Murphy Oil Corp (MUR) 2005 Q1 法說會逐字稿

Good morning, ladies and gentlemen and welcome to the Murphy Oil Corporation's first quarter earnings release 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. [OPERATOR INSTRUCTIONS] As a reminder, this conference is being recorded today, Thursday, April 28th, 2005.

I would now like it turn the conference over to Claiborne Deming, President and Chief Executive Officer. Please go ahead.

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

Thank you, Clairborne. And welcome, everyone, to our call. Today we will follow our usual format. John will begin by giving brief review of first quarter results, Claiborne will follow with an operations update and then we'll 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 will occur or that the projections will be attained. There are a variety of factors that may cause actual results to differ, many of these have been identified in Murphy's January 1997 Form 8-K filed with the SEC.

And with that said, I will turn it over to John.

Thank you very much, Mindy. And good day to everyone. Our net income in the first quarter of 2005 for Murphy Oil Corporation was 113.2 million, which equates to $1.20 per share. That's up 15% from the earnings net income that we had in the first quarter of '04, which was 98.2 million and $1.05.

The first quarter of '04 included the results from discontinued operations, which was income of 17.5 million, $0.19 per share, related to properties that we sold in the second quarter of 2004 in Western Canada. These were conventional properties -- oil and gas properties in Western Canada. So when you take those out and we've accounted for those as discontinued operations, when you take those out our first quarter earnings for '05 are still 113.2 million, but our first quarter '04 before discontinued operations was 80.7 million or $0.86 a share. So from a continuing operations, it's a 40% increase in results.

In looking at it by segment, our E&P earnings in the first quarter of the just completed quarter in '05 was almost 125 million versus 101 million a year ago. Our E&P earnings where improvement was mostly caused by higher oil price, the Company realized a $9 a barrel jump in our average sales price for crude oil. Higher exploration expense, however, somewhat tempered the affect of higher oil prices.

Our exploration expense increased $21 million, mostly caused by two dry holes in the Republic of Congo. Also in the 2004 period, it included a $15 million gain on disposal of two natural gas properties on shore United States and of course that did not repeat in 2005.

Our oil production rose 14% in the first quarter of '05 and equated to 108,700 barrels a day, compared to the same period in '04 it was up again by about 14%. The increase was mostly attributable to higher deepwater Gulf of Mexico production at two fields, Medusa and Front Runner.

Natural gas prices in North America were 14% higher this year. Our natural gas production declined by 12 million feet a day, primarily due to lost production from our Viosca Knoll's Block 783 property, which we call Tahoe. This field was hampered -- production from this field was hampered during much of the quarter following Hurricane Ivan, which occurred very early in the fourth quarter of '04.

Our downstream business lost $5.5 million in the first quarter of '05, that's compared to a loss of 6.4 million in the first quarter of '04. Our downstream results in the just completed quarter were hurt by rising crude oil prices, and margins at our U.S. retail marketing chain were squeezed as we had difficulty fully passing on higher wholesale gasoline prices to our customers.

Our results from our corporate area included net cost of just over $6 million in 2005, compared to 14 million in '04. The 2000 period had higher interest income because of interest received on a U.S. tax settlement, and also had higher invested cash proceeds that we earned interest on from the sale of the Western Canada assets previously mentioned. We also had lower net interest expense. We had less borrowing levels, lower borrowing levels and higher interest capitalization. We did incur higher G&A expense related to both stock-based incentive plans and higher retirement expense.

I will close by saying that our long-term debt at the end of March of 2005 was virtually unchanged from the year-end 2004, and stood at $613 million, a debt-to-capital ratio of 18.5% at March 31st.

With that, I would like to turn it over to Claiborne for comments.

Thanks, John. I will review development projects, production, both current and forecast, exploratory wells, and downstream activities. At that point, I'll take questions. And I'll start with developments.

Medusa, one of the six wells that's being worked over and will be back up in about three weeks. Current production is around 36,000 barrel equivalents a day. North Medusa, where we have a 17% interest, just came up, and is producing 5,500 barrels per day. Importantly, it pays for one-seventh of the spar operating costs.

At Front Runner, we have two wells on stream producing 30,000 barrel equivalents a day. A third well is coming on stream now, and the fourth well will come on stream in about 60 days. At Habanero, we're producing right at 25,000 barrel equivalents a day. And at Kikeh, we recently awarded the dry tree unit spar contract technique, along with the FPSO, we now have two of the four large contracts awarded. A few more announcements, contract announcements will be forthcoming.

At Kenarong, also in Malaysia on the Peninsula side, we plan to submit field development plans to Petronas, for both Kenarong and Pertang in July for 500 Bcf, 40 million-barrel project.

On the production front, we are in the process of selling approximately 4,000 barrel equivalents a day of Gulf of Mexico production. This production has an average cash lifting cost in excess of $15 per barrel, and represents approximately 7.5 million barrels of reserves. This cleans out our shelf properties and represents the last of our mature property sales into what is an extremely robust market. It should close in June. As a result, we will take down our production target for the year to 125,000 barrel equivalents a day.

Drilling at Thunderhawk, where we have a 37.5% interest in Mississippi Canyon Block 734, encountered over 500 feet of net pay, the same two sands we saw in the first well. Since then, we have been stuck in loop currents and have made no further progress. Once they move away and there are -- it's evidenced that they're moving away, we will get back to drilling. But this will be well wildcatting and not appraising.

Also in the Gulf, we will likely spud a miocene prospect called Krakatoa in Mississippi Canyon Block 540 where we have a 25% interest, located one block from Medusa. It's an 80 million barrel prospect and will produce through Medusa spar if we're successful.

In Malaysia, offshore Sabah, we announced a successful appraisal well at the Kakap structure in Block K, where we encountered around 150 feet of net pay. The well tested over 5,000 barrels a day, with diminimus pressure draw down. It was a very strong test. This field will be developed jointly with Shell, who will operate.

We drilled a dry hole at Jangas, also in Block K. We found 20 meters of oil in high quality but thin bed pay and elected to expense the well. Nonetheless, we are conducting a study of completion techniques to determine ways to access what is a large amount of oil in place. The rig is moved over and is now drilling Kerici, located just out board of Kikeh Kecil. Kerici is around 100 to 150 million barrel prospect. After Kerici, the rig moved to drill a down-dip will at Kikeh Kecil where an oil water contact was never established. We farmed the rig out at that point for a two-well program to another company.

Offshore Sarawak, we are currently drilling a wildcat at the Indal [ph] prospect in SK 311. An oil prospect just south and west of the Rompin oil discovery. Rompin looks like a 20 million barrel to 40 million barrel discovery and Indal [ph] appears about the same size, perhaps a bit smaller. They would likely be jointly developed.

We just flow tested the go light gas discovery located in SK 309 at 40 million cubic feet per day and around 400 barrels of liquids from two zones. The rig drilling Indal [ph] will be farmed out to another company, and we will bring it back in the third quarter offshore Sarawak for an appraisal well to flow test the Serampang [ph] discovery, another large gas discovery located in SK 311.

Offshore Peninsula Malaysia, once the rig finishes at Serampang [ph], we will move it over to Peninsula side, likely towards the end of the summer, and drill back-to-back wildcats in PM 312 located near the center of the Malay Basin. We have a 75% interest in that concession. Later in the year, we will go north of the Kenarong discoveries and drill two wildcats looking for oil.

In the Conga, we are licking our wounds a bit after the two dry holes following the Azurite Marine discovery. Current plans are to get the rig back in the early fall, maybe late summer, and drill an appraisal on Azurite, flow test it, and then drill another wildcat. We have six very similar prospects to Azurite within 30 kilometers of the discovery. We will likely move south and west of Azurite for the next exploratory well.

In the downstream business at Meraux, our current crude charge is 115,000 barrels per day with $5.50 per barrel gross margin. We suffered a power outage in early March, which disrupted our ROSE unit and new sulphur recovery unit startups. The ROSE is now up and running well and the sulphur recovery unit is back up this weekend. Starting in May, we will be fully configured at Meraux for the first time since the June 2003 fire.

Superior had a weak first quarter and currently has about $1.50 per barrel gross margin. We start selling asphalt in mid-May, move at least a fair amount of value at that time throughout the balance of the summer. Milford Haven is down for a turn around until mid-May.

At Wal-Mart we now have over 790 units in operation. We had a very poor first quarter as wholesale gasoline prices increased by $0.53 per gallon during the three months. Currently, business is quite profitable with strong double-digit retail margins.

And I'll take questions at this time.

Thank you, sir. Ladies and gentlemen, at this time we'll begin the question-and-answer session. [OPERATOR INSTRUCTIONS] Our first question comes from Jennifer Rowland with J.P. Morgan. Please go ahead.

Thanks. I wonder if you can give us a breakdown on the production guidance both for Q2 and also the full-year guidance that you gave of 125, if you can break that down by region.

Mindy, can you do that?

I'll do that for you, Jen. For the second quarter in the U.S. we're expecting about 35,000 barrels of oil a day; Canada, including syn crude, 45,000 barrels of oil a day; UK., 8,500; Ecuador, 7,500; Malaysia, 13,000; and then on the gas side, about 85 million cubic feet a day in the U.S., 10 in Canada and 6.5 in the U.K. For the the full year, and this range is largely dependent on when and if we are able to sell that shelf production because that will impact where we are in the -- in our range, but we should be somewhere around 30,000 barrels of oil a day, 12,000 in heavy, 25,000 a day offshore, 10 or 11 in syn crude, 8,000 a day in the U.K., 8,000 in Ecuador, 12 in Malaysia, 85 in the U.S., and this is gas, 85 million cubic feet a day in the U.S., 12 in Canada and around 9 in the U.K.

Okay. Great. And any update on the Ecuador situation, whether or not that resolution is going to result in a cash settlement?

I'm optimistic, Jennifer, it's going to resolve, but I've been optimistic before. I suspect it will be. It's just an issue of we do it in barrels or money and we'll get there. I suspect we'll get there this quarter, but it may be next.

Okay. Great. Thank you.

Next question comes from Mark Gilman with the Benchmark Company. Please go ahead.

Claiborne, how are you?

Good, Mark. How are you doing?

Pretty good. I got a couple things. First, clarifying a comment you made, I'm not sure I got down, regarding Pertang and Kenarong. You were talking about one development with combined 500 B 40 million barrel potential?

That's our current plan, Mark, that's not all the reserves that are there. Especially on the gas side. But that's our -- that's the basis of our current field development plan. It's really going to be an area development plan submittal. Once we get that going, I think we can -- there's room for more, but that's the current basis of our discussion.

You don't have a gas contract yet, though, do you?

No, sir. And once you submit your area development plan, that's what triggers that discussion. So I can't tell you when that will be concluded.

Okay. Do you have a sense with respect to Kakap [inaudible], how that resource might be shared between your interest and Shell's?

No, I don't. It's premature. It's premature. But it will be the subject of discussion over the next six months to nine months.

Okay. And let me -- forgive the lack of technical expertise, but I need to raise a question regarding what you've seen in the Congo. It seems to me that if you're relying on faulting to be the communication vehicle between pre-salt sources and post-salt prospects, that to a certain extent, it's going to be limiting the size of the structures to a series of fault blocks and, therefore, smaller accumulations. Is this consistent with the way you're now seeing it or am I just completely off base?

Oh, Mark, I haven't thought of it that way. And it's early in our evaluation of it. What we concluded so far is that you need faulting from pre-salt source up to the structure. And we didn't have it in the other two. We had it in Azurite. So that's the one thing that we concluded so far is the difference between the three, because we had nice sands and we had nice trap in sapphire and onyx.

So our current view, just in general, is to look for prospects that have that type of sourcing, and sourcing is always typically the most difficult of the three or four components you're looking for in a prospect. We know the basin is real oily, and we were drilling on structures that had ancient stream beds which had oil and other prospects in it. So we thought we reduced our risk, but we hadn't. And so we think we need a pre-salt source, and we think we got that now in hindsight from Azurite. That's where we think if we go -- especially to the south and west where we have a number of additional prospects, those are the characteristics we think we'll find.

Okay. Just one more, if I could.

Sure.

It's increasingly looking like the outboard side of K is less prospective than the inboard areas, including going toward blocks G and J. Is that the conclusion you're coming to?

What's happening, once you get outboard -- we'll find out from Kerici here in the next couple weeks, but we think there's a likelihood of pretty good sand in Kerici. Once you get outboard of Kerici, then we're finding thin bed pay in the area near what you could call the pizza slice, where we found Kikeh and Kakap. If you go further to the north, they're still finding plenty of sand.

Now we haven't always found it in our wells, but we have in some of our wells up there. For example, the first well, the Bagang had lots of sand. So it's not really a sand issue up there as much as it might be down in the southern part of the Block. But given the big time success at Kibabogin [ph], we know there's lots of sand and oil charge sand in that part of the Block, we just haven't unlocked the key.

But I think it is a fair statement to say once you get outboard, so far Kikeh Kecil in the southern part of the block that we're having difficulty finding piles of sand. We're finding charge, we're finding real high quality sand, but we're not finding big blocky box car sands. So it's a head scratcher.

Now, what we're going to do, there's lots of oil in Jangas, lots of oil in Senangin. And Cilacap, which we dry holed last year actually had thin bed pays. So suddenly it begs the question we've got a heck of a resource here locked up in thinner bed sands. Query is their way to unlock it. Likely, with much lower recovery rates because you probably couldn't pressure it with water given the number of sands. It would be primary recovery. And there's going to be a big enough resource, in fact, it's real big that there's probably some opportunity there. But it's not the same quality of field as Kikeh and Kakap are, and I think that's a reasonable expectation to draw.

Now, is that pervasive? We don't know yet. There's still only one exploratory well for every million-plus acres, so it's still early days and there's other play types. But the issue of lack of big box car sands outboard of Kikeh Kecil is something we don't like. That's not the issue of the northern part of the Block. I'm starting to repeat myself, but there's just some keys up there that we need to understand better that we don't have yet.

Claiborne, thanks a lot.

Okay.

[OPERATOR INSTRUCTIONS] Our next question comes from Donald Dexter with Dorsett Energy Funds. Please go ahead.

Good afternoon, everybody. Claiborne, earlier in the call, I think you mentioned that you want to go ahead and produce -- I think the numbers you mentioned were 500 Bcf of gas, 40 million barrels of oil, and I think that was from what Pertang and Senangin, is that right?

Pertang and Kenarong.

Yes, Kenarong. Sorry. What would you think of in terms of production numbers or years they allow you to pull this out of the ground, in other words, what sort of volumes could that represent?

Don, it's early. I mean I really don't want to prejudice any type of subsequent negotiations that we might -- the plan will have a number in it, however, but I have to admit I just don't know what it is. It may be in the range of 125 to 150 million a day, I'm guessing a bit. That's probably not going to be too far off. And the liquids would be probably in the range of 5,000 to 10,000 barrels a day, probably 10,000. But as noted in an earlier question, we need to negotiate a gas price. That's going to be real important here. There's a pipeline nearby that's got oil so that's not an issue. We have low C02 gas, which is a real positive. But we have to sit down and negotiate price.

But it could be 30,000 barrels a day equivalent, then, something like that.

Roughly. Roughly. That's eight-eighths [ph] and we're going to have 75% of that.

Right.

And so -- but that's roughly the numbers right now. As I mentioned earlier, the gas resource there is bigger, and there's a deeper zone of Pertang that we never quite got to.

Right. Right.

That has a lot of come on. So likely, there's a significantly bigger resource there. But we're starting with what we know and what's low C02 gas for sure. That's roughly the envelope.

Good. Well, thank you very much.

Yes, sir.

And our next question comes from Steve Enger with Petrie Parkman. Please go ahead.

Hi, guys.

Hey, Steve how you doing?

Good. A couple things. On Kakap and potential timing, what would you guess at this point? And then related to that, has the government given you any clarity from their standpoint as to kind of how they would like to see developments queued up?

Steve, because we're going to be involved with other companies specifically to majors, and because one of the other majors is going to be operator, I really don't have the latitude I would have had with Kikeh with information. But, in general, it will be obviously after Kikeh. There's a lot of work to be done. We need to negotiate all sorts of agreements, we need to negotiate equity splits. We just tested our wells and we're gathering information, Shell's done likewise and we're exchanging information. But all of that's got to be agreed before we actually submit development plans. So it's clearly post 2007 when Kikeh comes on. '09? I'm guessing, though, I'm purely guessing.

Has the government given you any sense, Claiborne, would they like to see these things come on every couple years and just grow production over a long period of time. Or do you have a different sense from them?

No. We really don't have a sense of that. That what their preferred timing is. But you would logically conclude that you wouldn't want to bring everything on at one time.

Right.

But we really haven't gotten privy to their view on that.

Okay. And then in Block K or in the deepwater, I'll say more broadly, I think in Block K, what do you see targeting in terms of wildcats next, when you get the rig back and come back later this year, how many more of them do you see drilling that are kind of drill ready at this point?

Two thoughts, one, let's see what we do in Kerici because if we're lucky there, there's obviously an offset or two to go. There's a large prospect up in the northern part of the Block that we'll get real interested in and if some other operators are going to drill some wells end up having some luck, will prompt some interest up there. And then at some point, we're likely going to come back and drill another well at Senangin. We had thin bed pays there, but they were vertically connected, some of them were.

And so we think that the thin beds merge into one bigger sand pile and so we need to find that sand pile at Senangin, so that's likely a well, but we're going to do this study on Jangas. Jangas and Senangin are actually part of the same huge structure, really, really long big structure. So there's suddenly a lot -- a lot of interest in our company of, gee, how do we access what's a big resource? But it doesn't look like the other fields that we found. But there's probably a well there. So that's what I can tell you now.

Okay. Okay. Thanks.

And our next question comes from Mark Fisher with Fisher Sites Capital.

Yes. I was wondering if you still plan to drill a second well on the Todak structure this year?

It's in the works, it's kind of the same issue, Mark, and that is that we had some encouragement. In fact, we had one real big sand that was wet in Todak and we're remapping, and we want to get a sense we can get charge into that sand in another fault block and Todak is one of these really long big structures with two or three fault blocks. So depending upon technical work that's going on right now, we will. But we don't have a firm plan for it now.

And a rig would be available if you chose to drill it sometime this year?

Yes. We've got a rig. Really, we've got the same rig all the way through the development of Kikeh, Ocean Rover, so we're okay rig-wise.

Got you. Okay. Thanks a lot.

Okay.

And our next question comes from Jacques Rousseau with Friedman, Billings, Ramsey.

Good afternoon.

Good afternoon.

Just a question for you on the downstream. I was curious if you had any statistics on same store gasoline sales periods over periods? And then also just curious how much cash you had at the end of the quarter.

We're up compared to last quarter in the range of 5 to 8%, something like that store to store.

Great.

What was your second question?

Cash on the balance sheet.

Cash on the balance sheet.

464.

Cash and cash equivalents?

Yes.

464.

Great. Thank you very much.

Okay.

And our next question comes from Jean Gil he is pi with Howard we will. Please go ahead.

Claiborne, do you have any makeup production from Ecuador in the production guidance for the full year?

No.

So that's about 1.5 million barrels that if you do it volumetrically that would be additive in the second half, perhaps.

Yes. And, Gene, whether it's volumetrically or whether it's cash, I don't know yet. It depends what day you ask me.

Also, Gene, the barrels have been produced. They just haven't been sold.

Yes. I understand that, yes. Okay. I was just trying to get a handle on the magnitude.

Yes.

Okay. Good.

And our next question comes from Mark Meyer with Simmons & Company. Please go ahead.

Good afternoon, Claiborne.

Hey.

Just one question. You spoke, I think or at least I read somewhat optimistically about perhaps getting past the loop current problems at Thunderhawk. I know you don't operate, but what are you seeing? There's a fairly significant precedent out there that these things can be a little more chronic than first expected.

Actually, we do operate at Thunderhawk. We assumed operatorship. And I'm very optimistic that we'll be able to get back to work. We're looking at it. We're -- I think we're going to be okay there. Hopefully, we can get back to work in the real near future.

So you have seen some change in severity?

Yes, we have in the last couple days, three days, it's subsided, and subsided significantly.

Yes. Sorry. I had forgotten you guys had taken over. That's all I had.

Okay.

Thanks.

At this time I have no there are no further questions in the queue. I would like to turn the conference back over to management for any concluding comments.

Thanks very much. Appreciate your attendance.

And, ladies and gentlemen, that does conclude the Murphy Oil Corporation first quarter earnings conference. If you would like to listen to a replay of today's conference you may dial 1-800-405-2236 using pass code 11028320#. Thank you again for your participation on today's conference. You may now disconnect.