Murphy Oil Corp (MUR) 2009 Q2 法說會逐字稿

Ladies and gentleman, thank you for standing by and welcome to the Murphy Oil Corporation's second quarter 2009 earnings call. During today's presentation, all parties will be in listen-only mode. Following the presentation, the conference will be open for questions. (Operator Instructions). The conference is being recorded today Thursday, August 6, 2009. I would now like to turn the conference over to Mr. David Wood, President and CEO. Go ahead, sir.

Thanks, operator. Hello, everyone. Thanks for joining us on our call today. With me are Kevin Fitzgerald, Senior Vice President and Chief Financial Officer; John Eckhardt, Vice President and Controller; Mindy West, Vice President and Treasurer, and Dory Stiles, Manager of Investor Relations. Dory?

Thanks David. Today's call will follow our usual format. Kevin will begin by providing a review of second quarter 2009 results. David will then follow with an operational update after which questions will be taken. Please keep in mind that some of the comments made during this call will be considered forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995.

As such, no assurances can be given that these events will occur or that the projections will be attained. A variety of factors exist that may cause actual results to differ. For further discussion of risk factors see Murphy's 2008 annual report on file with the SEC. Murphy takes no duty to publicly update or revise any forward-looking statements. With that being said, I will now turn the call over to Kevin for his comments.

Thanks, Dory and welcome, everyone. Net income for the second quarter of '09 was $158.8 million or $0.83 per diluted share. This compares to net income in the second quarter of '08 of $619.2 million or $3.22 per diluted share. For the six months of '09, net income is $329.9 million, or $1.72 per diluted share. Compared to the net income of six months of '08 of $1,028.2 million or $5.36 per diluted share. Net income in the second quarter of '09 included a $24.7 million after-tax, $0.13 per diluted share charge associated with an anticipated reduction of our working interest in the Terra Nova field, offshore eastern Canada, that also included a $13.4 million of after tax gains of $0.07 per diluted share from insurance settlements related to property damage at the Meraux Louisiana refinery and a $2.1 million after-tax loss, thats $0.01 per share in discontinued operations, for post-closing settlements related to the sale of our Ecuador properties earlier this year.

Net income in the second quarter of '08 had included a $67.9 million after tax gain, or $0.35 per share, on the sale of our Lloyd Minster heavy oil properties in western Canada. For the 2009 six-month period net income included the above mentioned Terra Nova redetermination and insurance settlements along with after-tax gains of $103.6 million or $0.54 per diluted share, thats in discontinued operations, from the sale of our Ecuador properties. 2008 six-month period included after-tax gains from the sales of Canadian assets which included the just mentioned Lloyd Minster sale of $108.3 million or $0.57 per share.

Looking at income by segment, in the E&P segment net income from continuing ops for the second quarter of 2009 was $118.3 million, compared to net income of 2000 -- second quarter of '08 of $576.5 million. 2009 quarter included the previously mentioned Terra Nova charge, while the 2008 quarter included the gain from the sale of Lloyd minister property. Lower E&P earnings for 2009, were primarily attributable to lower crude oil and natural gas price realizations while production and sales volumes were higher. Crude oil and gas liquids production for the current quarter was over 118,000 barrels per day as compared to approximately 111,500 barrels per day in the corresponding 2008 quarter. This increase was primarily attributable to production from Kikeh, offshore Malaysia which was ramping up during 2008, this was partially offset by the sale of the Lloyd Minister and Ecuador properties, and by lower volumes that had (inaudible) off the East Coast of Canada and at [Syncrude] which were both due to maintenance down time. Natural gas sales volumes were 147 million cubic feet per day in the second quarter '09 compared to 55 million cubic feet per day in the second quarter of last year. This increase was attributable to the December 2008 start-up of production from [Tupper] in British Columbia and at Kikeh.

Looking at that time downstream segment, R&M net income for the second quarter of 2009 was $27.8 million, compared to net income in the second quarter '08 of $77.3 million. This earnings decline in the 2009 quarter was primarily in the UK where refining margins were much weaker than last year. Income from operations in the US was up in the current quarter due to slightly improved refining margins, the previously mentioned insurance settlements and improved utilization at Superior, which was down for about six weeks for a full plant turnaround during the second quarter of '08. In the corporate segment, second quarter of '09 we actually had add net benefit of $14.8 million, on the second quarter of '08 we had a et charge of $35.3 million.. This improvement is attributable to a combination of favorable foreign exchange results, mostly as the result of the US dollar weakening against the UK sterling and lower net interest expense due to lower interest rates on borrowed funds and higher amounts capitalized for development projects. As of June 30, 2009, our long-term debt amounted to a little over $1.5 billion which is approximately 18.7% of total capital employed. With that I'll turn it over to Dave.

Thanks, Kevin. The most recent quarter saw crude prices regain some ground and as a result our leverage to crude oil enabled to us capture the up side. Half this crude gone at a premium helping even further. On the natural gas side, bearish fundamentals continued to weigh down the market and we are not immune to that effect. Underhaul (inaudible) deep water project in the Gulf of Mexico was recently brought on stream and our Azurite project in the Republic of Congo is very near to first oil. Third project for natural gas in shallow water offshore Sarawak, Malaysia is rapidly advancing towards start-up. I will discuss each of these individually in a moment but want to say how proud I am of the commitment of the individuals within our organization who were responsible for bringing these projects on stream as efficiently as possible and with excellent safety performance. On the exploration front, recent successes in the Gulf of Mexico, Malaysia, and the Republic of Congo will aid in backfilling our top tier production growth profile. As I've stated many times before exploration remains a core of this company. We continue to look to add up side in additional undertakings such as resource plays or other value enhancing opportunities across our business.

In downstream, US gasoline demand appears to be mildly improving of late at least at our stations. Retail started the third quarter off on the right foot before seeing margins weaken over the last week as oil prices moved up again. Refining worldwide, however, remains challenged due to excess product supply, especially indistillates. After taking everything into account we are favorably positioned but still looking to add more opportunities.

Now, I thought I would take a few minutes and get a little more specific on our business units beginning with exploration and production. As mentioned, we achieved important exploration success on each of the four wells drilled during the second quarter. The Gulf of Mexico the Samurai well located in green canyon block 432 where we have a third interest, found oil. Appraisal options are being studied now and we will likely develop this as a subsea tie-back to an existing facility. Offshore Malaysia in Sabah, oil was discovered at the sea of cap north prospect located in block K not far from our Kikeh and K-cap fields. We have 80% in the sea of cap north (inaudible) discovery. An additional appraisal well is currently being drilled to further assess the find as development options continue to be studied. Offshore Sarawak, Malaysia, the east Patricia prospect found natural gas pay that will likely come to market utilizing existing infrastructure currently being developed. We have 60% in that prospect. Finally, offshore republic of Congo in the Mer Profonde Sud block or MPS, as we call it, the turquoise marine well, where we have 50% interest, found oil on a structure very analogous to our Azurite field that lies 17 miles to the south. Appraisal plans for that are being looked at now and the development tie-back to Azurite is on the table. Currently in the republic of Congo we are completing abandonment operations on an unsuccessful exploration well we just drilled in the MPS block on a prospect called diamond marine. The well found oil pay but in limited qualities -- quantities. While we've been quite active of late in exploration, things will naturally slow down in the second half of 2009. We plan to drill an eastern Gulf of Mexico well later this year. We will also commence drilling this month on our Eagleford shale position located in south Texas where we are still actively leasing. It's difficult to predict gas prices but I feel confident that with low cost supplies into any market situation, we'll be favorably placed to grow production.

In production activity, thunder hawk in Mississippi canyon 734 commenced production on July 8. Current production levels at the semi-submersible floating production unit, are approaching 27,000 barrels a day of gross production from two wells. Offshore the Republic of Congo, the Azurite project as mentioned earlier, was ready to produce any time as we work through a mechanical problem within our first completion. In Malaysia, Kikeh's average production for the month of July was 116,000 barrels of oil per day. Payout was achieved during the second quarter as anticipated, less than two years after first production, and this week marked our 100th successful lifting. British Columbia, Canada, or at our [Tupper] gas field, recent production volumes have been averaging in the mid-40s -- million of cubic feet per day. We are running three rigs, two at Tupper main and one at Tupper west. Just yesterday our board of directors approve the sanctioning of the Tupper west development opening the door for added production growth. How quickly we ramp up that project, will be influenced by natural gas prices which currently are weak.

During the third quarter we will begin producing natural gas at our Sarawak project, off shore Sarawak Malaysia in blocks 309 and 311. Production will ramp up to $250 million gross per day later this year and continue on for many years. Overall company wide production for the year could come in slightly lower than previously anticipated due to an array of factors including unplanned facility downtime, slower than anticipated ramp-ups and start-ups, and third-party processing issues. Depending on how the rest of the year shapes up, we anticipate that production for 2009 will average about 170,000 barrels of oily equivalent a day and a fourth quarter average of 210,000 barrels of oil equivalent a day.

In our downstream business, refining segments in both the US and the UK struggled most of the quarter with negative margins. While retail margins came under pressure during the quarter they improved toward the latter part of the quarter as wholesale gasoline prices fell. Today the Meraux refinery is operating near 100,000 barrels a day, while the Superior refinery is running up 36,000 barrels a day making asphalt. [Wilfordhaven] our UK refinery is currently running near 103,000 barrels a day. In US retail, we now have 1,036 retail outlets in operation, 993 of which are Murphy USA sites, plus 43 Murphy express sites. Volumes have improved from earlier in the year and for the month of June ran flat with previous year.

Overall I'm pleased with the recent success in our exploration program as well as achieving first production at thunder hawk. Additional milestones will be reached later this quarter as we bring on Azurite and Sarawak natural gas. And down stream, retail has moved as expected and we are well positioned for the remainder of the driving season. We are still seeing many more opportunities on the horizon. And I'm looking forward to our first group of wells in our Eagleford shale acreage.

As was announced yesterday, Harvey Doerr, who many of you know, was our executive vice president of downstream and planning, chose to retire from the company and return back to his native Canada. Harvey has served the company exceptionally well for over 20 years in various leadership roles. I certainly wish him and his family the very best and would like to thank him for his valuable contribution to Murphy Oil Corporation. Our downstream units will now be managed individually by three extremely capable leaders. That ends my prepared remarks. And I'm happy to take your questions.

Thank you. We'll now begin the question-and-answer session. (Operator Instructions). Our first question is from the line of Evan Calio with Morgan Stanley. Please go ahead, sir.

Hi, gentlemen, it's Ryan Todd here at Morgan Stanley. Just had add few follow-up questions on your Malaysian operations. As far as I understand your 3Q production target is around 76,000 barrels a day, which is almost up to the Q1 peak despite your transition to cost recovery. Can you talk through what the driver is there? Is it out-performance at the Kikeh field? And what's the best way to look at it going forward?

Let me answer the broader question and we can kind of drill down to Kikeh, I think. We're suffering from some project delays. Azurite I was hoping would be on production by now. It's got a problem in one of the valves, in one of the wells that we want to bring on, and we've kind of lost a couple weeks here, but I'm confident that we'll get that fixed and be able to bring that up. So that's a little bit of delay.

If I look at the whole year, we're talking about 170,000 barrels a day average. We're seeing some Sarawak gas delay and some Kikeh gas delay, that accounts for about 60% of the change and the rest is delay in thunder hawk for about eight days, and then one of the wells that we've got on is not performing as expected. It's doing okay, but it's not doing as we expected. That's about 1,100 barrels a day. And then Kikeh with the issues with gas and how that field has been working is about 1,500 barrels a day behind.

So, when you had a all that up and you throw in the positives and slide positives in Canada and the Gulf of Mexico gas, we're down about 4,900 barrels a day for the year. So, that's kind of the production guidance story there. Fourth quarter will still average 210,000 BOE a day. Specifically on Kikeh, part of its has been tied to this Kikeh gas and being able to get the gas off the facility on a consistent basis. The last few weeks, that's been doing much better, and so I think some of the relative performance is because we've overcome the change in entitlement with better operational performance, largely tied to that. We also had a flare tip on the facility that was repaired in the first quarter and kind of knocked that down a little bit. But that was just for a few days. Does that hopefully address your question?

Yes, I mean, is it still safe to say that in terms of kind of Kikeh net production volumes of the year going forward we should be looking in maybe the low 60,000 barrel a day range net?

No, it should be in the low 70s, Ryan.

In the low 70s.

Right, on a percentage basis of net, in the low 60 percentile range, but production barrels actually, you're talking about in barrels in the low 70s.

Great, thanks.

That often gets confused when we talk about barrels and percentages. So, I think it's a good question that you've got. Dory has actually addressed that.

Great. I appreciate that. If I could have one follow-up as well, you mentioned opportunities that you -- you're still considering taking advantage of opportunities that you see in the environment out there. Can you talk through what type of opportunities you're seeing and maybe how you're looking at the world and how maybe it's changed since the last conference call a few months ago?

You know, it's a funny world we live in, I'll say that. Oil prices are high, and I'm not quite so sure I understand the fundamentals as to why gas prices are low. I wish they were higher. We are seeing continued opportunities for gas, particularly in North America, which is why we're still leasing in the eagleford and why we're continuing to grow our position up in British Columbia for gas. But that's kind of a long-term view.

I think -- and I've talked about this before, being able to bring gas on in the $4 world and less, if you can, I think is going to give you advantage long-temperatures, and so that's the type of thing we look for in North America. A lot of our exploration takes place outside of the US, and we're still trying to look for oil opportunities. I'm very pleased that some of the discoveries that we've made here so far this year have been oil and have been places that we think there's further running room. Next year, we'll get to drill in places like Surinam, which we've had that acreage here now for a couple of years. Just finished shooting some 3-D this year. We've got some blocks in Indonesia and Australia.

So, those type of positions I think will continue to grow. Acquisitions still the bid spread, bid [asked] spread is still kind of wide, but we look at those. We look at joint ventures. And so I think we'll be able to do some deals here in the next 12 months. But I'm not in a big rush, because -- and now you have exploration success, we have a little bit more cushion here, but I'd like to get our exploration program back up to a little higher level of activity than just five or six wells a year, so we'll be watching ourselves pretty close to do that. There's just lots of things being looked at.

Okay, great thanks, David I appreciate it.

You bet.

Thank you, our next question is from the line of Mark Gilman with Benchmark & Company. Go ahead.

Folks, good afternoon. I had had a couple of things. First, David, you referred to processing issues as one of the reasons for the reduction in the 2009 outlook. Were you referring to issues in the Tupper area with that comment?

No, in Tupper we're producing a little over 40 -- actually 60 something today, but we've been averaging 40 million, the and we've got some new wells to bring on there. This is not a processing issue there. I think the most recent issue we had to deal with was pretty strong thunderstorms. Typical things like that, Mark, up in that part of the world.

Well, what's the processing issue you were referring to, then?

Yes, third-party processing at the methanol plant, Mark.

Oh, okay.

I've mentioned that before. That plant is not taking as much gas, but here recently it's doing much better. So, that's the real issue.

Okay. David, could you talk a little bit about what kind of access options you have from longer term perspective to the [bentulu] LNG facility taking into consideration the recent [east pat] discovery?

East Pat is nice because it just kind of back stops stuff that we've already got. Don't hold me to these numbers, but it gives you the order of magnitude of how busy we've been in Sarawak. I think we've drilled 32 exploration wells, 42 appraisal wells, and we found a number of gas fields, albeit quite small. Phase 1 development of Sarawak gas, is just three fields. In phase 2 is two fields.

And so we've got a number of small fields that now we've established the infrastructure that can be brought on, tied to how much gas demand there is. And so that's really not, in our control, that's a business that we're going to have to work out along with our partner (inaudible) with petro (inaudible). How much gas do they want, when they want it. The thing, from my perspective that is important, is I think we've discovered the reserves now, they need some more appraisal, et cetera, but I'm pretty pleased with the overall position that we've got there. Having said that, with the level of exploration that's been done there over the years by us, clearly a lot of wells, a lot of appraisal, that level of activity isn't going to be kept up going forward. And so -- but I do think we have a lot of drilling activity for things that are found that need to be appraised.

David, am I interpreting your comments correctly, such that what you're seeing is a plateau, an extended plateau at this 250 or 300 a day level, from Sarawak and not anything incremental there to?

You know, I can't answer that question, because I don't know what the demand is from the company that buys the gas. It's not a mechanical deliverability, Mark, because I think we could deliver on a rate basis substantially more. But that's the way we've designed this system, is 250, stepping up to 350, and we can do that for quite a long period of time if we're asked to produce higher than that, (inaudible) we can accommodate that.

Okay, just one more from me. I'm a little bit curious as to the reasoning behind drilling an appraisal well on [seacap] north given what was indicated to be the small size of that prospect. Did the result of that first well alter your pre drill expectations on the prospect? What's the thinking behind an appraisal as opposed to just straight tieing it back to Kikeh?

Yes, Mark, that's a very good question. The issue is that the structure is shared with another block. So, we have to appraise our piece of that feature just like it's been appraised or will be appraised on the other side. So, that's the issue there, as you remember from how we've developed Kikeh water injection and the efficient use of water injection is critical to maximize recovery in any field. If you have a field that's shared across a lease line, you need to have a unified development so that you maximize the results of water injection and minimize the costs. And so the reason for drilling an appraisal well now is simply we need to know what's on the side of our line, that's all.

Great, thanks a lot, David.

You bet.

Thank you. Our next question comes from the line of Blake Fernandez with Howard Weil. Please go ahead.

Good afternoon, guys. My question is on the underlift, overlift standpoint. If I'm not mistaken we were under lifted first quarter and second quarter and then it appears that guidance for 3Q is for another underlift. And I'm just trying to get an understanding for where we are on balance from an underlift and overlift standpoint and if 4Q could potentially see a reversal.

Okay, Blake, this is Dory. For the six months ended at the end of June, we were in an underlift position of about 840,000 barrels.

840,000 at the end of June.

Right.

Third quarter guidance has a total underlift, as you see of, 7,000 barrels a day primarily, the components of that would be Malaysia and the the Congo.

Okay. Great. And then my second question was on the R&M. It looked like performance was really strong, at least relative to what we were looking for, and obviously the refining industry has been suffering quite a bit. Is it fair to say that a lot of that performance came out of the retail division, and if so, is there a way to kind of provide a contribution by percentage.

Yes, I think it's safe to say that everybody is refining is getting beaten up and we're probably no different. I think what happened, and where the discrepancy is in the UK for us, we had cat problems with the milford haven refinery, so it should have had better results. So, on a relative basis, the first quarter and the second quarter should have have looked more equivalent. We had about, I think 56 days of either the cat shut down or impaired operations, and so that impacted how that refinery was running in the first quarter relative to the second quarter. If it was running, we would have done much better.

Okay, well thanks a lot, guys, appreciate it.

You bet, thanks Blake.

Thank you. Our next question comes from the line of Paul Cheng with Barclays Capital.

Hello, guys.

Hello, Paul.

Just have a quick question. David, do you have a forecast for the 2010, any change (inaudible) I think you've been talking about 205 with a bid of maybe that uncertainty in the North American natural gas market. Should we assume that that will be a pretty decent one or that need to be shaped a bit?

I think that's pretty decent. And yes, there is uncertainty in the North American market, Paul. I'd love to have a crystal ball to be able to see where prices are going, but I don't. In our ramp-up here, in what we're doing is kind of going to be tied to where we think prices are.

Right, can you tell us that in the 205 for next year guidance what if the Malaysian gas and also Canadian gas assumption, and also that if you can tell us similarly, that for the fourth quarter when you're talking about 210,000 barrel per day target, what is the Malaysian and Canadian gas volume?

Sure. For the -- you said the fourth quarter on your last part of your question, Paul, is that right?

Right. And also for 2010.

Sure, fourth quarter Malaysian gas would be about 250 million a day, Canadian gas about 74 million a day.

Okay.

And for 2010, the -- I may have to get that number for you, Paul. The numbers -- Sarawak looks like in the low 30 million on a BOE basis. Its how I've got it broken out on my sheet here. I don't have the full level of detail. And for Canada on a BOE basis, probably about just under 12,000 a day on a BOE basis.

So, that is 72 -- meaning cubic feet per day?

Right.

So, it will be close back to the fourth quarter level you expect?

Then would you also have a Kikeh gas component as well in there, Paul.

Right.

Which is probably about 80 million a day.

So, that 80 million for the Kikeh gas and then you say its 30, so that's 180 million cubic feet a day for the [sour] gas?

Yes, that's right.

Okay. Okay, and --

Well, you're right on the numbers there.

Anyway, maybe this is for either Kevin or David also. In Congo, with that starting up, what kind of operating cause and DD&A run rate should we assume initially, on a per (inaudible)basis?

Yes, you know, the way I would look at it is for next year -- this year we're going to have relatively small volumes, but if I look at kind of next year, we're looking at a operating cost of about $14.50 in the DD&A in the order of $23 that kind of range, Paul.

Dave, I mean, as you finish the initial ramp-up is those way is going to go down, or they is going to stay pretty flat around there?

The -- talking about Azurite development there Paul, is that right?

No, I mean -- when is the -- the next year that I presume, you haven't book all the reserves, so maybe as a result your DD&A is still going to be on a unit cost basis that is higher. Should we assume that as you move to the end next year or early part of 2011 that your unit run rate on the unit cost as well as cash call and DD&A will start to go down, or not really?

Paul, we've not booked anything at Azurite so far. Our first booking will be this year.

Okay, thank you.

Thank you.

Thank you. Our next question comes from the line of Gene Gillespie with Gillespie Consulting group. Go ahead.

I've got two things. One, in terms -- just a modeling question, looking at third quarter, what would be looking at profit versus cost recovery barrels from Kikeh to be around 50/50?

Gene, I will look into that and get back to you. I don't have that breakout. Gene that seems awfully low, but why don't you let us get that question specifically answered.

Okay.

It seems low just at the outset.

Which side of it sounds low?

The profit split?

Yes.

But why don't you let us get you a number.

That's fine. Second question, you kind of reminded me, I know it's early in the year to talk about the reserve replacement, but under the circumstances, you've had four discoveries this year. You have no bookings for Azurite, you have a very minimal -- I think its about 6 million BOEs -- bookings for thunder hawk. Sarawak gas is starting up and you'll have some significant production experience by the end of the year hopefully. You've just sanctioned west Tupper. You've got over 100 million barrels of unbooked Kikeh reserves. There's a lot of BOEs there when you total it up. Any comments?

Yes, you know, I like having lots of things to book that I know where they are, Gene, and so we're working hard to keep that going. For Tupper west, I think that's going to be a great project for us. This phase 1 that we've sanctioned should get us 900 plus net bcf. We have a Phase II that's just a little less than that that we'll sanction in future years. And so, projects like that do really well. Eagleford, which we'll drill our first well here this month, I'm hoping that we'll have some production tests from that well in November and then, you know, if you get to put that on-line, in the event that it does what we think it's going to do, there will be something there as well. So, I kind of like the momentum that we have here. For the most part, our main projects still have some sizable amounts of booking ahead. So, that's always the best place to be.

Sounds good, thank you, David.

Thanks, Gene, I appreciate it.

Thank you. Our next question is from the line of Michael Jacobs with Tudor Pickering Holt. Go ahead.

Thank you. Good afternoon.

Hello, Mike.

Just thinking back to two years ago when you're acquiring 3-D and offshore Surinam, can you talk about the geologic concept when you first entered the play?

Yes, the real attraction there is the cretaceous -- low cretaceous aged source rock that works very well in Venezuela. And what we were looking at was difficulty in defining things attractive in Venezuela. Not that the geology is not attractive. And so, we tried to move that same geology around and see where else it could be. And we looked at a number of place.

We recognized a play for a turbonite fan sequence within that same source rock interval offshore at Surinam, and we to a good ground and were successful in picking up the block that we've picked up, which we have 100%. We actually just finished shooting 3-D, beginning of this year and now getting the data in. In that same time frame, there was announced success in West Africa that if you reconstruct how the world was, puts that successful play juxtaposed to this same area. And so we think some of the things that, from a geological perspective, have worked very well in West Africa, are kind of key elements in what we're now seeing in our data, and hope to see even more as we get to work the 3-D harder offshore Surinam. The encouragement directly in the country is that there is a field on shore called tamboredo, which is probably a billion barrels in place, and it sits in sands that sit right on basin.

So, the oil has got to have been sourced from deeper in the basin. The acreage we picked up is deeper in the basin. And so we're looking for relatively subtle stratographic type drafts that we think on the data quality that we think we're going to get, which we've kind of got a good indication of, we should be able to see. That's name of the game. It's jack-up water depth. It has lots of running room and as an old exploration guy, and they don't let me do any exploration any more, I get pretty excited when I see things like that. So, I'm anxious to drill it next year.

So kind of just following up on that, the African analog, if you think about a concept where you've got a gassy shelf coming on and creating traps for oil accumulations, how many of those types of structures do you think you see offshore Surinam.

It isn't a question of structures, because what you're dealing with is an interval of source rock that might be on the order of 2,000 to 3,000 feet thick. And so what we're looking to play is discrete sand intervals that were deposited within that section. And so the number of sand fans, if you will, could be a large number. They may not be sitting on top of each other. They may be geographically separate. Or we hope they sit on top of each other, and they've been sourced by the common source, and you could have, if you will, multiple horizons all on one similar type of feature. So, those are kind of the two end members. So, it's not so much number of structures, because I don't think we're going to be drilling four-way dip structures so much, but it's how many of the discrete fan units do you see in this relatively thick source rock section.

Do you have -- are you planning to test that any time soon?

As soon as we get comfortable next year I'd love to drill a well, or more than one.

And then if I could squeeze in one more on the eagleford, you mentioned actively, or ongoing lease efforts from a high level, given where you're it at, I believe you're between the Edwards and the slaigo reef, are you thinking of adding additional acreage more to the east or more to the west?

Yes, the play in concept I think stretches in a pretty good length as a ribbon between the two reef trends you mentioned, and we're looking at all of that area. We're primarily focused on the gas part here, but don't preclude an interest in the oily (inaudible) and beyond that I really don't want to hamper our lease guys, otherwise they'll say it's my fault for lease costs going up in certain (inaudible) versus others. S,o I'll bow to the pressure from them and say we're still very actively leasing, very interested in the play.

Having said that, all we've got to go off of is other the people's results, because we've not drilled a well, but we're going to fix that this month. So,the wells that we are going to drill we're going to core and ultimately drill them horizontal and frac them, so we're very much climbing a learning curve ourselves, but there's a lot of other people active. We have been getting good experience from our British Columbia effort in the (inaudible) I think we have a good idea of what we need to do and so we're going to apply that here. Overall I like the play.

Great, thank you very much.

Thanks.

Thank you. Our next question is from the line of Jim Mahoney with The Daily Oil Bulletin.

Hello, Jim.

Good morning -- or good afternoon. The question I had was interference to Tupper west. And I think you mentioned, David, that you would be bringing on production later on this year. And I'm wondering, is this the best time to bring on new production, given that you've added 92 million a day in second quarter from -- between Malaysia and Canada, I think it's roughly -- it's approaching that figure. And it just strikes me that some companies might consider shutting in gas when prices are this low.

Yes, Jim, let me just correct one thing. Tupper west we sanctioned here this week with our board but first gas won't take place until the second quarter 2011. Tupper main is currently on production. So, that's the production that I was talking about.

In 2011, in the second quarter, I'm hoping gas prices are going to be better than we are now. If they're not, I think that's going to say a whole lot more about a whole lot of other things. I'm quite happy for other people to shut their gas production in and let me produce, by the way. I would say that. That we do have, I think, gas up there that makes money at $4. But clearly gas prices are lower than that up there. And so we're taking a very conservative approach to bringing new production on and we won't ramp up until we see things that kind of make sense. So, I think that's along the lines that you were saying.

And just following up on that, is there a gas price at which you would shut in production? In other words, if gas falls low enough is there a point where you would shut in some of the Canadian production?

I'm not looking at doing that now. And so, I think we've got to see what the -- not the day to day issues are, but kind of some longer term issues. I mean now our operating costs up in Canada or for gas are close to $1.

I see. Okay. Thank you.

You bet, thanks, Jim

Thank you. (Operator Instructions). Our next question is from the line of Kate Lucas with Collins Stewart. Please go ahead.

Hello, good afternoon. I just had a quick question on your foreign exchange during the quarter. How much of it -- how much of the gain was attributable to a change in the value of your Canadian government securities?

None, because we're Canadian functional up in Canada.

Okay.

And they're all the Canadian securities. It's primarily -- there's some in Malaysia. It's primarily UK.

Okay, thanks.

Thank you. Our next question is a follow-up from the line of Mark Gilman with Benchmark and Company. Please go ahead.

Hello, guys, I just had a -- I guess a bit of a procedural question regarding this redetermination at Terra Nova. I'm not quite sure I understand why the release suggests that the arbitration process that will go forward from here, could only further reduce your working interest, as opposed to potentially increasing it. Could you put some color on how this whole thing is working and why the statement regarding only further reductions?

Yes. Mark, let me kind of help you here. There is a -- under the operating agreement, there is a single set redetermination process. And that kicks in if and when all the parties cannot agree on a revised working interest going forward. And so we got to that point. We all had opinions as a group, and we all could not agree. So, we're now kicking off a process where we have to select an expert. That expert has not been finalized yet, and we've not signed the contract.

So, I'm a little loathe to start going into the who said what and who says what level everybody else should be. What will happen once that expert has been chosen is that each of the parties, of which we're one, will make formal submissions as to what specifically they think that working interest for all the parties should fall down to. And then this expert will pick one of the cases. So, there isn't a negotiation sliding scale, let's say there's five submissions, then the expert will pick one submission is and it won't be moved around from that. So, that's kind of the process. I'm not expecting anything until the end of 2010. And so what you've got in our notification is the fact that its likely that we're going to come down in interest. So, that's the process. That's the time line, and that's what's happening there, Mark.

So, I guess just make sure I understand, you know what the submissions are of the remaining four, and all of them would suggest a reduction at least equal to what you've proposed, if not greater.

No.

Is that what you're saying?

No, what I'm saying is in the discussions that have been taking place so far, where -- and we've not had had official submissions from anybody, there has been quite a range, and so that's why we couldn't reach agreement. That's why we're going into the redetermination process now. We haven't seen the official -- this is company A's opinion, company B's opinion. We haven't got there yet.

Well, without (inaudible) laboring it, why couldn't the reduction be less than, David?

Well, it could. It could. You're absolutely right. It could be more I hope, but I don't think so.

Okay. Thanks a lot.

You bet.

Thank you. Our next question is also follow-up from the line of Gene Gillespie with Gillespie Consulting Group. Go ahead.

David, what's next in the Congo? You didn't provide any real follow-up. I know that the -- you have an issue with rig in the short term, but what are the plans for, lets say, over the next couple of quarters?

Yes, you know, Gene, I was hoping somebody was going to ask the question because that could provide a little bit better color on where we're there. As you remember, when we got into the Congo we thought it was a one in three exploration success. We made a discovery and drilled four dry holes so it became one in five. And as Mindy reminds me, all you needed was one more discovery to get back to one in three. So, we drilled one more well, we made a discovery go, back to one in three. But since then we drilled a diamond prospect, which we just said today which actually found oil in the first sand, and then had well developed sands all wet underneath it.

If I looked at the two prospect, turquoise and diamond, and could choose which one was going to be successful before we drilled it, I would want turquoise for several reasons. One of which, it's a little bit bigger. The second thing, is there are prospects around it that have very similar attributes, including CSCM anomalies which turquoise did. So, I like the fact that we've got some nearby follow up from a well that has very nice oil pay in two channel sands. And one of the structures has exactly the same channels. The channels run east-west. We're on a bump, it goes down into the saddle to the west, it comes back on another bump and that same channel also has these anomalies.

So, I feel pretty good about follow-up there. The reason why we didn't drill that is the rig that we've got, it's right at the edge of its depth capability in terms of water and that would be just too far. So, we'll have to come back with a different rig to drill that. There's other exploration prospects on the block. I think one in three is probably where we need to be. And technically we've got to get ourselves comfortable.

So, I see other prospects to drill. What we're doing now with the rig is we're bringing it back to turquoise, and we're going to drill the eastern African feature. As you recall in Azurite, it had multiple fault blocks. And when we drilled all the wells all the fault blocks had oil. So, we're going to drill the eastern plank of the turquoise feature next so that we can then have a much better idea of how better to develop that and tie it back into Azurite. So, that's kind of the game plan.

I'm pretty keen on coming back next year to do some more exploration in NPS, but we've got partners to talk to. We've got our government friends to talk to and we've to to line a rig up. But, current rig availability is better today than it was a year and a half ago. And so I feel pretty good that we'll be drilling at least again next year for exploration (inaudible).

Anything happening on the north block?

You know, the north block has got the southern 0.3 of it has the same type of play, and so we're going to put that into the mix as to where we were going to drill. The northern part of the block has different plays which have different risk elements to them. And so I think we probably ought to stay with the things that we know work, at least at to the one in three level. So, that's kind of -- and we certainly could put that in the mix.

Are you still anticipating bringing a partner in at some point in time on the north block?

No, we traditionally don't stay at 100%, so I think it's possible, and we've talked to companies about it.

Thank you.

You bet, thanks Gene.

Thank you. (Operator Instructions). Our next question comes from the line of Wilma Kidd with Central Securities Corporation. Please go ahead.

Hello, gentlemen. I got on a little bit late, but did you say anything about this seaacap north in block K that could you be so kind as to repeat or expand for me?

Yes, no problem. Seaacap north is northeast of Kikeh. It's the same type of play and geologic section. We found oil, nice oil in several sands and we appraised that with a second well. We did that because the structure extends across into another block another lease, and the extension of that feature is into that block. So, we're just in the appraisal phase and once we finish that then we'll have to sit down and see the best way to develop it. So, that's where we're at there.

Okay, thank you very much.

You bet, thanks.

Thank you. I'm showing no additional questions at this time. Please continue.

Thanks, everyone, for joining us. We appreciate it -- taking the time -- busy schedule. And look forward to getting together again. Thanks a lot.

Ladies and gentlemen, that does conclude the Murphy Oil Corporation second quarter 2009 earnings call. If would you like to listen to a replay of today's conference please dial 1-800-406-7325 or 303-590-3030, followed by the access code of 411-20-59 and the pound sign. We would like to thank you for your participation. You may now disconnect.