Murphy Oil Corp (MUR) 2004 Q3 法說會逐字稿

Good morning, ladies and gentlemen, and welcome to the Murphy Oil Corporation third quarter 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 this conference is being recorded today Wednesday October 27, of 2004. I would now like to turn the conference over to Claiborne Deming, President and Chief Executive Officer of Murphy Oil. Please go ahead, sir.

Thank you. I'm join by John Eckart, Controller, Kevin Fitzgerald, our Treasurer, Mindy West, Director of shareholder Relations. And I'll turn it over to Mindy at this point.

Thank you, Claiborne, and welcome, everyone, to the call. We will follow our typical format today. John will begin by giving a brief review of third quarter results, and then Claiborne will follow with an operations update, and then we will be glad to 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 occur or that the projections will be attained. There are a variety of factors that may cause actual results to differ, and 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. I hope everyone listening is having a great day. Our net income in the third quarter of 2004 was $118.7 million or $1.27 cents per diluted share. That compares to $68.7 million for the third quarter of '03, which was 74 cents a share. Our '04 period net income includes $2.9 million or 3 cents per share from discontinued operations, which relate to western Canada, properties sold in the second quarter. That compares to 2 cents in 2003. Excluding discontinued operations, our income was $115.8 million in the current quarter, that's $1.24 a share versus 66.8 million in the prior period. The 2004 continuing operating income includes $24.6 million gain on the sale of our T block field in the U.K. north C. This amount of gain amounts to 26 cents a share. By type of business, our results from continuing operations were as follows. Our E&P business, our exploration and production business earned almost $119 million compared to $66 million last year in the third quarter. Our downstream business earned approximately 19 million versus 5 in the same period last year. And our corporate net costs were 21 million compared to a $4 million cost last year.

In our exploration and production business, it obviously benefited from the T block sale and the gain there on that I've already mentioned, it also benefited from better oil and gas sales prices. Our oil price averaged over $40 a barrel which was up 57% from the '03 period, our North American natural gas sold for $6, MCF, which was 22% higher than the same period in '03. Oil sales volumes were actually about flat with '03 due to the timing of some of our liftings, while our oil production was about 10,000 barrels a day higher than the prior year in '03, in the third quarter, due primarily to the Medusa field in the deep water Gulf of Mexico, Mississippi came at 538/582 that started up late in the year in 2003. Our natural gas sales volumes were down about 7 million cubic feet a day. And that's essentially due to downtime related to tropical storms in the Gulf of Mexico. Speaking of the tropical storms in the Gulf of Mexico in the third quarter we recorded estimated cost to repair storm damages there that's not recoverable from our insurance policies due to policy deductibles, we recorded $2.6 million of cost in E&P side as well as 750,000 cost to the downstream side. Our total -- looking at the downtime related to the storm, we had a total income affect of lost production in the Gulf of Mexico of about $11 million on an after-tax basis. That's 12 cents a share. That's based on 4900 barrels of oil equivalents a day lost due to the storm.

Also as noted in our press release, we had virtually no sales in Ecuador, we had no sales from block 16. We are working with the operator following a change in our transportation arrangements to commence selling the oil there in the fourth quarter, hopefully. Total lost sales in the third quarter '04 amounted to about $8 million on an after-tax basis of net income lost. Our exploration expenses were $70 million in the just completed quarter versus $44 million in the '03 quarter, increase mostly due to dry hole cost off of the east coast of Canada. Higher seismic cost over our large Malaysian acreage position. Downstream results were much stronger in both North America and the U.K. in the '04 quarter as we earned as I said before almost $19 million. You may recall that in the third quarter of '03, our Meraux refinery was off line for all of the period following a fire in June of '03. Wal-Mart retail results were good, margins were squeezed a bit with higher oil prices in the quarter, but still profitable. U.K. operations had another solid quarter of earnings, and is setting the pace for a record year of profits from this business, and they are almost at a record profits through the first nine months. Corporate net costs were $21.5 million in the third quarter of '04 compared to 4 again. We had a $13.6 million after-tax unfavorable variance in foreign exchange and higher Sarbanes compliance and other administrative cost. The foreign exchange affect is due to the weakening of the U.S. dollar against primarily the Canadian dollar but also a bit against the pound, sterling, and the euro.

On the year-to-date basis from continuing operations we made almost $365 million of income compared to $222 million year-to-date in '03. Our E&P prices are 34% higher on oil prices, and 12% higher on gas prices in North America. We have on a barrel of oil produced, we're 18,000 barrels per day higher in sales volumes this year-to-date, and we had higher gains on property sales, including T block sale. These favorable variance were only partially offset by higher exploration expense. Better results in -- on our downstream business, we had better results in North America, primarily attributable to improved performance of the Meraux refinery, and again, as mentioned, our year-to-date results in the U.K. downstream have been very strong. Corporate cost on a year-to-date basis are up from $1 million in '03 to $47 million in '04. It's a combination of factors. It's higher net interest cost. Essentially due to lower capitalization on Medusa and Habanero field development and on Meraux clean fuels expansion project. Since these projects have, in fact, been completed now. We also had unfavorable variances in foreign exchange as noted before, weaker U.S. dollar and higher G&A cost with Sarbanes-Oxley work and higher expenses for retirement and insurance as well. In the prior year of '03, year-to-date, first nine months, it included a $20 million benefit in the U.S. and corporate from a settlement of tax matters and that did not repeat this year. As of September 30, our long-term debt stood at one -- slightly north of $1 billion, 1.05 billion, essentially unchanged from the previous quarter and as a percent of capital employed our long-term debt was 29.6%. With that I'd like to turn it over to Claiborne for his comments.

Thanks, John. I'll review development projects production, current, and forecast exploratory drilling and downstream activities and I'll start with developments at Medusa. We came back on line on October 15. We went down on September 13. We're currently producing right at 40,000 barrel equivalents per day from five of the six wells. The A1 well will be worked over at the end of the year. It starts back producing in the first quarter of '05. At Habanero the field is currently producing around 4500 barrel equivalents a day from one well. A rig moved on location on December 1, to work over the other well by repairing a subsurface safety valve. We should be back on production in the first quarter of '05. Front 1 of the first wells forecast to come on stream at the end of November at an estimated 15,000 of oil barrels equivalent per day. Subsequent wells should come on approximately every 60 days after that until all eight wells are on stream.

At 2K as previously recorded, all necessary approvals have been received, we're currently going out for tender for various production packages. On the production side, clearly Ivan hit us pretty hard. As stated Medusa's now back on the front runner got belayed, Tahoe operated by another company will not be back up until the middle of the first quarter. Unrelated to the hurricane, the workover at Habanero I previously mentioned is important to us, and that should be back up in the first quarter. Ecuador, as John mentioned, we are currently producing but not lifting in block 16. We changed our transportation arrangement in early June to send our barrels through another facility. In order to accomplish this, we need to tie into another meter on the OCP pipeline. This has not occurred. We expect it to occur this quarter. We also expect to make up our under lip position. Out of conservatism, however, we elected not to include this production in our guidance because it has proven a bit more challenging to accomplish the above than we initially thought.

On drilling wells, in the Gulf of Mexico, we're drilling at Mackelow in Mississippi canyon block 937, which is a 2 to 300 million barrel middle miocene prospect we farmed into. It spud in mid October and should get down in the first quarter. It's right at a $60 million dry hole cost and we're paying two-for-one for a 10% interest. At Thunderhawk, the appraisal well to the west of the Discovery well is planned to spud in Mississippi canyon block 734 in early December. It should be around an 80 to 90 day well. At south Dachshund located in Lloyd ridge blocks 1 and 2, we'll spud at the beginning of December. It's a 200 BCF prospect in the eastern gulf and should take around 30, perhaps 40 days to drill. And Dalmation, where we have a carry 50% increase in Desoto canyon block 48, now looks like it's going to fall over to the first quarter. In the Congo we're moving towards a December spud, although this spud may spill over to the first quarter. Water depth will be somewhere between 4 and 5,000 feet and prospect size is between 1 and 200 million barrels. Our interest is 85%. Recent nearby announcement discoveries by Chevron to the east and Exxon to the southwest have added an added degree of prospectivity to this well.

In Malaysia and peninsula Malaysia the rig is back at Kenarong where we have a 75% interest drilling an appraisal well which is located approximately 2 kilometers from the Discovery well. We plan to float test this well. Once this operation is complete, we'll move to Kenarong number three well, which is located in a separate fault block. In Seerwalk, Malaysia we're currently drilling at Seranpang, where we have an 85% interest, which is located about 15 kilometers northwest of west Patricia. This structure is roughly the same size as west Pat and we should have results in the next week or so. Our Savra program we just announced a dry hole at Todac where we encountered a number of oil bearing sands but too thin to be considered commercial. The structure is quite long, 30 miles with distinct fault separation and trapping styles. As a result we will study sand distribution and likely come back next year and drill a second well. The rig right now is farmed out to another company for two wells. We should get it back at year end to test a prospect called Panaga, on block H where we have an 85% interest. In our downstream business Meraux has accrued charge of around 120,000 barrels a day and is earning around $3 a barrel.

We're starting up a new sulfur plant right now which will allow us to sour up our slate a bit in November. Erosion start up is now mid December and will permit at that time a full light sour slate for the plant which should improve its profit given differentials. The superior crude has risen in price, over the last six months. Asphalt has not because prices are fixed, road contractors up to six to nine months in advance. As a result margins have been under pressure and we have lost as much as $3 a barrel at that plant in the last month. The margins, however, are robust and are around $4 a barrel. At Wal-Mart we're up to 730 units, 16 are opening this week. And we should be up close to 750 by the end of the week. Retail margins have been under pressure as John alluded to as wholesale prices have risen quite rapidly in the last month. But they have recently improved.

Lastly, we mentioned in our earnings release that we had acquired a property at Seal. It's a heavy oil property located in northern Alberta, and we acquired it in June. But we closed October 1, effective back to June 1, -- July 31. We already have production in the area immediately adjacent, in many cases, to production acquired. We're currently producing around 2,000 barrels a day from the new property. This is forecast to ramp up next year and the next to ultimately around 8,000 barrels a day. We estimate recoverable reserves at around 23 million barrels, of which around 8.5 million barrels are currently proven. We have 115 locations identified to drill. And we currently have two rigs working in the field. In summary, it's a property we know well, and which we acquired at a reasonable price. The western basin in Canada now offers by and large conventional heavy opportunities and unconventional opportunities similar to sim crude. We understand both well and will continue to invest opportunistically in both of these. So with that, I'll take any questions you might have.

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 one on your push button phone. If you'd like to decline from the polling process, please press the star followed by the two. You will hear a three-tone prompt acknowledging your selection. If you're using speakerphone equipment you will need to lift the handset before pressing the numbers. One moment please for the first question. Our first question is from Arjun Murti with Goldman Sachs. Please go ahead.

Thank you. Claiborne just on the Ecuador production first, did you say that the 7 or 8,000 barrels a day was not in theat fourth quarter guidance of 111? And then I assume at some point there will be some makeup sales for the production you already produced for last quarter and this coming quarter.

Arjun, let me take that question, when we gave the guidance range of 111,000 barrels a day, production from Ecuador is included in the production number but we excluded it from the sales number. So for your modeling purpose, you will need to remove about 8,000 barrels a day in order to calculate your earnings.

Right. But at some point when you get it settled out, you should make up the production.

We have about 900,000 barrels currently in inventory that we need to make up. So you're correct.

Our expectation Arjun, even though this has been a bit more difficult process than we anticipated is that we'll make up most of it, if not all of it, in the fourth quarter and crude prices are going our way, actually. So it could end up being a benefit if we, in fact, make up the fourth quarter.

For sure. Then just any follow-up on timing of appraisal drilling for Senangan and some of the other prospects. Sounds like Panaga after you get the well back is an exploration well. Any early '05 drilling calendar you can provide.

Yeah. But, first look at it says that we'll drill an appraisal well at K cap, we'll drill an appraisal well at Senangan. And then we've got two or three additional prospects in basically that part of block K that we're going to pursue. Depending appraisal results at those two fields there may be additional drilling there as well.

Any thoughts to bringing in the second rig, which I think you've at times contemplated?

We have. Not at this point. No. I don't think we need it for purposes of next year. Unless something unusual happens. Sometimes it does. I've taken a look at our -- early look at our budget. I think one rig can handle the program primarily in block K.

That's great. Thank you.

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

Morning. Two questions. First on reserve replacement, how much do you expect to book in Malaysia this year, and what is reserve replacement look like outside of Malaysia? And then separately, Claiborne, do you guys qualify for the small refiner benefits in the tax bill the President just signed? And if so, what does that mean to you?

Fred, we haven't yet made conclusive decision on how much we're going to book at K. We will book. The way the rules are structured, you can only book if you have water support that you're injecting. What you can produce by a primary production, until you see evidence of that water support, there's some exceptions of that in certain basins in the world the SEC recognizes but that doesn't include Malaysia, at least at this point. So there will be a starting point that you ought to think about is what can they produce just from primary production without injecting water for pressure maintenance. But given that constraint, we'll book as much as reasonably possible within that envelope.

Give us a ballpark?

I really don't. Just given the environment that everybody is in, I'd much rather prefer to sit down and have our numbers right in front of us and then give you a call. Outside of Malaysia, I don't see great reserve replacement. We're driven primarily by what we discovered in Drill bit and it's going to be premature at Thunderhawk for sure. We'll have a pretty good sense of what we have by the end of the year beginning of next year, really. So a pretty good sense there. We'll have normal ins and outs in the course of fields that underperform or outperform. But I don't see anything material out there that will hit us. It will be primarily in Malaysia. On the small refinery issue, yes, we do. And it's complicated. But basically it allows you an accelerated writedown or tax benefit from moneys that you spend on taking sulfur out of distillants. And we'll get a benefit from that.

You also get -- I think there is a provision to get a tax credit on barrels of sulfur produced as well, with some limitations. Just wondering if you guys have calculated the dollars and cents sort of impact for '04, '05, '06?

Fred, this is Kevin, we're still working through that. What we see so far -- it's still a little bit preliminary. What we see so far is it won't have a huge impact. We're still working through the details.

All right. Thank you very much.

Thank you. Our next question is from Steve Enger with Petrie Parkman. Please go ahead.

Hi, guys.

Hi, Steve.

Couple of things, Claiborne on block A in your strategies as you look ahead to next year, with the early '06 block, I guess I'll say exploration, you think that you can get to all the prospects that you've identified with one rig, even including that some of those activities will be appraisal next year?

Steve, that's the issue. And I think the answer that -- so far is yes. I think these wells only take 30 to 40 days to drill. And so you really can drill a number of prospects in the course of a year. So I think, barring something unforeseen that's out there, that one rig is going to give us a pretty good sense of what we have. We certainly want to drill those obvious prospects that have amplitudes, it's -- nice structures that are close to the success that we have. We'll certainly do that. And then Todac, as you recall was in the middle of the block, Panaga is in block H, which is another 40 kilometers away. So we're getting pretty good bookings of what we've got, what the issues are, where the risks are. And so I think at least at this point, one rig ought to do it.

And you talked about potential to go back to Todac specifically. Do you see other prospects in the central part of the block. And then same question to the north you've had mixed results up in that northern part block of K with a gang, if I recall correctly. Panaga is yet to be tested, obviously. But do you see a lot of potential up there or just a little bit of potential? Can you at least qualitatively address that?

Around Todac, there's likely another well to drill on the structure. There's different traps there, there's a supertrust, there's a subthrust, there's amplitudes, amplitudes are now that we have a better sense of what we have and we can tie it to seismic, we have a sense there's likely a better location. But premature. I don't want to say certainly that we're going to do it. But that's certainly where we're leaning now. And there's other prospects in the middle of the block, in fact, Shell has discovery in board of us that they announced called Malachi I think, about 20 kilometers away, maybe 25, just in board of us. So I think there's plenty of prospectivity there. We just have to understand it.

Okay.

You have to drill wells and you have to tie it in, you have to see what the risks are. And the northern part of the block, Panaga is on the same big thrust that whole series of discoveries was made. Kebaboggin, Kehmis, Kehmis thrown, Kehmis canyon, and we're following that thrust up and we're going to drill what is a very big feature with big amplitudes. There's I think the biggest risk here, I mean, there's risks in everything, the biggest risk is going to be hydro carbon type. Because they found lots of gas on that thrust, they found lots of oil, too, obviously we'll test all of that. But I would consider that our grade A prospect.

Okay. So you don't rule out that you would do some drilling up there next year as well obviously as a function of what you find at Panaga?

Yes, it's clearly a function of what we find at Panaga. If you look at the seismic, you can clearly see a big mother structure and you can see lots of amplitudes in it. There's been a lot of success along that thrust leading up to us. So I think it's logical to go ahead and drill a well there.

Okay. And then kind of the same thing looking ahead off peninsula Malaysia you're working hard on Kenarong right now, you had success at Pertang but not Aring. How many more structures are out there? Is there a lot of those yet to be drilled next year along with the appraisal?

Steve, the answer is yes. But I'll qualify it a little bit. We need to go back to Pertang and we need to test a lower zone, that has a big amplitude, and got lots of encouragement from them. We need to test, it'll be the flow test to see what we've got. There's a lot of potential there. Kenarong will flow test this well, we'll drill a separate fault block at Kenarong, which is a whole separate -- it's not an appraisal well, it really is exploratory well. In addition to that we're shooting seismic in the southern part of those two blocks that we have. And there's a fair amount of prospectivity down there. It's closer to the kitchen, and it's closer to the big oil discoveries that really made the Malaysia basin famous. We've got what we think are low relief structures coming out of the basin. The oil migrates that way, the middle of the basin migrates out. So if our seismic confirms what we think we see, we've got a really nice prospect to drill on the southern part of those two blocks close to the big Tapis fields. That's one to watch probably midyear, next year.

Perfect. Thank you.

Thank you. Our next question is from Jacques Rousseau with Friedman, Billings, Ramsey. Please go ahead.

Good morning. Just a couple of questions on the downstream. I was just curious if you could give us any numbers on gasoline demand, same store sales. And then second question would be an estimate for low sulfur diesel capital expenditures and timing.

Okay. Starting at the back of your questions, we're pretty much finished with all of our investment for low sulfur diesel, both at Meraux and Superior, where -- have a delay at Superior when we have to meet the final 15 PPM rigs to 2009 or 2010. We had an interim standard we had to meet, we've met that, just completed the equipment last month to do that. We completed our equipment at Meraux hydrocracker last year. So that's behind us. On gasoline demand, I mean, anyone can look at the macronumbers and see what the U.S. is. As far as we're concerned in our stations, we're up, oh, same store sales this month compared to the same month last year 8%. We've been loathe to ever really give exact numbers on what we do at our stations but we're certainly bumping around the 240 to 250 range, somewhere around there, thousands of gallons a month.

Sure.

I think I answered your question.

It's up 8% October over October, same store sales?

Yeah.

Okay. Great. Thanks very much.

Thank you. Our next question is from Jennifer Rowland with JP Morgan.

Question on the earnings guide for the third quarter I wonder if you could tell us what the assumption is embedded in there for exploration expense and also if you could break down your production guidance by area.

Jen, let me handle that one. Our range, again, is $1.30 to $1.70. The production is 111,000 BOE a day. Again, that does include Ecuador, but you will need to exclude that for your sales number. The realized oil price world wide that we are estimating is around $46. Gas price about $7.25. Dry hole cost exposure is almost $65 million, of which 43 million is in Malaysia, and of that 43 million, about 27 million is in tax relief. In the U.S., we're expecting to spend $22 million. So again , that is our exposure. To get us to an exploration expense number, it's about $80 million including the dry hole cost. For a production break out by area. Quickly on the oil side, it's volumes of about 16,000 barrels a day in the U.S., about 9,500 barrels a day in the U.K., 700 barrels a day of Canadian light. Almost 9,000 barrels a day of Canadian heavy. 27,000 barrels a day of offshore. 12,000 syncrude. 8,000 in Ecuador. And 14,000 in Malaysia. And then on the gas side it's about 68 million cubic feet a day in the U.S. 9 million cubic feet a day in the U.K., and 14 in Canada, which should get you to a total of 111. Did that answer all your questions, Jen?

Yes, it did. One other one.

Did I go fast? I think I wrote that down quickly enough. Another quick question regarding the FPSO. I know you're in the process of getting bids back for that in the Kehkai development. Just wondering if you could share with us if there's any indication yet from bids that you may have already received whether or not the 1.4 billion that you're targeting for development of that area, whether or not that looks to be too light or whether or not that's still a good number to think about?

Jennifer, it's too early for us to be commenting on the bids that we got back. I think that's the short answer.

Okay. Thank you.

Okay.

Thank you. Our next question is from Gene Gillespie with Howard, Weil. Please go ahead.

I've got three unrelated questions. First one is what would be the timing, if you can comment on it of a development project on the peninsula of Malaysia?

Gene, our stretch goal is to have something in the fourth quarter of '06. We need to test this well and see gas rates versus liquids rates and have a better sense of what type of development that we have, and that will drive us a little bit. But it's doable if we get about it.

Claiborne, it appears that you have enough oil to do a kind of -- to replicate west Pat. Would that be -- would that be before any type of a gas development, which would probably be separate from that?

Gene, that's the issue that hasn't been decided. There's arguments either way. It could. We need to see rates and we need to see where that's going to drive us. I'll have a much better sense of that at the end of the year.

Second question, can you give us an idea of what the T block reserves that you sold and proceeds from the sale.

Gosh, we're looking at each other blank. I want to say--

I think it's 1.5 million barrels. About 1500 barrels a day of production. We sold it for almost $20 million.

Lastly to follow up on Fred's Leuffer's question, does the tax bill in any sense improve the economics or the possibility of committing some capital at Superior?

The short answer is no. The big win there was getting our requirement to put in equipment to fully desulfurize diesel pushed back to '09. There's an interim standard we need to make and have met. And I don't think the tax bill is going to help us much beyond that I think that's the big win. It buys us three or four years to kind of see what the future lies there.

To the extent then that most of your spending at Meraux was prior to '04, there's really not going to be any significant benefit then?

There's potentially some, Gene. You've just got to work it all through. That's what we're in the process of doing now.

Kevin, has there been a determination of whether or not you're going to lease part, all, or own Frontrunner thus far?

Gene, we financed it out of cash flow. We've been approached about various leases, we've looked at them, and I haven't found anything that can -- that's a better financing alternative than my normal avenues.

Okay. Hurricane, the impact of the hurricane on owned structures out there hasn't changed your mind, has it?

If somebody wants to do me a deal that's cheaper than what I can do otherwise, you know, I'd be happy with it. I've got cheaper alternatives and haven't been convinced otherwise yet.

Thank you.

Thank you. Our next question is from Mark Gillman with the Benchmark Company. Please go ahead.

Claiborne and folk, how are you? Hope all is well.

Good, Mark.

Couple of things, this Mackelow prospect and hopefully I'm not mispronouncing it, whose prospect is it and what's the appeal, Claiborne?

Chevron is the operator. This is the appeal. You can clearly see the bottom is salt, and you have to drill through a lot of salt, it's mid miocene. It's about 30,000 feet TD planned total depth. You can put lots of sand in it right as you come out of salt, lots of miocene sands, miocene sands so far in the play have proven to be extremely prolific, great P&P and a couple thousand feet of objective section. So you can see a pretty clear 3,000 acre three-way trap, a very clear 3,000 acre three-way trap. So it's got size. You can put sands in it. The bottom of salt, which is always hard to define. Is real clear here. It's got all the criteria that we look for. The promote is steep. But if you look at what leases that look like this were going for in the last lease sale, I was looking yesterday, in fact, Greed came to 468 and 512, which is very similar to this, except it's a four-way -- we bid on it, so I know -- those two blocks go for $66 million. The promote pretty much reflects what you'd have to pay to get it now. It's a little bit better than that, really. But I think that's a rough way to look at it. So that's the appeal. We'd like Moore, in fact. But Moore wasn't available and, gee, query do you really want more two for one promote. So 10% works because of the size of the prospect is big enough to carry it. So that's about how we thought about it.

Is there an analog to Mackelow.

Tahiti is not a bad one.

That's what I thought.

It's the same play. It's stacked miocene sands, 5,000 feet of them coming out of salt. If you can get the sands there, and we have laws that you can clearly put sands there, and you have a trap which you can see, which we can, it's a hydrocarbon risk at that point. There's lots of hydrocarbon in that system we know. It's risky because it's subsalt. But given the way you look at prospects in the gulf now and given what we have, it's a good prospect.

Okay. Just a couple of other things, if I could. What did you pay for the Canadian heavy property?

$120 million.

Okay. Where do you stand on cost recovery at west Pat ?

You know, Mark, we're spending a fair amount of money in what we call phase two right now and we've got four more wells to drill another platform. So I haven't looked at anything recently. But I would say that we're a year away or something like that. The threshold number from an economic standpoint to look for is when you produce 30 million barrels. That's when the government take goes up and step change. The payback piece as you pay back once, one and a half, twice, the incremental increase, once you produce 30 million barrels is when you get a pretty good chunk taken out. We're a ways away from that. We ought to be at this production level for another couple of years, I would guess. The field is producing more than we thought. Production is better than we thought. So we'll have a little bit of offset from higher government take from better production.

Finally, this is a bit superficial but let me try it anyway.

I can be superficial too, sometimes.

Are you laughing enough, guys? It seems from a very lay perspective, that as you try to step out from PK, that either in board or more to the central part of the block, the sand development is just not as good. Would you agree with that, or would you challenge it, as an observation?

Well, I'll answer it a bit obliquely, we don't yet understand how sand is distributed, Mark. The main risk that we thought we saw in Senangan was really hydrocarbons. If you recall we drilled dry holes at sea cat. And they got lots of sands that are wet. At that time I said, look, the model is not busted, because sand was there, we had a breached trap. In fact, that's proofed to be true. As we stepped out, we had hydrocarbons at Senangan.. I noted in the reference that they were thinner sands than Kehkai. And they are, but Kehkai was you have to recall an enormous sand pile. And Senangan is going to be a nice discovery. We'll appraise it and we'll either have a stand alone or tie it back to Kehkai. It's not quite as sand rich but it's not sand poor. Todac is really thin sand so that was just clearly non-commercial. We don't understand the middle part of the block yet. There's other trap types that we haven't tested that could have big sand piles. We know that Shell had a big sand pile, at least we think they did in their well 20 kilometers away. So that shouldn't be as much of a risk. I can't definitively say yea or nay. I can tell you that we have big traps and that we have sands and we have hydrocarbons. And have we found another big pile of sand, outside of Kehkai, no, except for Kakap, we have. It's too early to draw significant conclusions.

Thanks a lot. Appreciate the answer.

Thank you. Ladies and gentlemen, if there are any additional questions, please press the star followed by the one at this time. And as a reminder, if you are using speakerphone equipment, you will need to lift the handset before pressing the numbers. Our next question is a follow-up question from Steve Enger. Please go ahead.

Couple of things. Claiborne, what's your view now of insurance recovery from Meraux? I think there was some pretty good sized numbers there that could be positive for you in the future. Any view on timing and how is that going with the insurance companies?

Steve, you'll see a bit in the fourth quarter, I would hope. We have a fair amount of money out there that's owed us. And it's just an issue of going through really complicated models. P&L models with people who represent insurance companies who are paid by the hour and trying to agree. It's one of those things you've got to throw lots of people at it. We'll reach a number, then they will start questioning it, but we're close. And we're getting close on the first quarter particularly, then we'll work on the second quarter. So you'll see some, I hope, benefit in the fourth quarter. Them you ought to see the balance of it in the first or second quarter next year.

Sounds like fun.

Well, you've dealt with them before.

Yeah. Can you give us a ballpark on what the amount, total amount could be?

I'd say minimum $20 million. Then it goes up from there. But I'd be real loathe to say how much more.

Separate topic, back on Malaysia and gas markets, independents in Malaysia, would seem to be some competition from some other projects out there. How do you see that market in the next couple year timeframe you guys are targeting, how critical is it for you to get gas going quickly. Can you access that Talisman pipeline, is there really going to be space available and any other comments you have on that market.

Steve, the way we see it now, we have low Co2 gas, that's a premium in that particular basin. There's lots of high Co2 streams out there that need our gas to make them marketable. So there's currently always a capacity in that line that goes past us that originates the Talisman field, and we think it's going to continue to have a fair amount of spare capacity. I think our gas is needed. I think we got pipeline capacity. And should be all the ingredients to make a deal.

Okay. So there's not some critical window that you need to hit, otherwise you're locked out for several years?

We don't see it. Given especially the nature of our gas.

Okay.

Which is an increasingly needed commodity, low Co2 gas.

Okay, thanks.

Thank you. Our next question is from Ken Beer with Johnson Rice. Please go ahead.

Hey, guys. A lot of information out there. I did want to see, Claiborne, if you had any current thoughts if you look out to '05 kind of what your production numbers might look like for '05 now. I think most of the Ivan adjustment will be made more in '04, with '05 being pretty clean.

It will, Ken. And we're putting our budget together, so I hate to start giving numbers. But the numbers we've told you before, so it will be in the 130s, I think that's a reasonable number.

No adjustment off of that.

Not right now. Now, I'll give you a caveat. We're sitting down next week to go over our budget and we're going to do it region by region and field by field by the big fields and see where the risks are. But that's what the numbers add up to. One thing that I think everyone underestimates, certainly me, in these big deep water gulf fields, if you think about Murphy, we have six wells at Medusa we're going to have eight wells at Frontrunner, we have two wells at Habanero, that's 16 wells. Sixteen wells is what produces all of our hydrocarbons in the Gulf of Mexico basically.

Right.

So before on the shelf it shows 113, we had 100 wells alone in that particular field. So there is risk that one well goes down, one well gets sanded up, one well has a mechanical problem, one well underperforms. There's just more risks there. And there's more risks than I probably -- stupid me -- appreciated. So I just bear that in mind as we go forward. Everything right now is fine. Medusa produces 40,000 barrels a day, five out of six wells going. We had the problem at Habanero with the subsurface safety valve and that hurt us. So you'll see stuff like that occur more. With that caveat and the caveat of not sitting down and going through our budget, we're looking about in the 130s.

Gotcha. Fair enough, then. All right, guys. Thank you.

Thank you. Mr. Deming, we have no additional questions at this time.

Okey-doke. I appreciate it very much. Thank you.

Ladies and gentlemen, this concludes the Murphy Oil corporation third quarter conference call. If you would like to listen to a replay of today's conference you may dial 1-800-405-2236 followed by access number 11012230. Once again, we thank you for your participation. Have a pleasant afternoon. You may now disconnect.