Murphy Oil Corp (MUR) 2003 Q3 法說會逐字稿

Good afternoon 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 the conference, please press star followed by the zero. As a reminder, this conference is being recorded today, Wednesday, October 29th, 2003. I would now like to turn the conference over to Mr. Claiborne Deming, President and Chief Executive Officer. Please go ahead sir.

Thank you. I'm joined by John Eckhart our controller, Kevin Fitzgerald, our treasurer, and Mindy West, our director of shareholder relations who I will now turn the program over to Mindy.

Thank you, Claiborne. John will give a brief review of third quarter results then Claiborne will follow with an operations update and then we will take your questions. Please keep in mind that some of the calls made during this call will be considered forward-looking statements. As such no assurances can be given that these event will occur or that the projections will be obtained. 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 second. We will discuss certain non GAAP measures and the reconciliation is also included on our Website at www.murphyoilcorp.com/IR and with that said I quill turn it over to John.

Thank you Mindy and good afternoon everyone. The net income of Murphy Oil Corporation for the just-completed third quarter of '03 was $73.1 million or 79 cents on a diluted share basis. That compares to $37.4 million of net income or 41 cents of diluted share in the third quarter of '02. Both periods included net benefits and net income from special items. The third quarter of '03 included $9.4 million of net benefits which was 10 cents a share, and that compares to $7.9 million of net benefits in the third quarter '02 which was nine cents a share. The special items included in the just completed quarter 3 include an $11.4 million tax benefit in Malaysia that tax benefits generated in prior years. Generally accepted accounting principals require that tax benefits cannot be recognized until their really assured. Shall owe water SK 309 have commenced our assessments indicate that future taxable income will be such to utilize these prior year expenses in our future tax returns and thus we recognize those benefits at this time. We also have $5.4 million of after- tax foreign currency gains that are associated with U.S. dollar denominated assets and liabilities in our Canadian operations. We had $5.1 million of after tax additional cost related to our Meraux refinery fire, and we had $2.3 million of after tax impairment charges related to Gulf of Mexico properties.

Excluding these special items in our earnings our earnings were $63.7 million or 69 cents a share in '03 quarter, and $29.5 million or 32 cents a share in the third quarter of '02. Breaking these down then by business, our E and P business, exploration and production generated a profit of $62.5 million this quarter versus 47 million of '02 and that's an increase of 33%. Our downstream was profitable generating $10.3 million in earnings compared to a loss of nearly 14 million in '02. The $15 million improvement in E and P was primarily due to higher oil sales volumes where we were up 37 barrels a day and better North American sales prices which improved to 4.60 approximately this quarter. Exploration expenses were higher in the just completed quarter compared to the 2002 third quarter, and total $48 million this quarter compared to $17 million in the same quarter of '02. Total oil protection was 84,800 barrels a day, quarterly record for the company. Our natural gas production declined from $288 million cubic feet in 2002 to $203 million in 2003. And that decline is primarily due to the field decline at Ladyfern in western Canada. The increase in our oil production was approximately -- which was up about 14,000 barrels a day was related to West Patricia SK 409 commenced production late in the second quarter. Our downstream earnings were improved in both the U.S. and the U.K. businesses. In this quarter compared to the '02 quarter. As we enjoyed much stronger margins in the U.S. in both our upper mid western refining and wholesale business and our retail marketing business.

Our corporate net cost excluding special items increased by $4 million this quarter compared to '02 and it was due to lower tax benefits and higher employee benefit cost. For the nine months ended September 30th, '03, and again excluding special items, our income was almost $196 million or $2.11 a share. That compares to $46 million and 50 cents a share in the first nine months of '02. Our exploration and production business earned more than double in '03 for the nine months and that is more than double the first nine months of '02 and of course better oil and gas sales prices and we had higher sales volumes, oil sales volumes which accounted for the increase. And finally our downstream business on a year-to-date basis earned $19 million excluding special items compared to a loss of $35 million in the 2002 period, once again our U.S. refining and marketing margins were much improved in the nine months of this year, and likewise, we had much stronger margins in the U.K. in the 2003 period. With that I'd like to turn it over to Claiborne for his comments.

Thanks job. I'll start with an update on the development projects, go over the exploration plans for the near term, and close with downstream results and then I'll take questions. First, development projects. First, is Medusa, first production is now mid December. I mean sorry, mid November. Delay caused by to some degree weather but primarily it's simply taken longer to complete the six pre-drill [inaudible]. It is an extremely porous sand, loosely consolidated, they all need [inaudible] packs. It is the most critical part of the development. We're taking the time I don't like it but it's probably the right thing to do. Habanera should be the first week in December. The derrick barge is now in the field, Ecuador, heavy crude pipeline is completed currently producing 60,000 barrels a day from the block going to 65,000 barrels a day by December. We're going to need some additional capital which will be in next year's capital program to get to 75,000 barrels a day primarily due to the fact that we need additional water handling capability in the field. The capacity for the oil is there we just need more processing equipment. Front runner wholesale was earlier this month. We should be on location later in the year.

Top sides installation is June or July of '04. First oil is August to October. As we get closer to it, we'll narrow that window a bit. Looking at exploration, our exploration program in the Gulf, we have two deep shelf wells drilling one at south Pelto 19 where we have 50% interest, intermediate department and 75 BCF plus or minus. South Temblor is the second, 23% paying 29. 75 BCF plus or minus as well. Likely well spud this weekend and probably that latter well is a 60-plus day well. In our deep water program, we'll spud probably LeComte and perhaps Johnny's Wagon one or the two beginning of the first quarter, driven by the availability of the Amos Runner which is on another location but going to be available we now think at the end of the year.

Secondly, is Thunder Hawk, Mississippi Canyon, spud first or second quarter, probably the first quarter of '04. South Medusa which is in Mississippi Canyon 621, 85% interest, just south of the Medusa field, 15 to 25 million barrel potential, probably first quarterback end of the first quarter spud. Lastly Dalmatian where we have 50% quarter, Desoto canyon, first half and it is an East earn Gulf will so the pacing item is going to be permitting. Canada we got back to [inaudible] to Stolberg (ph), and Foothills we have 35% interest and we’ll be down before the end of the year. And then we have three Devonian prospects that we’re drawing west of Ladyfern, Millgan and Weisel are a bit behind but they all should be down by the end of the year. Malaysia in our Shallow Water Program the wall prospect and SK 309 was wet. And will be plugged and abandoned. It was right offsetting the West Patricia field. West Patricia however is performing substantially better than we had anticipated with much less pressure draw-down and we're likely at 40-plus million barrels recoverable there now.

Block K the rig which is conducting the drill stem test on Kikeh No. 4 is nearing the completion of that text and we should be releasing results in the next ten perhaps 14 days. The rig will then move to the Kikeh No. 6, this is where the producers are going to be located, producers at the top. And we don't have a well penetrate there yet so we want to put one there to confirm our reservoir model. That should take less than 30 days. Then the rig moves to the Iah prospect, which is on trend with Kikeh Cacheal (ph)to the west 100 to 300 million barrel prospects. When that's completed we'll likely move to the other side of the Kikeh Cacheal prospect, on trend 100 to 300 million barrels roughly the same size as Iah. Next year we will continuously drill in Block K and we've got a number of prospects yet untested, it's going to be a big part of our program next year. Block H well near Keebabogen likely in the second quarter of '04. And in -- picked up two Peninsula Malaysia blocks last year, 75% interest drill a well likely first quarter of next year PM 311 to confirm a preexisting discovery called Bundy which is a gas field which we shot 3D over it looks quite promising and we'll confirm that that's there and then likely if it goes the way we hope and think then we'll get about developing that.

Lastly exploration wise is Congo, it’s mapping out nicely for the first half of ’04 likely farm it out and lot of interest in that acreage. Downstream Meraux has restarted. It's been a ragged restart for us as the hydro cracker is integrated and we expanded new equipment new instrumentation on and all of that is being brought up of course in the backdrop of the fire. But we're up and if we were up fully at 125,000 barrels a day and we're not yet, we'd be -- we'd have about a loss of 50 cents a barrel plus or minus somewhere around there. Superior earning four bucks a barrel and has been for the last couple of months. Real strong asphalt season. Milford Haven, Wall Mart, we passed 600 sites today, we should be around 615. We had an unusually strong September, October is weaker but still pretty good. So with that update I'll now field any questions you might have.

Thank you sir. Ladies and gentlemen we will begin the question-and-answer session. If you have a question, please press star, followed by the 1 on your push-button phone. If you would like to decline from the apology process, please press star followed by the 2. You will hear a three-tone prompt acknowledging your question. Your questions will be polled in the order they are received. If you user speaker equipment you will need to lift the hand set. Our first question comes from Tyler Dann please state your affiliation.

Banc of America Securities. How are you?

Hi.

Timing, first of all on Block K. In terms of the -- looks like we'll be completing the drill stem test by kind of a mid-November time frame. From there, it takes the crest appraisal well, so how long do you anticipate that to be drilling?

30 days.

30 days?

Yeah.

Okay. And okay. That's fair there. I -- I think I missed exactly what you were saying about Block H so would you mind for my benefit alone, would you mind repeating what your activity is going to look like on block H and when that's going to probably take place?

I was brief about it. We'll drill a well near Keebabogen. As you recall we went to the middle of the block and we drilled greedily the biggest structure there. Had pretty good shows but clearly we need to get back closer to what's worked. And so we're loosely saying second quarter. It's driven a bit by rig availability there. We have nothing under contract right now. But the mapping is about done and there's some good things to drill.

Okay. And I guess my final question would be on the deep water exploration in the Gulf of Mexico, is it me or is there a bit of a -- I wouldn't want to characterize it necessarily as a delay, but I had been under the assumption that the Johnny's Wagon might be a bit earlier. Am I mistaken in that?

There is a lot of discussion in the partnership. It's pretty well-known that we have some disagreement on which prospect ought to come next. Johnny's Wagon is 50 to 70 million barrels big bright amplitude. LeComte which is the other prospect which is in the running is bigger. Not quite as bright. Probably better looking structure. And you'll drill deeper so you'll see more section, and as a result, you'll learn more about the southern part of mini basin. So there's pluses and minuses for each of these. So I kind of carefully couched it that we'll do one or the other. A lot of the timing, by the way, is driven by the availability of rigs. The rig that we get back is the Amos Runner that we still have under contract for about 100 more days. And that rig will go most likely to the Frontrunner mini basin. That's really the pacing item here. And while we're waiting we're talking.

Got you. Real quick on Ecuador, the incremental capital required to get to 75,000 a day and is that above and beyond what you had been budgeting?

I don't know yet, Tyler. I don't think it's going to be huge. It's water handling so it's pipes and pumps, compressors, and tanks. But I don't have a handle on it. It's relatively new news. Because we got it up, we thought we'd get 75 and lo and behold we have more water producing than we anticipated. You always produce a lot of water in this particular project. It's the way the world works there. And so it was -- we missed on how much. And so there's going to be some capital required to get it. And so haven't seen a number yet. This is, you know, 30 day old news, 25, so I haven't seen what the operator's fix is.

Okay. Super. Thanks for the update. I appreciate it.

Okay.

Our next question comes from Fred Leuffer.(ph) Please state your company name followed by your question.

Bear Stearns.

Hi Fred.

Two questions Claiborne. First it looks like the tax rate and EMP has been trending down. What is a good going-forward rate to use? And then secondly, do you have any news on the Brunei (ph) Malaysia territorial dispute and what are you thinking about you know at this stage as far as drilling wells in Block L? I think you had two scheduled for next year.

Fred, I'll answer the latter one, second one first then I'm going to let John Eckhart or Kevin handle the tax question. The disagreement and negotiation between Malaysia and Brunei is really state to state and we're not part of it so I don't know. Not to be flip but that's just the truth. And what we do next year with regard to that acreage is really driven by the availability of it. And so that's where it is. If it becomes available we'll likely get about it. If it stays in limbo then we'll obviously sit on the sidelines.

Nothing new there?

No, not to me.

Fred as you may recall we sold Ninian and Columba (ph), and it had PRT associated with it. There is no PRT in the U.K. anymore so that drives down the average rate on combined basis for E and P. If you put it all together, we're probably between 38, 38 and 40% overall based on the mix, and it's a mix issue. You are U.S. at a 35% rate and Malaysia now on the shall owe water we're at 38%. Canada it varies depending on whether you're talking about offshore or onshore, onshore being about a 42% rate, and Syncrude (ph) being 33% to 35%. Depends on the mix but 38% and U.K. by the way is 40 for what's left over there with no PRT. Depends on the mix but I'd say 38% to 40% depending on the mix.

Terrific thank you.

Next question comes from Mark Gilman. Please state your company name followed by your question.

First Albany. Good afternoon folks.

Good afternoon.

What happened Claiborne with Habanera?

It is a pacing item on the derrick barge. It was stuck. I think it was a McDermott barge and it was in another job that got caught in loop currents. So it was really unfortunately stuck on station there for a couple of months, 60 days or so. And so that was the only one available for the type of work we needed to get done or Shell needed to get done at Habanera. They final got it and they are on track and that's it.

Looks like you cut the peak in half and are back to a one well option looks like as opposed to two?

No, I don't think so. I think we're still talking about 8,000 barrels a day is where it's going to end up. Oil and natural gas.

I'm sorry, Claiborne?

Claiborne Deming I think we're still at 8,000 Mark. All I said was, it's barrel equivalents. There's some natural gas primarily oil at the outset.

Okay. Have we reached a point of some degree of stabilization on the Ladyfern decline?

No. No, in fact I asked that very question this morning. And regrettably, the answer is no. We're dropping net to our account probably $5 million a month, something like that.

Okay. My arithmetic may be off and I guess it might be a function of both my advanced age as well as the data today is.

You're younger than I am, aren't you?

It's marginal Claiborne at best. I'm coming up with like a 7.50 per barrel DD&A at West Pat. Is that right?

Little bit south of seven. I'd say 6.50.

I thought it was much lower than that? It was going to be much lower than that and you're talking about a better reserve base.

Well, we haven't booked those yet, one, and two, the other side of that, Phase 2 which is a water injection phase is going to cost more than we originally anticipated and unfortunately eaten up the reserves so the DD&A cost ought to stay the same. Lifting cost is about 3.50 something like that so about 9 bucks.

One final one if I could. I wonder if maybe John in lay terms can walk through what the impact of this Medusa lease is going to be, in terms of the kind of numbers we're going to see in terms of DD&A and lifting cost?

John or me?

Whatever.

Okay. He was looking at me, I was looking at him.

Which ever one of you wants to take it.

Claiborne Deming We should be talking about 8-plus, 8.50 DD&A something like that and 2, 2.50 lifting cost, something like that. Our share is 60 million barrels, yes, 60 million barrels. So that's about it. Say 8.50 plus 2.50.

Yeah, but with a lease it's not going to be DD&A is it?

It will be in -- under a lease situation Mark we would have to pay a tariff.

I'm sorry I wasn't understanding you properly.

And the tariff is --

If we ended up doing a transaction, DD&A would come down say four bucks a barrel. Lifting cost would go up four bucks a barrel, something. It's a little bit of a tradeoff. Well, almost a 100% tradeoff, going from DD&A to lifting cost.

That would be the sum total of the impact of it?

Yeah, just about. Yeah. Now if we do a deal, now we've talked about this for a year, we haven't done anything. And they're not easy and so I wouldn't count on it but at the same time something may come together and we might do something.

But what's been talked about you'd pull 100 million in capital out of this is that right net to you?

Yes, that's right, that's correct. I can tell you this for my planning purposes and for the budget we're putting together right now planning purposes, I'm assuming we don't do anything there. But if we did do something, then that would be the impact, correct.

Okay, folks, thanks a lot.

Welcome.

Our next question comes from Ken Beer. Please state your company name.

John Strauss. Flipping over to Malaysia, in '04 moving to Block K. Is that with the single rig or would you be bringing in another rig? What's the activity level we might expect in Block K for next year?

Ken, if we're just talking K which I'm assuming we are, it's one rig. And these things -- I say these things, these wildcat wells really don't take that long to drill. We're only talking seven or 8,000 feet below the bud line. So they're logging, et cetera, they're 45 days sometimes less and you can drill a heck of a lot of wells.

Would you think about bouncing back and forth between using that rig for appraisal and then exploration plays kind of what you've done this year?

Right now that would be a plan. If you start making discoveries, then maybe you accelerate that a bit. But for now, we're talking about using one rig and we're talking about using the same rig for drilling wildcat, side tracking, any appraisal work.

Okay. And one last one while we're still over there. If indeed there's a thumbs-up agreement in Block L would you then bring in a separate rig or would that one rig that you spoke of be shared? I'm assuming you'd bring in --

You know, that's all a lot of speculation there and I'm going to just say I'll step by that question.

All right. All right, thanks. That's it for me then, thanks.

Thank you.

Next question comes from Mark Meyer, state your company name followed by your question.

Simmons and Company. Claiborne, deeply on the deep shelf test, can you give us some gross cost with the south Pelto wells please?

I'm going to guesstimate a bit, somebody here, South Pelto $19 million is $10 million gross and we have 50% interest in south Timbalor (ph)some we have 29% of that cost. And that won't be too bad wrong. There -- you know they're deep.

And that's most of what's in the variance for Q4 in terms of exploration expense?

Yeah.

And what else decisions is not clear outside of those two wells?

Yeah, yeah. There are Stolberg issues, Mark, that we'll have to address, and those are the primary drivers. I'm trying to think if there's anything else. Yeah, the Wadry hole which is $3 million, we get tax relief on that because it's in an income-producing license.

Switch to Medusa real quick.

We don't get tax relief.

I'm sorry, there's one more. We're participating in a well off the coast of Ireland called Cong. I tend to forget about it and it's about $3 million and there's no tax relief in, about 20 clicks from Koreb. We've had the license since '94 and it's finally time to drill it.

Switch to Medusa, you cited weather but primarily longer completion experience early on with the fract (ph) packs. What was the original cycle time estimate and what is it now on a per well basis?

I can't be that specific. We hoped we would be up in the, now we're looking at the middle of November, and you know, it gets kind of specific bit but there's one particular well we were going to go to, it ends up that there's a piece of equipment that connects the riser to the underground pipe that didn't work. And so we had to say okay, let's go back and fix that later, let's complete another well. And went to that well that we'd picked second, and the drilling -- the completion fluid which had been in the well bore since we drilled the well a year ago, had done some bad things. So it took us four or five additional days to clear that out. Bay right primarily had been the culprit. Couple days of bad weather. One thing adds to another. They're all excuses but they happen to be accurate.

Does any of this have an influence, maybe it's semantics, the startup for Frontrunner, August and September I think, last update was mid year?

In August I would stretch and say is mid year. And the October date is Claiborne throwing in a broader window because you know, live and learn.

That's all I had, thank you.

Okay.

Next question comes from Arjun Murti (ph) State your question.

Thank you, I'm with Goldman Sachs. Claiborne, I know there is disputed between two companies ongoing and out of your purview. If it's not resolved in some reasonable period of time, does that impact your decision to move forward and develop the Kikeh area or make a decision to wait to see on what you may or may not have on Block L?

I don't think it will have any effect on what we have Arjun We have a discreet reservoir an Block K at Kikeh. We are narrowing down on what the right option to produce is and I think we'll arrive at that by the end of the year. And then we'll sanction it early next year by our board, and get about it.

Okay, so you don't feel you even need to wait for some of the Kikeh Cacheal and the other two prospects in that area before determining to move ahead?

No, no. I don't. You know, over time, as we learn more about the -- what's called the Kikeh trend now, I think our options on what we do subsequent to the first producing facility will expand. And the twinet (ph) or do you go to something else. But the first thing we need to go is focus on okay, let's lock in on something that is a facility that we could use to produce Kikeh and let's get about doing it. Because if we wait and delay this thing will not be '07, it will be '08 or '09. We spent a year looking at it so by gosh we ought to know so let's pick one and let's move on.

Do you plan to continue your hedging program into 2004?

Not so far. You know, I'm wrong every single time. And so if we don't do it probably is the wrong thing to do.

I hear you, thanks Claiborne.

Next question comes from Irene Haas. Please state your company name followed by your question.

This is Sanders Morris Harris. Irene Haas. I'm curious when the topside will be welded, the timing for that, and when would you be hooking up the first well and roughly how long does it take month, month and a half and how many wells total that will be hooked up at the Frontrunner complex when you are totally done?

Wow, that is a mouthful and I won't be able to answer all that. Top Side's installation is June or July. We'll start completing wells right as soon as the darn thing is installed. Numbers of wells, I think we have five, six. Seven, I'm being corrected, seven. And then the earliest you can have first oil is August. And I've added kind of a fudge factor and said well maybe it's October. That's all I know to respond to you.

Okay. Roughly, how long would it take, you know, is judging from your experience, how long, you know, under normal circumstances with no LOOP current per se, how long usually does it take to hook up a typical well?

Well, I don't know if there is such a thing as a typical well. And I hate to be evasive. 20 days.

Thank you.

Our next question comes from Bruce Blythe (ph). Please state your company name, followed by question.

Company News. Back in July you said you expected lower crude prices during the remainder of the year, down to perhaps the $25 a barrel area. I was wondering if you changed your outlook at all. Especially in light of the OPEC cut that is expected next month and expand on any of your price expectations for next year.

As typical, I'm wrong. My gut feel tells me, with the rack coming on stream with some West African fields coming up, we know Ecuadorian production is going to add a couple hundred thousand barrels, unless the world economy picks up materially, you'll see a seasonal low, I mean that's been my history in this business. Now, if there's some intervening event, then so be it and prices stay high. But we should see some softening in crude prices, I think that's a reasonable expectation.

And can you specify any particular price range or area you're expecting here?

I decline.

Okay. And how might this affect your operations?

You know, we're pretty slick. Our budget, which is being put together now based on crude prices substantially less than what we have now. And so we should be able to fully fund next year without any issues.

And last question, just a quick update on your U.S. refinery operations, you brought the Meraux refinery back up again in late September. Everything operating okay there?

Yeah, everything is getting back to normal. You know, as I mentioned at the outset we had a fire. Then we had a turnaround plan to integrate this brand-new unit in, and then we did revamps on three of our main vessels or units during the turnaround. So we had this confluence of three events. And it's been a ragged startup and I anticipated it would be. We're increasing the footprint of the plant by about 40% and it is. And so we're not quite to where we want to be but we're certainly starting up. So Superior's going fine and Meraux will be fine soon.

What are you processing then roughly on a daily basis at Meraux?

We're going to average for the month something 85,000 something like that plus or minus.

For October?

Yeah, something like that.

Okay, thank you.

Okay.

Our next question comes from Gene Gillespie, please state your company name followed by your question.

Howard Weil. Claiborne, you suggested that all end cost at Medusa about $11 a barrel and that's at $60 million gross?

Is that's at 60 million eight eights.

Ten months into the year. Can you give us just a broad general feel as it relates to refining cost and reserve replacement experience?

Yuck. It depends what we book in Malaysia, Gene. We've got barrels to book, Kikeh, depending on a couple of factors, we will have something to do that. We have fields that outperform but other than that we don't really have anyplace to look to add. So it's going to be driven really by Malaysia.

What is the critical date or critical event as it relates to the sanctioning of a development plan for Kikeh in terms of your building to book?

Well, it's fuzzy as you would probably expect. You've got to be sufficiently advanced in it to have a reasonable degree of certainty you're going to go forward. And that's about what the language reads and all the clarifications read. It will not be officially sanctioned by the end of the year but we'll have all the technical data to know what the range of reserves has done. And we'll also know what type of facility that we're going to use. And we'll also have lots of quotes from people on how much those would cost. And so we'll look at all that information, and then we'll make some conclusions as to what we can do.

Thank you.

Our next question comes from James Mahony. Please state your company name followed by your company.

Hello, it is the Daily Oil Bulletin. My question is for Claiborne, you mentioned Ladyfern would be off five million for the next few months. I wondered other than the three Devonian prospects you mentioned, for the next three quarters in West Canada. Other targets in terms of bringing production back.

Not to counteract that, no. We really don't. We have a pretty active program called our central program, Central Alberta, $150,000 wells and we'll drill ten or 15 a month. But they simply won't be enough given risk to counteract that. That's just the sad but accurate truth.

Okay. Great, thank you very much.

Our next question comes from David Wheeler, please state your company name followed by your question.

I'm with J.P. Morgan. Hi Claiborne. Can you give us any update on production guidance for '04?

I can give you a feel. Again we're putting together our budget. Early numbers we'll average 150, exit the year 165 or something like that.

Over at Kikeh, I know that the flow rates aren't in yet on the production test but you did some cores that I guess were pretty encouraging as to potential recovery rates. Are you more comfortable with either end of the four to 700 million barrel range right now?

No. We're not going to really -- probably we'll keep that range for a while longer David. I'm trying to think of a good response. Once we get all the data, you look at it and work it, then we'll narrow it over time. We came up with that number I was thinking about the other day after our third well and we've drilled a bit more since then, we'll have test and data, we'll look at it to see where we go. The big variant in that is where is the water. Recovery factor is an issue and we'll -- we'll be pretty conservative there. I would hope there'd be some room there. And there probably will be some room on where the water is. We'll probably assume some -- you know pretty conservative numbers there so as we get data we'll give more guidance but for now I'd say at 400-700m.

Do you know what Ladyfern produced in the third quarter net to you?

50. 50 million a day.

Okay. And last one for you, just the Gulf of Mexico exploration strategy, any sense that you're going to shift that away from kind of the stand-alone high-impact wells to more -- one that's more smaller targets around your new infrastructure around Medusa and Frontrunner?

It's going to be a combination David. In fact we had a planning session I was looking at our program and we were trying to agree what works and what works for Murphy. We'll probably have about a third of our program, deep water program will be on high impact stand-alone type prospects, conventional, Pleistocene, Flanksalt (ph), we'll continue that. Prospect inventory in that area is diminished, probably third of the program. About a third will be drilling around the two mini basins where we have infrastructure. And I see that as south Medusa and then we've got two others in the Medusa area that are good. They're good prospects. And I think there's a good chance we'll have some success there and then Frontrunner.

We haven't drilled south of the field except for Frontrunner south, or Quatrain I'm sorry in about a year. We went over to the other side and drilled Cool Papa which is was a dry hole. We don't know that much about the south end of the mini basin. There when to drill, how to drill, et cetera. But we'll certainly we'll get about that. And then the balance or another third will be you know, new trends out there. I'm not sure we'll drill many next year but we'll certainly position ourselves to participate in modestly deeper water and other what we call emerging trends.

Okay, that's helpful, thank you.

Ladies and gentlemen, if there are any additional questions, please press star followed by the 1 at this time. As a reminder, if you are using speaker equipment you will need to lift the hand set before pressing the numbers. One moment please for our next question. There are no further questions at this time. Please continue.

Well, thank you very much for joining us. And good afternoon.

Thank you, sir. Ladies and gentlemen, this concludes today's Murphy Oil Corporation third quarter conference call. If you would like to listen to a replay of today's conference please dial 800-405-2236, followed by access No. 555527. Once again if you would like to listen to a replay of today's conference, please dial 800-405-2236 followed by access No. 555527. We thank you for participating. You may now disconnect.