Murphy Oil Corp (MUR) 2003 Q1 法說會逐字稿

Good morning ladies and gentlemen and welcome to the Murphy Oil Coporation's first quarter conference call. At this time all participants are in a listen only mode. Following today's presentation instructions will be begin for the question and answer session. If anyone needs assistance please press the star followed by the zero. As a reminder this conference is being recorded today, Thursday, May the 1st, 2003.

I would like to turn the conference over to Mr. Claiborne Deming, President and CEO of Murphy Oil. Please go ahead, sir.

Thank you and good morning. I'm joined by John Echart, our Controller, Kevin Fitzgerald, our Treasurer and Mindy West (ph), our Director of Shareholder Relations.

I'm going to turn it over to Mindy now.

Thank you, Claiborne. I would also like to welcome everyone to our call. We will follow our usual format today. John will begin with a brief review of first quarter results then Claiborne will follow up with an operational update and 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 S.E.C.

This call will also include discussion of certain non-GAAP measures (inaudible) have been reconciled to net income and in the earnings release, and the reconciliation is included on our web site, at www.murphyoilcorp.com/ir.

With that said I will now turn it over to John

Thank you very much Mindy and a good day to everyone. First quarter of 2003 Murphy Oil's net income amounted to 87.1 million, which equates to 91 cents per share on a diluted basis. That compares to $2.5 million of profit on a diluted basis and 3 cents a share in the first quarter of'02.

The most recent quarter included two special items that I wanted to comment on briefly. First of which was a settlement of income tax matters that generated a gain of 20.1 million which was 22 cents per share. This settlement covered matters dating back into the early 1990s and included a period of time when we did the Odoco (ph) acquisition and the sale of contract drilling.

Secondly we had a required accounting change that was effective January the 1st, 2003, to reflect the new accounting method for retirement of assets, which is for us in the oil business virtually all related to abandonment obligations related to oil and gas assets.

This change required accumulative one-time but non-cash catch up charge of $7million after tax which was 8 cents per share. To restate the books as if they had always been on this method. Excluding this one time catch up this effect of the change of accounting had no significant effect on the quarter.

Excluding these two special items our earnings were $74 million, 80 cents per share and its the highest its been since the second quarter of 2001. Let me also say that there were no special items in the first quarter a year ago. By segment our expiration and production earnings amounted to almost $87 million compared to 20.5 million in the first quarter '02. Obviously this improvement was related to higher oil and natural gas sales prices as well as we incurred lower exploration expenses and these are the primary reasons for the improved earnings.

As noted in our press release our average worldwide oil prices increased by 36% and averaged $26.87 a barrel. And our North American natural gas prices more than doubled and were $5.60 per MCF. Our exploration expenses were lower primarily due to lower dry whole cost in both Canada and Malaysia in this quarter compared to the '02 quarter.

Downstream earnings for this completed quarter were a loss of 3.5 million that compared to a loss of 13.7 million in the 2002 quarter. Both our North American and U.K. downstream results improved this quarter with the North American improvement primarily due to better retail marketing margins and the U.K. improvement primarily due to better refining margins.

Our corporate costs were higher by almost $5 million and we had higher benefit cost primarily retirement, and lower income tax benefits this quarter compared to '02.

Let me comment finally that our long-term debt at the end of the period stood at 895 million and 34% of capital employed.

With that I'd like to turn it back over to Claiborne for his comments.

Thanks John. What I thought I'd do is go through the status of our various development projects, talk about production, spend a fair amount of time or exploratory drilling, what's coming up, and then talk about our downstream business and then take questions.

Beginning with development in Malaysia in the West Patricia field in our shallow water Malaysia program, we plan to start up this weekend, should get up to 10,000 barrels a day in the next several weeks. In the Gulf in Medosa (ph), it looks like production will startup in August rather than July. Production ramps up all year long and we should exit the year right at around 17,000 barrel equivalents a day.

At Habanero (ph),we tie into the Audra (ph) platform in October and we should exit the year right around 8,000 barrel equivalents a day.

In Ecuador, the OCP or the heavy crude pipeline is still scheduled to be finished in the third quarter. And we should exit the year there at around 10,000 barrels a day.

And then lastly at Front runner, we're drilling our last development well now. It's got an exploratory tail on it, but it's primarily development well, the No. 8 well in first production there still is scheduled for the first half of next year or 2004.

On the production front, let me recap two sales that we announced in the first quarter. One, we announced the sale in March of the Ninian (ph) field which will close in the second quarter. The price was $36 million. The ultimate gain will be around $33 million. Fourth quarter production attributable to Ninian and Colombo which were both sold together was around 4,000 barrels a day and also in April we announced a sale in Western Canada of various light oil and natural gas properties. The full year '02 production for these properties was 1500 barrels a day and the price there was about $35 million.

And as reported at the time, we are simply cleaning up very high cost quick decline assets and taking advantage of the market, the market opportunities there.

On production full year '03 production is scheduled for 130,000 barrels equivalent a day. And that's adjusted for the Ninian sale. The Western Canadian sale there isn't any adjustment.

In exploratory drilling first deep-water gulf we're currently drilling at Cool Papa (ph) which is in the western part of the front runner mini basin where we have a 37.5% interest. Its an 80 to 100 million barrel prospect and we should be down in 30-plus days there.

We'll spot (ph) a well and test a prospect called Johnny's Wagon in the southern part of the eastern half of the Frontrunner Minibasin which is a 75 million barrel prospect. We plan to drill a bit deeper here through the Johnny's Wagon amplitude so we can better date the LeComte (ph) and Exactabox (ph), those zones which we can better test and better read age read on them.

In the Eastern Gulf at Dalmatian (inaudible) Canyon, we have a 50% carried interest, we are in 5800 feet of water depth, 250 BCF equivalent prospect. That will spot probably in the first quarter of '04, maybe the fourth quarter of this year. Lastly, Thunder Hawk, Mississippi Canyon, North Thunder Horse looks like look a , first quarter '04 spot, (inaudible) thunder horse. It's going to be a real interesting and highly prospective wildcat.

In Canada in the Devonian Reef (ph) this winter, we had a modest discovery at Milligan, we drilled three other wells that were dry holes and we're clearly winding down that program. More work to do there likely next year but every year as we don't enjoy significant success, I can see us winding or slowing that program down a bit more.

In the foothills, we continue to drill at Stoberg (ph), we have a 35% interest, we pay 30%. As noted before, large prospect 500 BCF and we're at intermediate depth and still have a way to go.

Scotian Shelf (ph) we're deferred as previously reported drilling to follow up the Annapolis discovery, but that will drill next year that's in the deep water play. And in the shallow water play, the carbonate play, we are currently discussing participating in wells on either side of the deep discovery, haven't made a decision but those are currently being evaluated, one of the Muscodavit (ph) license and the other in the Margaret (ph) license and our interests are in the 25 to 30% interest there.

In Malaysia, first in the shallow water program, off the province of Seravac (ph), we will drill a well in December, wildcat and a prospect called the WAU, east of West Patricia, and its a 30 million barrel size, good amplitude and good prospect.

In our deep-water program I'll start in block H where we have an 80% interest. We have one well-planned in August, it's a prospect called Denkis, it's in1100 feet of water, it is a 13,000 foot test. It's 30 to 40 kilometers north of the Kibovagen (ph) discovery, same type of prospect as Kibovagen, which is a thrusted event. Same age section. The minimum size is 200 million barrels, and then it can get substantially larger than that. If the section worksout.

Moving over to the block K area, and our other deep water program, still off of Saba (ph) this program this year involves two rigs. We're going to pick up the trans-ocean 534 drill ship, we'll pick it up in May this month and we've committed to three firm wells, and we have six option wells for this drill ship.

Secondly, we've contracted to pick up the Ocean Rover (ph) which we'll pick up in July. And we have committed to three firm wells on the Rover with four option wells. And so we have six firm wells and ten option wells on tap for the balance of the year and into next year.

Now, we'll drill in the Kikeh (ph) area, the drilling prospects with the same characteristics as Kikeh. Same type of structure, all four-way dip. Some have a stratographic (ph) component. Same geological section. Similar seismic characteristics. On the size, some are a bit smaller to some that are significantly larger than what Kikeh is.

On the risk side of this, the structures look like they're okay. I think reservoir, we have a good fix on that. Charge is the risk. As it was in Kikeh. And thats both volume (inaudible) type. This area is about 50% oil and 50% natural gas. And over time, that's what we expect. If we continue to enjoy success in that area, that's what we expect to encounter.

Now, more specifically on the 534 which is what we pickup this month we'll start out with a wildcat. When that's completed we'll drill over and we'll drill the No. 4 appraisal well at Kikeh. We'll drill and log it. We'll then sidetrack it and we'll take a full-hole core and then we'll move off. And then the Rover drills another wildcat. So it is wild cat appraisal well wildcat.

On the Rover which we pick up in July we'll start to the wild cat, then we'll move over to the No. 4 appraisal well and flow test it. We're looking at a 6 to 15 day test. We'll shut it in for an equivalent period of time, see what the buildups are, and then move off. And then the Rover drills another wild cat. So the Rover is wildcat, flow test and then wildcat.

Obviously we have options on these wells as I mentioned before. So we have opportunities to continue, and certainly side-tracking if we're successful is the first thing we'll look at.

On the call side, these wells are typically 13, 14 million bucks apiece. The Kikeh appraisal will be closer to $30million. Just because of the time and location.

Turning to our downstream business, we had admittedly a lousy first quarter. And I thought I'd spend some time but briefly walk you through why. At Meraux (ph), we are heavy users of Venezuelan crude. Light sour slate, crude called Furielcrude (ph) (inaudible). Force Mageure (ph), Gulf coast spot market those barrels and we were replacing them in January and February.

As you would expect when a bunch of light sour crude is taken off the market, there is a lot of buyers in the spot market, the differentials between light sour crew and WTI West Texas intermediate shrinks. Typically that differential is 1.50 to 2 a barrel. When we were in the market it was 50 cents a barrel.

Obviously if you're a sweet refiner you are not paying much more for crude than a light sour refiner. Sweet refiners typically 1.50 (inaudible) better. And then on the heavy sour side, Mia (ph) differentials blew out. They were in the $5 range below WTI, they blew out February to March into the $10 range. If you recall Orion, big refiner on the river had a 75,000 barrel a day coker (ph) godown. One of the reasons that differentials widened. So if you're a heavy sour refiner, you're doing well.

At the same time, that we were paying more relative to sweet crude for crude, sour 6 oil prices fell out our bid. They went from eight dollars a barrel below WTI to 16 a barrel belowWTI. We typically have a yield (inaudible) 12 to15%. So that obviously penalized us, if that decrease was $8 a barrel and it's 15% of our yield, then you're looking at $1.20 for every barrel that we refine of a decrease in realization just from the decrease in (inaudible) prices. Now some people crack ReSid (ph) as you know so if you are buying ReSid to crack it and sell it you're making lots of money. Sweet refiners did well. Heavy crude coking refineries did well.

And people at crack ReDid did well and we didn't. And I don't like it. You don't like it. And it's a lot better now, in fact. But in a way it was a perfect storm for people like us with the refineries we have to do poorly and in fact we did. Now, it's superior because of the unusual heavy or high price for crude specifically heavy crude, we backed it out of our slate. We didn't want to be make asphalt in the winter, asphalt loss in the summer.

So we backed it out so we're only at superior running light crude and we've reduced runs so our crude slate is more expensive and our operating results per barrel is higher because we've reduced runs. Superior did not help us a bit in the first quarter as well and that's turned around in addition.

Right now Meraux is making $1.50 a barrel, Wal-Mart which improved dramatically in March continues to be extremely strong.

By the way the hydro cracker green fuels project which comes on stream in the third quarter of this year will have been a real benefit to us in the first quarter of this year and will be a benefit when it comes on. You run a higher sulfur crude, currently average about 1.1%and we can go up to a 1.7 which is an A light slate and also you get better yields.

We add a couple of percentage points to gasoline yield and we decrease yields by a couple of percentage points so it would have made a significant difference for us and it will when it comes on stream. So that business was a poor performer for us in the first quarter. There's reasons it's better now and will get better for us in the future.

So having said all that, I'll open it up for questions.

Thank you sir. Ladies and gentlemen, at this time we will begin the question-and-answer session. If you have a question please press the star followed by the 1on your push but on phone. If you would like to decline from the polling process, please push the 1 followed by the 2. You will hear a two-tone prompt. If you are using speaker equipment you will need to lift the hand set before pressing the numbers.

Our first question comes from Tyler Dann from Banc of America Securities. Go forward with your questions.

Hi, how are you all?

Good.

Good, staying busy. Question for you on Run for the Roses and anything you have learnt from that and anything as remains of your deepwater program in the Gulf.

Tyler, no, not really. What we were encountered was about 100 feet of at least the reflector was about 100 feet of 40% porosity volume volcanic ash sitting on wet sand. We had three separate three D surveys over it, they all lit up like Christmas trees and it was a hell of a prospect in fact but that's what it was. That's what it was. So I don't think it's got implications, it's just that what happens when you do what we do.

Questions have been raised, does it have implications for LeComte and Exactabox which are 24 miles to the north, given the number of minibases between us and Run for the Roses, it is really difficult to correlate, interpretive at best. You can't do it. We're deepening the Johnny's Wagon well just to confirm the age of the LeComte and Exactabox rocks. One thing we learn from the Run for the Roses, the lower portion of the upper (inaudible).

And so if we can date the sands better that we're targeting at LeComte and Exactabox it will help a bit. It won't preclude us from drilling the prospect too far away to draw a conclusion to Run for the Roses for those two but nonetheless it will be more data to have.

So I think we continue on. Obviously, you adjust risk as you go along. You bring in partners. We generate almost everything we drill so we're in a position to get partners and we do and hopefully get people to share risk disproportionately, which is what we did on Run for the Roses.

Okay. Thanks for the explanation. I have two further questions. First off on Stolberg (ph) did I hear correctly that you're at intermediate depth on that and that the well you're drilling with Shell Canada 50-50? 50?

There's three partners, we are paying 30 to earn 35. We promoted it out to a private company in fact, not a huge permit. We are probably going to have to shut that down for the summer and resume in the fall. We might get done before then, I doubt it. It's slow, hard rock drilling as you know in the foothills and slower than we planned, I promise you that. We're making progress and ultimately get down.

Thanks for that. I think I heard correctly that you mentioned the well cost in Malaysia was, deep water, $14 million per well. And that seems lower than the 18 to 20 that is the initial exploration wells cost. Any particular light you want to shed on that?

Yes, mode cost is high and drill rig rates are lower (inaudible). Combination of all of that.

Okay. Thanks very much.

Our next question comes from Bruce Lanni from A.G. Edwards.

Hi, Claiborne, how you doing?

How you doing?

Pretty good. You were talking about Meraux and Superior,(inaudible) and the refineries, how is Europe looking for you right now, that would be one question? And then I have one about the Wal-Mart JV.

Bruce, we've been averaging and 2.25, 2.50 gross margins. It's been pretty healthy, primarily in our retail business, that includes our retail. And you know it's been a nice contributor. It didn't start off the first quarter a nice contributor. Nothing was working for us. But if I recall, I think March we earned $2.5 million out of Milford Haven, that's where we are now.

With regard to Wal-Mart, I know you don't want to provide actual numbers and I can understand why. Can you give us guidance as to the level of profitability for the Wal-Mart JV versus the higher quarter, higher lower or are you seeing the results that you hope to see, is the competition increasing?

Bruce, I'll give you the best answer I can. And that is, the first quarter was a lousy quarter because wholesale prices rose all quarter with crude. So no retailer did particularly well, and we didn't. Now, when wholesale prices sort of dropping in March, we got well fast and so we made money for the quarter in Wal-Mart.

And we're doing well now. And what I've told people consistently with it is that volumes are substantially more than we had initially planned. Our costs are exactly right in line to a bit lower than we had initially planned. Margins are lower. Are we causing a lot of that? Yeah, we are. Who wins that battle in the long run? We do. And so I'm comfortable where it is. I think it's a good business model. It can be painful at times. But we've made money every single year that we've had it. Some years we make more than others. Last year we didn't do well. Year before we did very well. Right now we're doing very well. We're up to 540, we'll be at 600 by the end of the year. I don't see it slowing down.

And for next year are you still planning the same rate of expansion, Claiborne?

Yes, sir.

Okay. Just one other, just kind of housekeeping question, you addressed in your earnings release. But I want to make sure I did the math right. On the hedges, was the loss incurred by the hedges somewhere in the area of $25 million for the quarter, does that seem right?

Yeah, yeah. And that's awfully ugly isn't it?

Not as bad as others, trust me. Really.

It just really, really distresses me. I will tell you this, that on the oil side at least we're in the black for the balance of the year as of two days ago on our hedges and so maybe, but maybe we'll come out okay on those.

I guess one question that would come out of this then because I know hedging has not, you know, commonly been something that you've entered into. Does this change your mind at all about hedging going forward or do you think it's going to become more important especially in Malaysia?

Reaffirms all my worst fears were all confirmed. All absolutely happened, my night mare happened. Reason I hate them every more. We are worried about locking in enough revenue to fund it and so we did about 25% of our production as a kind of a half-way house.

In the future would you be more apt to ship away from it Claiborne?

Depending on our budget and capital needs, it is actually a useful tool as we all know if you keep a level head about it. Despite my flash there we will keep a level head. I wouldn't rule it out in the future. It works for companies like us when you have a lot of capital needs. And we're going to have a heck of a requirement for capital.

Yeah, well, Claiborne, everything looks good. Thanks a lot, appreciate it.

Yes, sir.

Next question comes from Arjun Murti from Goldman Sachs.

I believe the plan had been you drilled the appraisal, got the other wildcats in Malaysia, year end you make the go, no go decision including the decision whether to bring in partners or I guess consider more meaningful external financing. Is that still the plan and you've undoubtedly received calls from companies and whether that's causing you to lean one way or the other?

Arjun that's still the plan. We'll see what the wild cats bring for us, if we have other opportunities. We'll have a better fix on Kikeh, we have a better fix on the cost of Kikeh, timing of Kikeh. And so the end of the year, will present a lot of options to our board, and the recommendations and we'll decide.

Any biases developing one way or the other?

If I have them, I'm not stating them.

That's fair enough. And then you've been selling some isolated fields here and there, high-cost, non core. Is there consideration given to getting out of some of the areas you're in, for example, heavy oil in Canada or other Western Canadian properties or any other area?

Not currently. I want to see what happens in Malaysia and what our capital, just what the scope is going to be, for get capital even just what scope and scale are we talking about and then we need to examine the other assets in our portfolio as a company. Lot of things of course are almost off the table. And heavy oil by the way probably is not one that we'd consider offloading because I think it's got a nice long term growth profile for us. Others probably depending upon results, and all the typical caveats could be put on the table.

Appreciate that. Thank you very much.

Next question comes from Ken Beer from Johnson Rice. Please go ahead with your question.

Hi, guys. Logistical question. Claiborne, you highlighted you are going to get a rig in Malaysia in May, drill a wild cat, drill the appraisal well, have that rig leave and have it followed up with a different rig to do the flow test. Just wondering why would you go through what I would think would be mechanical issue of taking one drill ship off and putting another rig on. What's the thought behind that?

The Rover is better equipped, don't want to conduct a flow test with a drill ship, DP drill ship, rather do it with a semi sub. It's just equipment, safety, that type of thing. Nothing else.

And it makes no difference just the idea of waiting for the Rover to actually drill the well?

Yes, there's no issues either way. Nothing to read into it at all.

Fair enough. And I think you said Cool Papa you said 30 to 40 days away?

Yes, 30-plus but I've heard 30 to 40. It's deep. Its 26, seven, 8,000 feet. It gets slower as you get deeper so that's a good time frame.

Fair enough so thanks again.

Yes, sir.

Next question comes from Steve Enger from Petrie Parkman and Company. Please go ahead.

Hi guys. On production can you give us an update on lady Ladyfern (ph) , and what Ladyfern production represents from your 139 million a day in your first Canadian gas production where that may go and then the second piece, you mentioned the Canadian heavy growth prospects which you guys have been talking about for awhile. Are you seeing potential for some growth in Canadian heavy volumes before the end of the year or is that something that comes later?

First on Ladyfern, let's see, through March we were at about 65 million a day net there. And we declined to about 35 million a day at the end of the year, something around there.

Okay.

On heavy oil yeah, we should see increase, increases. And our plan is to exit the year around 15,000 barrels a day of heavy oil. Lot of work to do between now and then though, I have to admit. And so we're working on it. And people are on notice that we need to get after it. Lot shut in now because of just the seasonal period, and breakup in Canada and once we get into the summer you'll see a nice bump. I still think we will get the 15,000 but I have a little concern starting to enter my brain.

Couple of things on the Malaysian program, on Block H you're going to drill the first well30 to 40 kilometers from Kibobagen (ph). Why so far you've mapped a prospect, I am showing prospects that are closer.

Because it's the biggest one looks like it. We have got prospects closer and also arguably, some of Kibobagen spills over to us. But something thats meaningful, lot of size to it, this is the best one. And you know it's wildcatting and so we may drill it and say oops we screwed up, let's move clearly to Kibobagen, that's what happened in Block K that we were flat wrong about where to drill the first well, and then obviously the second well and we got smarter as we went along. I suspect that's what will be happening in H.

And then on block K you've got four wildcats planned. Can you characterize are those all nestled close to Kikeh or are you going a little far afield for some of those (inaudible)? They are all in the vicinity, they are all within the area. So it's the same. You know the key being, the same geological model, same depositional environment, same reservoir, rocks, we're seeing the same amplitudes, same types of structures, obviously same clay type. We are be picking out the ones with the same similarity to Kikeh. Some are very close, some are further afield.

Okay. And does it look like you're going to get all six of the tests that you described, those would all be done somewhere around the end of the year if you stay on schedule?

Oh, yeah, yeah. These wells actually once you start drilling them, don't take that long, now that we know better what we're doing, 30, 40 days, something like that for most of them. So yeah, we should get it done.

Right, we'll look forward to it.

Yes, sir.

Thanks.

Next question comes from Matthew Warburton UBS Warburg.

Could you perhaps update us how the progress is going on the rollout in Canada?

No, not as well. It's been slower. It's - we started in rural areas, and it hasn't worked as well for us there. And so we have one in Calgary, which is new and very well, and we are targeting to build with Wal-Mart in Eastern Canada. Toronto, Ontario, just the eastern, that's where the model works best. And so we're still at 6 where 6 which is where we were six months or nine months ago. And if you recall, when we first started Wal-Mart here, we built ten then 20 then ultimately 35 on a pilot basis to see how it would work, to see if we liked it, they liked it. I think in hindsight that's what we're doing in Canada. I didn't think it at the time but now that we know more I think that's more what we're doing. Market's slightly different. And we're learning more as we go along. Once we understand it then we'll get high behind it.

100 is the target roughly for Canadian exposure?

Sorry?

100 is still the target for potentially the full rollout of the Canadian part of the joint venture?

I don't know if I've said that number, certainly more than six but I'd hate to hang my hat on a number.

Couple of more questions Claiborne if I could. The hedge position is moved back into the black with weakness in pricing. Did you think about actually closing it out given your obvious love of hedging as you outlined earlier?

Yeah, sure have. Hadn't so far but it's certainly passed my mind.

Okay. Finally as well, I notice on the balance sheet that you're letting the cash build up, 217million, debts are rising. I wondered if there is a conscious decision behind letting the cash accumulate as you have in anticipation of the development spend or other issues going on that maybe we can't see from the outside.

No, I tell you probably what it is Matthew, a lot of that cash is in London and there is a buildup to pay excise taxes at the end of the month. We haven't paid them yet. The government takes a big piece of it so that's a lot of it. You can't ever repatriate it. You can't ever use it in your business.

Okay, that's fantastic. Thanks very much.

Next question comes from Paul Cheng from Lehman Brothers. Please go ahead with your question.

Hi guys good afternoon. Claiborne, several quick questions. If we looked at your production target for this year, 130, I think several months ago, before your other sales program, you were originally looking at about $140,000 for this year and 160 for 2004. Now with 2003 job to about 130 what is your outlook for 2004?

Let's see, for 2004?

That's correct.

Let's say we're going to exit the year around, what, 160? Around 160. I'm winging it a bit but that's close plus or minus. The decline at Ladyfern will primarily be behind us. We'll add Front Runner in the middle of the year. I'm not looking at a forecast right in front of me. I'd say 160, 165.

Next year number, you say remain the came same?

I think that's fair.

Okay. On the second question, if we look at, maybe it is not a fair question, over the past several years that you guys have been very successful in your high impact, high interest drilling program, but given the size of the company, using that strategy, of course, when you are successful that will be really good but on the other hand, from a portfolio management standpoint that is a pretty high risk strategy either. So I mean, is that something that occurred to you perhaps that the strategy need to be more diversified, and lower your interest on per-prospect or per -block standpoint, in Malaysia, obviously that's very good with the TK that was such a great discovery but on the other hand do you really need to be in the 85%, would you be better off let's say if you had only 30, 40% be able to participate in more blocks?

I think that goes to the crux of a lot of things. And it is a deliberate strategy and has been on our part to keep high working interest especially in areas where we think we can meaningfully impact our company and Malaysia fits that. Obviously per the question earlier in the conversation, earlier in the conference call, the end of the year we're going to look to see whether or not we need to reduce that, when we get to the development stage.

You know, you create your value, typically at the front end. And so in a perfect world you'd rather have high working interest when you're drilling wells if you think you have a reasonable probability of success, you know, given wildcat odds, because that's how you make money for shareholders. Once you've made the discovery, the value has been realized and it is a better time to bring in partners. On balance, that's the way we think. If we think the risk is a bit high on the front end we bring in partners little bit earlier. So it's a -- you know, it's subjective to a certain extent. But also you look at what -- how do you move Murphy Oil Corporation, given our size, what's our competitive advantage. And I think given the company that we are, begin the technical strengths that we have, the quickness that we can move, the balance sheet, the legacy of the company in terms of what we've done well in the past, I think it's -- what we're doing is probably the best way to make money for people. It does get painful sometimes which I'll quickly admit. And if the pain continues too long I think you have to alter it. I think on balance, it's going to work out extremely well for people here. And so probably won't see a big change in that in the future.

Okay. Last question. With Medusa, Front Runner (ph) coming on stream, Medusa this year fun run next year, what is your core structure in terms of operating cost and DD&A, unit structure for U.S. is going to look like?

I can tell you specifically on Medusa Paul it's going to be about 11 bucks on Medusa. And that's weighted towards the DD&A side, say eight bucks there maybe seven and three bucks on the operating side. On front runner, I don't know, in fact. But it should be a bit less than that because it's a bigger field. And so should be a bit less. But something hike that. And I think, especially Medusa, I think we booked our share of 60 million barrels, we think it's bigger. And so I think you'll see that DD&A number come down overtime but I think it's a safe place to start.

You think front runner should be lower?

I think so but I can't tell you, I don't have an estimate in front of me. But just instinctively, it's a bigger field by an order of magnitude, and the facilities don't cost an order of magnitude bigger. Also, there are surrounding opportunities at front runner at the time. So I think we'll probably make more money there if I was guessing I think you'll see lots of satellite opportunities there. Already have one at Quatra (ph)-in and we got three four five real prospective areas to drill there.

So that one probably will end up being a more profitable field than Medusa. Wouldn't rule Medusa out though because didn't mention it, we'll drill Medusa north and spud it in about a month. And then we have Stone Maker which we just added acreage to which is over to the west of Medusa, and there's a lot of drilling to do there. So that probably will work out as well, kind of amortizing the platform over a lot more barrels. But just from what I can see I'd give Front Runner a better shot of making more money than Medusa now.

Very good thank you.

Next question comes from Mark Gilman from First Albany. Please go ahead with your question.

Folks, couple of things. Claiborne, can you talk about appropriate analogy between Cool Papa and front runner and Quatrain(ph)?

Talk about what analogy?

Any appropriate analogy between the Cool Papa prospect and what you observed at Front Runner and Quatrain.

Mark its deeper and (inaudible) and if you recall the map we've shown people its one of those buried ridges in the western side of the mini basin rather that the eastern basin separated by a pretty big geological (inaudible). So it is instinctively higher risk than drilling near the discovery and drilling on the right side so the speak of this big ridge which is kind of guides the depositional behavior of the sediments. And so you know it is a one in three, one in four. It's a nice bright spot. It's clearly lights up. And so you know I think it's a reasonable shot. But deeper, deeper and older.

Okay. Could I ask a question about the second quarter, 120,000 equivalents production number, I guess I'm having a little trouble getting there taking into consideration a likely rebound in crude, start up of West Pat, also at the same time the absence of the Ninian Colombo barrels. What am I missing? It looks a lot flatter?

I'm sorry we're sitting here looking at each other and talking.

(inaudible) there is not going to be that much of a rebound in Sin crude volumes. The volumes sold for Ninian and Colombo will continue to be reflected in second quarter production at least through the end of May.

You have that through the end of maize will include Ninian Colombo and the turn around is in both quarters, it laps over. Does that help?

Sure does. One more if I could. Just to clarify something I think John said at the outset. If we look at the whole abandonment issue on a before and after FAS 143, taking into consideration the accretion component that now exists, is there any material change excluding the cumulative impact in what the aggregate abandonment provisioning under FAS 143 versus what it was previously?

Mark, in relation to where we would be going forward it is very very, very similar numbers. There are no significant increases on putting it all together. Because the DD&A rate is actually a bit down from where it would have been otherwise counting the abandonment expense before and accretion makes up for that so we are more or less back to the same place. It may be a bit higher but it is not anything significant.

Okay. Just one other one. I noticed that there was some exploration expenses in Malaysia in the quarter. Is that seismic or was there actually some drilling activity that I may have missed?

No, it was seismic in the peninsula blocks we picked up last year.

Thanks Claiborne. Appreciate it.

Yes, sir

Our next question comes from Graims Spence from Central Securities Corporation.

Hi guys I know you got into Ladyfern production a little bit already. But I was wondering the overall volume of natural gas sales, and the year-over-year comparison between first quarter last year and first quarter this year. You know, down about 20, 30%. Is there a -- can we expect to see these back any time soon, back at their previous levels?

No, short answer. I don't want to be flip, but Ladyfern in the first quarter was near its peak. And it's just a once in a lifetime event in a way. And we don't have a program designed to replace it. And we had a -- took a shot at it but I don't see that happening. I think you'll see the U.S. flatten as we bring on some deep water fields that are primarily oil but have a gas component. But I don't -- Canada will just have to decline. And I don't see it changing. And you know, I fretted over it, and thousandth thought about designing a program to alter it, that or try to impact that. But in fact I think we can spend our money better in other places quite frankly. And I think we'll make a lot more money for shareholders by doing what we're currently doing. And I'd say that with some regret because you want to get your company to look a certain way. But in fact I think we'll make more money this way. So that's the answer at the end of the day.

Okay. That's perfectly reasonable. So we should get used to 35 million a day or thereabouts. You said it had been 65 million initially at one point.

At some point it will fade out. You have metrics porosity. I was hoping it was 35 or 40million a day. It may be lower, 35 million a day. We will find that spot we haven't found yet.

Thank you very much.

Next question comes from Mr. Gene Gillespie from Howard Weil. Please go ahead with your question.

Back to Malaysia. Claiborne, given the properties dispute between Brunei and country of Malaysia are you spending any G and G money on blocks L and M?

You know, we had previously picked up 3D on Block L, Gene, are we currently spending money, no. But we had some money already that was 3D data that we had in-house.

What would you surmise as to be the timing of the resolution or a compromise, whatever it is, between the two countries?

I'll say this, the country of Malaysia feels very strongly that property is theirs. And we are their licensees. And they feel as if there is nothing to resolve. That they own it and it's clear. And we respect, as their licensee that view.

So you will continue ahead as-is and when s time to drill a well you'll drill a well?

Yes, sir. Okay, thank you.

Our next question comes from David Wheeler from J.P. Morgan. Please go ahead with your question.

Hi Claiborne, two questions. Just a quick one LeComte, I know that was on the schedule but you mentioned you wanted to at Johnny go a little bit deeper, what's the timing on that or is it dependent on what you see in Johnny Wagon?

I don't think it is dependent. It is low risk. I would guess fourth quarter, I'm fetching a bit because we don't have a drill schedule that reflects that and obviously if Johnny's Wagon comes up a cropper we may have to rethink. But currently, I would speculate fourth quarter.

Okay. And secondly, many companies in the industry not only this quarter but over the past couple of years have been experiencing some pretty significant cost inflation, particularly in the mature assets. And I know for you guys there's a lot of moving parts, asset sales, new projects, production taxes, Canadian royalties. If you could peel through that a little bit could you talk about your experience in your per barrel cost, are cost going up actually faster than you had hoped or expected?

They are going up faster than I'd hoped, I guess not that I expected. The ones that you would expect to go up, which are mature Western Canadian smaller fields Gulf Coast, Shell Water, Shelf fields, clearly are, and it's not necessarily inflation. It's just the nature of these fixed platforms with fixed people on them, pipelines, and you're not amortizing as many molecules or barrels over them. Around that's why you have to sell this stuff. Because you can't find properties like that to replace them with. The basins won't give them up. So it's inevitable. You have to have other places to invest your money to replace it. And you have to sell them. As they get older and longer in the tooth.

And so that's what we're doing. Nonetheless our cost structure is increasing because it is still a pretty big piece of our mix. And so yeah, it's real and it isn't going to stop.

Now, going forward, you guys are in a little bit of a unique position in terms of the new projects are a bit lower cost like Medusa and Front Runner and you are actively selling some of the higher cost assets. Do you have any objectives for what would you like to do to the cost structure over a one or two year basis?

Not over one or two, it is what it is going to be, it is what what it is in a way. The ideal place to be is somewhere between eight and 10 bucks all between your DBA and operating cost rates. The perfect place is four and four to me. Four bucks to find it and four bucks to lift it. I don't think we can get there. Malaysia will probably be there, probably so big of our fix we get there de facto. Hibernia is there, Terra Nova (ph) is not there but it is real real close.. After that it's hard for us to get there. And so that's where you ought to be but the world just dictates something else for you.

Okay, thank you

You're welcome

Our next question is a follow-up question from Bruce Lanni from A.G. Edwards. Please go ahead with your question

What would be a good run rate that we should be using for corporate and other?

For what?

For corporate and other expenses, your corporate expenses going forward what would be a good run rate?

John Echart is going to answer it.

We run two.5 to 3 million a month.

That would be the run rate and that includes your interest expense?

Yes, it does. That's net of capitalized interest now.

Right. Okay, great. Thank you.

Okay.

Mr. Deming at this time there are no further questions. Do you have any further comments?

No, I'm used up.

Ladies and gentlemen, this concludes the Murphy Oil Corporation first quarter conference. We appreciate your participation in today's teleconference. If you would like to listen to a replay of today's conference dial 1-800-405-2236 and enter the access number of 534535. Again, that number is 1-800-405-2236, and enter the access number of 534535. We appreciate your participation today, you may now disconnect.