect. It's got a relatively high chance of success, and so we'd sure like to have that company drill it. That one would be next. At that point we're probably going to concentrate more on middle miocene. Over time that's going to have more impact on Murphy. There's probably two other good prospects for us to drill in the Eastern Gulf, but for our money I suspect if we really want to find big reserves to move the needle, the middle miocene is what we've decided to highlight. Post-Dalmatian we probably won't do anything for at least a couple of months.

Okay. That's great. Thanks a lot.

Okay.

Thank you. Our next question comes from Mark Gilman with the Benchmark Company. Please go ahead with your question.

Claiborne, have you secured capacity potentially for South Dachshund at the Atwater hub?

Yes, we have.

Yes?

I'm sorry, yes we have.

Did I hear you correctly when you talked about potential unitization with Kakap?

Gemunsut.

I assumed Gemunsut was on the other side of it. Any thoughts as to roughly how the lease line cuts that structure?

No, Mark, I'm not in a position to really discuss it. It will all be subject to sitting down with the other owners of the field and trying to come up with something that's reasonable, and it will, as all of these discussions are, it will be a fulsome one, so it will probably be quite lengthy, regrettably, but we'll see what we can do.

And that's why you're going after all the detailed data?

Correct. Everybody -- the other companies are certainly drilling on their side, and they should be, and we need drill on our side, so we'll all have a fair amount of data about the field and we'll have a pretty good sense of size and where the reserves are.

Could you just go over once again, because you were going too quickly for this old guy, on Kenarong, Penaga, your reserve thoughts and in particular where your thinking is right now in terms of the oil lag on both which it appears you're de-emphasizing a bit?

Mark, this is what our current view is, is looking at just Kenarong is 40 million barrels of oil and condensate and you're right, I'm not quite as bullish as I was the last time I talked, had the conference call, we had drilled Kenarong 1 and found oil and water, went up, dipped, expecting to find more oil we found gas and gas condensate in that same particular sand. We've got more condensate, less oil, and more in the 40 million barrel range is what our current estimation is. A little bit less than what I would have told you three or four months ago now that we've got more data. We're saying 500-plus bcf of gas at Kenarong. 40 plus million barrels of oil and condensate. We've got oil. We just have other liquids as well.

Wasn't there an oil leg or a condensate feature of the other one at Pertang as well?

There's not as much liquids in Pertang and what we've got to understand at Pertang is a deeper zone that's got a good reflector that we've never fully evaluated and we need to -- in the course of the year we're going to drill deeper and actually test a deeper zone that's got -- we're not sure what it is. It could be oil, but we certainly just don't know at this point. It's some type of pay and we just diagnostically don't know yet what we have. There's a fair amount of come-on there but this has been a more difficult drilling campaign than we initially thought after the Kenarong 1, I'll tell you that. The well's been more expensive, and it's been a bit more difficult to get our hands around it. But we need to test that deeper zone at Pertang and then I'll be in position to tell you what we've go. We've got 500 bcf of gas for sure.

Our next question comes from Ray Deacon with Harris Nesbitt.

Hey, Claiborne, I was wondering if you could, the projects you listed, Medusa and Habanero and Terra Nova, are those sort of at peak stabilized rates or do you think there will be any volumes going through the year to come on?

No, I think at 40,000 barrels a day, that's the peak at Medusa. 27,000 is a peak at Habanero. And most of that comes from one well, by the way. The vast, vast majority. Terra Nova you will start seeing mid-year declines. You'll start seeing some mid-year declines at Medusa. So all three are at peak.

What about the eastern flank at Terra Nova? Is there any drilling plan there for this year?

Ray, I'm hesitating. I'm sure there is but I can't specifically point to a well for you.

That's Okay. It might help you offset some declines.

In fact, there's oil enough there to be developed. I think we're going to start to see some stuff back in maybe 18 months.

All right. And in the Congo the second prospect, is there, in terms of size and maybe risk, is it very different from the first prospect you drilled or --.

Well, there's two things going on. One, the -- we picked Azurite to drill first because the particular response -- seismic response we were looking for ABO was the strongest there, and the Saphir doesn't have quite as strong an ABO response. Then you have to offset the fact that since we have discovery at Azurite you have got de-risk Saphir a bit, and then as I mentioned earlier we think we can map the channel that goes through Chevron's discovery nearby, over and it's the same channel shared with Saphir so that's a plus so I think you'll find channels, I think you'll find sand we just don't know if we'll find hydrocarbons in them. The basin by the way 1 and 3, I mean it's a good place to be looking, but I wouldn't change that. I'd still say it's 1 and 3 at Saphir like it was at Azurite.

One last question. I know you changed the strategy in the Gulf a bit and we're focusing more on acquiring leases in the miocene and lower tertiary plays. Anything you've seen make you more encouraged about that area?

No. We're certainly going to buy some leases there. But our current thrust is to do the middle miocene. That will be the immediate thing that you'll see us do. Makalu is that, as is Thunderhawk. We've got a prospect around Front Runner that's middle miocene that we may drill later this year, and working on some others, so they're hard wells to drills and they're expensive but it's a heck of a section.

Right. Thanks a lot.

Yes, sir.

Our next question comes from Paul Cheng with Lehman Brothers.

Hey, Paul. How are you doing?

Very good. How are you doing?

Good.

Claiborne, just several questions. Just want to make sure I get you. You're saying that Block K would be expired a year from now?

Correct.

Block H will be in two years?

That's correct.

So one is February of 2006, the other one is February of 2007?

Don't pin me down on H but that's plus or minus on H. Probably it's a bit more than that but that -- it does -- that is the time on Block K.

Okay. In Block K, if you looked at your prospect -- doable prospect inventory today -- how many additional orders that we may need to identify to whatever prospect you have?

We've got prospects to drill clearly that are in a rig schedule ready to go through, say, August, Paul. And then we'll look at what the results are and we'll see where we need to go.

Does that mean that you're going to do a little bit more seismic if you assume you're going to be able to renew the prospect?

To renew the Block?

Yes.

Yes, we'd have a whole other work program that we would submit to the government in a renewal request that would include wells and seismic.

I see. And at -- Claiborne, can you refresh my memory or remind me I thought you have another Block which is a -- in the disagreement or that (INAUDIBLE- highly accented language) Malaysia and the government is in negotiation. Any update on that?

They're Block L and Block M, and I don't have any information.

So you're still in never, never land?

Yes, what I -- my standard response is it's an opaque process.

Okay. And in Ecuador I think at one point at Kakap you was thinking to or there was your partner to expand the production there and is that still the plan? Or that -- given what you have seen you decide not to pursue for that, it's too expensive?

It's a little bit different than that. Our budget for last year '04, based upon what our operator told us, was we produced gross 75,000 barrels a day in Block 16. In the event we produced more water than we had capacity to handle, and we ended up averaging about 50,000 barrels a day in the course of the year from the Block, gross, and our budget this year is 54,000 barrels a day, gross. I would certainly like to get it up higher and -- but it's going to cost -- the partnership talks about it frequently but we haven't put it in a budget to do and so you could chalk it up to folks collectively aren't willing yet to spend the money to do it. Oil is there, you just need lots of capacity to handle water. And that's the issue.

And in Terra Nova, PETRONAS, I think mentioned that the royalty rate would jumped to 25 percent by the third quarter because it's already finished their earn out. I presume that's also applied to your share, right?

Yes, yes. I'm a little quizzical where it's 5 percent now, Paul, and I don't know if that's 25 percent of profits or what, so I'm just going to have to plead ignorance.

They saying that the royalty rate has jumped from 5 to 25 percent by the third quarter. Just wanted to make sure that is for you is under the same time schedule on that.

No reason why we would be different for sure so I'll just to have do some homework for you.

We'll get back with you, Paul.

Thanks, Mindy. And in Congo, Claiborne, how many drillable prospect that you so far have already identified? You are going to drill two more. I presume that in your prospect inventory you have more than that?

We, do, Paul. Let me not give you a number but certainly we've got three ready to go and there's more to come but we'll concentrate on the next two.

Okay. Can you -- I think earlier in your comment you talking about some one-time tax benefit in the U.S. E&P. Can you quantify how big is that?

It was about $5 million.

So --.

Fourth quarter.

Is it all in U.S.?

It was all in U.S., correct.

And two final questions. One is my favorite, Wal-Mart. Claiborne hasn't talked much about that yet. Any kind of a number that you can share with us in terms of average earning per site for those open more than a year say for the past two or three years?

Gosh, I don't have that number on the tip of my tongue, Paul.

Or that the return that you have seen or any kind of number that you can share with us to see if that is really a worthwhile program for you to continue spending in a pretty rapid pace?

You know, I will say that of the earnings that we had in our U.S. downstream business the vast bulk of them came out of Wal-Mart this year -- and let me reflect upon how better to answer We haven't broken it out yet so that's my hesitation obviously at some point we will. We feel real comfortable that we've gotten the results for the past two years in particular that merit additional capital. I had always told folks that our target was around 15 percent and I can comfortably tell you that that's a number that we're real comfortable that we're making.

So you continue going to spend about -- going to be 100 per year? That's still the trend.

I'd say 140 this year.

140?

Yes.

And then finally, Claiborne, in the Gulf of Mexico I know that you continued to look at it as a core area but given the success you have outside U.S. is it really important for you to be continuing engage in the Gulf of Mexico which is a free account I see a lot of competition? Will you be actually getting the bang for your buck or is it better off for you to focus your resources outside?

Paul, I'm feeling pretty good about it now. The results that we had at south Dachshund are encouraging. We thought it was about a 60 percent chance of success. I didn't try to pass that on too much. It worked. So I felt comfortable that technically we knew what we were doing. Then the Thunderhawk discovery last year, now we need to -- we're drilling a mile away delineation, our appraisal well. That needs to work for it to be something that we're real proud of but if that works then I think we feel pretty comfortable that this middle miocene it's an expanded section, it's a couple thousand feet that you're drilling for. Of course in net pace it's a lot less than that. It's a huge section. it's sub salt so you've got drilling problems, you've got imaging problems but the trap is gorgeous obviously sealed, so it's got all the things you look for. It's got size. These things can be 2 to 500 million barrels. So it's early days for us in this play but if Thunderhawk works, and we're drilling one at Makalu that's obviously a wildcat, not a delineation also it's got more risk but if we were so lucky to do something there I think we'd say, hey, this is something we want to continue to pursue and it just provides some balance to our Company. So I'm feeling better than I was a year ago, a lot better.

Next question is a follow up from Mr. Ken Beer. Please go ahead with your follow up question.

Sorry. I actually was going to stay on Thunderhawk. Obviously you're drilling this well right now. If that is kind of as had hoped -- or as hoped for, what's the timetable on Thunderhawk? If I remember correctly you're still looking, I think you just quoted, kind of that 200 plus million barrel type of a prospect size or reserve size. What's the timetable assuming this next well is a good well?

With intermediate depth, drilling gets to be hard sometimes when you're doing these sub salt things but I would hope in the next 40 days we'll be down and have news.

I'm sorry. Let me move ahead and assume that this well is good with the timetable in terms of development.

I'm sorry, Ken. It depends on how you develop it naturally. Not to be flip about it, there's nearby facilities that we could potentially tie into, which is a two or three-year development. Four years otherwise would be typical turnaround. And you mentioned -- and I mentioned 200 million barrels, Thunderhawk we'd be extremely lucky to get up to that number. The range that we've given people is 50 to 150 million barrels.

Let me ask a couple other real quick ones. With Ecuador how are you going to count for that? If they just cut you a check, you know, you actually showed the production out of Ecuador in the fourth quarter but no associated sales. What's the accounting procedure for Ecuador?

This is John. If they cut us a check, Ken, we would recognize the revenue at that time and we would -- I would anticipate that we would show the barrels as being slow because essentially right now we've got inventory barrels, if you will, on the books that belong to us, that they indicate on their records. So to clear that inventory off the books if they were to pay us cash we would reflect that as a sale of barrels, as well as revenue so that kind of clears itself up by doing it that way.

Also on the reserve side P you haven't come out with your reserve numbers. Sense as to when that might happen. And any thoughts as to how much of -- how much bookings you'll get out of Malaysia? Any guidance there?

I wish I could help you. We should have some numbers here, oh, I don't know, shortly, couple of weeks. It's a function of Kikeh and what we can develop, I mean what we can book. As I've said many times before it's typically you're limited in new basins to what you can produce from primary production, and I suspect that will be the case here and so it will be a number that everyone notices and sees. We just haven't landed on the number yet.

Final question. If you look back at '04 and look at the number of exploratory wells that you drilled, do you have a sense as to kind of what the success rate would be Company-wide and then also specifically in Malaysia just so I can jot that down and be correct?

Gosh, Ken, we started off the year horribly. The first quarter last year we drilled two dry holes in Malaysia, and two in the Gulf. We were kind of 0 for -- then second quarter turned around with Kenarong and Thunderhawk. And then we had Kakap in there. And I'm trying to think --.

Senangin.

And Senangin. I'm sorry, I'm sitting here. Mindy is whispering in my ear. Senangin. So those are the significant or potentially significant discoveries. I'm trying to think of the big dry holes in Malaysia aside the two earlier in the year Siakap and Aya.

Todak.

Todak. So I would say we're, you know we always say it was a 40 percent. I know that sounds high. If obviously if you're drilling around Kikeh it's higher than that. If you get out from there, our success is a lot poorer. And so blended we're probably at 40 percent, I'd say 35, 40 percent, in deepwater. Now, if you're offshore Sarawak we're having real high success rates with finding gas. Some of which we'll develop, otherwise it's shut in subject to getting a market. And then off the peninsula we had the success at Kenarong and Pertang. So if you say deepwater Sabah is 35, 40 percent, success rate in Sarawak is -- for finding hydrocarbons is 78 percent and peninsula we drilled one dry hole but that's it two, dry holes?

We're two out of three on success.

so we're probably say 60 percent success rate in peninsula so far, probably 50 percent plus in the area.

Thank you guys. Appreciate it.

Our next question comes from Mark Fisher with Fisher Seats and Capital. Pleases go ahead with your question.

Yes, thank you. On Azurite, assuming that that is 100 million barrels could you give us some broad indications of what your net on the 100 is likely to be, what the projected production cost and DD&A would be on development, then finally what would be the most likely period to start booking those reserves. You mentioned potential working toward development late this year. Does that mean that you could actually book some here in 2005? Finally, initial production. How many years would it be before that could come on?

Boy, you're really getting the cart before the horse on all this. As far as DD&A rates and operating costs it's going to clearly be a function of do we have additional fields that we can develop in conjunction with the discovery of Azurite. And that's typically how it's done in this part of the world. You would typically get something like an FPSO and develop two or three fields, maybe more together, get up to a pretty decent reserve number that you then amortize over one production facility and that will drive your number. You either have a heck of an operating cost and a heck of a DD&A rate or if this is the only one that we discover it will be substantially more than it would have been otherwise with additional discoveries so that's vague but I don't have enough information to give you anything other than that right now. As far as terms it's a production sharing contract and if you're familiar with Block K at all, terms is similar to that where there's a cost oil and a profit oil component. Instead of 75 percent cost oil as it is in K I think it's--.

It's in the lower 50 percent range for the cost recovery portion and for the profit portion it's in the mid 60 percent range and the royalty that we pay is 15 percent. And also in the Conga the state pays our income tax for us which makes a material difference to the terms versus Malaysia and also costs are recovered on a Block basis and profit is on a field by field basis. But we can't really note it down to a number of barrels or a cost per barrel because we just don't know enough yet to be able to do that for you.

We need to get an idea of how much it's going to cost to develop these things then you can understand what your cost component is and you can book those. Then what you think your profit component is and you can book those. So it's early.

Assuming success at the next two, to be optimistic, in terms of bookings and initial production in that part of the world what kind of range would you be thinking about?

I don't think we can book this year almost under any circumstance. We'll know what we have by the end of the year but then we have to submit a plan and go through that process so it's next year before it's approved and that would trigger us I think to book next year. What we have there. Then probably -- it's so early, but I would point you probably to '08, '09 maybe, for first oil.

Got it. Great. Thanks a lot.

One hole in the ground, so good grief. Give us some leeway.

I understand. Thank you, Claiborne.

Yes, sir.

Our next question comes from Gene Gillespie with Howard Weil Incorporated. Please go ahead with your question.

Claiborne, in your first quarter earnings guidance, can you give me some idea of what the -- I know you have a very huge dry hole exposure in the first quarter, given the level of activity. Kind of what's implicit in that 90 to $1.25 range?

I'll answer that Gene. You're correct, we do have a huge exploratory drilling program for the fourth quarter. Keep in mind that we will be charging the remainder of the dry hole cost for Penaga in the first quarter, that will be about $16 million. In addition to that we have almost -- we have about $95 million of other wells including $27 million for appraisal wells at Thunderhawk and Kakap. You'd like to think that those would be successful but you don't ever know. We have almost $30 million for two wells planned in the Congo. $14 million for Makalu which we expect to be down during the first quarter. $11 million for a couple of wells in Block SK 311 and shallow water Malaysia, 14 or $15 million for the Jangas prospect that Claiborne mentioned. In addition to that we would have about 14, $15 million of other exploratory costs in addition to the dry hole costs that I just mentioned.

Mindy, the -- ex Penaga, then, you've got about 94 to $95 million exposed, that risk, it's about after tax $0.65 a share. I guess what I'm trying to get to is what's implicit in terms of how are you risking your dry hole exposure in your earnings guidance range?

We didn't really risk that. What we tried to do was cap the upside a bit because of the weakness we've seen so far in our downstream results to date. We had a particularly good quarter last quarter, but quarter to date we are just not seeing any results like that and so we wanted to be able to cushion ourselves a bit if downstream continues to perform poorly throughout the quarter.

I'm with you. Thank you.

Thank you. Our next question comes from Mark Meyer with Simmons and Company. Please go ahead with your question.

Couple of questions. Thunderhawk, assuming delineation is successful, any plans to flow test?

No, Mark, I haven't seen that. And, boy, I wouldn't assume -- it's sub salt, you can't see it, we're a mile away. So we're hopeful, but there's plenty of risks with this one.

Assuming it is, and I guess this is more of a general philosophical question about validating deepwater reserves in the Gulf of Mexico, any more, I guess, external pressure to flow-test as part of the appraisal process?

No. I think if we -- if we're so lucky to be successful and we take a core, full hole core, there ought to be enough analogies that you could probably say, yes, this thing is bookable. I would suspect that's the case. The risk becomes when you get out of the North Sea and the Gulf of Mexico and there's no analogies to your fields, then without a flow test it becomes more difficult. Known basins typically if you have good analogs, and there ought to be plenty of good analogs for this, I mean, next-door, you ought to feel pretty good if you have a core.

You mentioned really a middle miocene strategic focus. An apparent large number of lower tertiary miocene type of Blocks coming up for expiration in '06 and '07. Are those similar pre-emptive opportunities in the middle miocene or is your plate full there in terms of prospect pipeline?

I think they're awfully good prospects, and we're late to the party. We were concerned about rock quality forever. Didn't know if there was enough veracity and permeability. There hadn't been a flow test yet so nobody knows, but I think we're getting more comfortable with it and so we'll certainly aren't going to ignore it. And I think certain parts, at least the best that we can ascertain, work certain areas are much better to be drilling play than other areas, so you'd want to get real focused on where you were looking.

One final one. Apologize. Could you reiterate the retail margin?

Today for us is 8.5 cents. But it's been weaker than that in January. It was extremely -- we had a fabulous December but we -- January was exactly the opposite.

What was January specifically?

It was certainly in excess of $0.15.

No, January.

December was $0.15?

Sorry, January, January was around $0.04 or $0.05. And basically wholesale prices increased all month, so you're fighting that.

Great. That's all I had. Thanks.

Thank you. Our next question comes from Don Texter with Dorsett Asset Management. Please go ahead with your question.

Afternoon, everybody.

Hey, Don.

Couple of things. I misheard what you all said about the 3-D program over in, you know, 311 and 312.

Yes.

Could you just repeat that?

Yes, I could. We got our seismic back last week, Don, and we've got low relief structures. We're looking for oil and we need to make sure that the 3-D confirms the 2-D and that we can see the structure and feel some comfort level there, then we try to drill it at mid-year. It's -- if it holds up it's going to be a real good prospect to drill. I don't want to get too far out ahead because we haven't --.

But you want to do some more analysis before you --?

We just got the seismic in and we shot it obviously for this very reason to see if we can make the structures hold up. And they're low relief but they're big and that's the oily part of the Malay basin that we would be drilling in so, yes, I'm kind of fat, dumb, and happy at this point. Once we see it more clearly, then maybe we'll back off, but so far so good.

But it's going to take you awhile longer.

Yes, but we'll pick up a rig, I think we're showing on a schedule April time.

Okay.

Something like that.

Okay. Second question I had, could you provide any guidance as to how the ROSE unit at Meraux -- what happens in terms of the crude you buy because you've got this big discount, or big delta between light and heavy, sweet and sour. How does the ROSE effect, affect Meraux?

The easy way is to say that right now we're at about 1.25 percent sulfur crude. We'll go to close to a 2 percent sulfur crude. So we'll be a light, classic light -- like we'll have an Arab light slate, it would look like that, which is like a 1.75 percent sulfur crude. And so we'd pick up that additional discount on crude, and then we'd produce a little bit less resid than we're producing now. We're -- when I say a little bit less, I'll guess for you and say 1 or 2 or 3 percentage points less resid, with a more sulfurous heavy crude. So, you know, by no means do we become a heavy crude processor but we become a pretty darn good light sour processor. And we'll pick up. It depends, obviously, on product differentials, $0.50 to $1, if things hold out where they are now.

Okay. Great. Thanks very much.

Okay.

Operator, I'm afraid we don't have time for any more questions. Could you please give the play back information.

Thank you. Ladies and gentlemen, this concludes the Murphy Oil Corporation fourth quarter conference call. If you'd like to listen to a replay of today's conference call please dial 1-800-405-2236, followed by the pass code 11022152. Once again if you would like to listen to a replay of today's conference call please dial 1-800-405-2236, followed by the pass code 11022152. You may now disconnect, and thank you for using AT&T teleconferencing.