Murphy Oil Corp (MUR) 2010 Q2 法說會逐字稿

Good afternoon, ladies and gentlemen, and welcome to the Murphy Oil Corporation's second quarter 2010 earnings conference call. Today's call is being recorded. I would now like to turn the conference over to Mr. David Wood, President and Chief Executive Officer. Please go ahead, sir.

Thank you, operator. Good afternoon, everyone, and thank you for joining us on our call today. With me are Kevin Fitzgerald, Senior Vice President and Chief Financial Officer, John Eckart, Vice President and Controller, Mindy West, Vice President and Treasurer, and Craig Bonsall,Supervisor of Investor Relations. I will now turn the call over to Craig.

Thanks, David. Welcome, everyone, and thank you for joining us. Today's call will follow our usual format. Kevin will begin by providing a review of second quarter 2010 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 a further discussion of risk factors, see Murphy's 2009 annual report on Form 10K filed with the SEC. Murphy takes no duty to publicly update or revise any forward-looking statement. I will now turn the call over to Kevin for his comments.

Thanks, Craig. Net income for the second quarter 2010, $272.3 million, or $1.41 per diluted share, and this compares to net income in the second quarter of last year of $158.8 million, or $0.83 per diluted share. For the six months of 2010, we had net income of $421.2 million, $2.18 per diluted share, and this compares to net income for the six month period of '09 of $329.9 million, or $1.72 per diluted share. There were no unusual items of significance in the 2010 quarter or for the 2010 six month period. However, net income in the second quarter of 2009 included combined net charges of $13.4 million, or $0.07 per diluted share, for several items. We had an anticipated reduction of our working interest in the Terra Nova field, offshore eastern Canada and for post-closing settlements related to the sale of our Ecuador properties, which was partially offset by insurance settlements related to property damage at the Meraux, Louisiana refinery. For the 2009 six month period, the net income number included the above mentioned Terra Nova redetermination and insurance settlements, along with income from discontinued operations primarily related to the sale of Ecuador properties.

Looking at the net income by segment, for the E&P segment, net income from continuing operations in the second quarter of 2010 totaled $219.1 million, compared with net income in the corresponding 2009 quarter of $118.3 million. Higher E&P earnings for the 2010 quarter were primarily attributable to higher crude oil and natural gas price realization and higher sales volumes. The 2009 quarter included the previously mentioned Terra Nova redetermination charge. Crude oil and gas liquids production for the current quarter was just shy of 132,000 barrels per day as compared to approximately 118,100 barrels per day in the corresponding 2009 quarter, an almost 12% increase. This was mostly attributable to production from Thunder Hawk in the Gulf of Mexico and Azurite offshore Republic of the Congo, both of which came on stream in the third quarter 2009.

Natural gas sales volumes were a Company record 348 million cubic feet per day in the second quarter of 2010, compared to 147 million cubic feet per day in the second quarter of last year. This increase was attributable to the third quarter 2009 start up of production from a field offshore Sarawak Malaysia, continued ramp-up of production at Tupper in British Columbia, and higher third party demand for our gas at Kikeh.

In the R&M segment, we had net income in the second quarter of 2010 of $83.8 million, compared to net income in the second quarter of last year of $27.8 million. The earnings increase in the 2010 quarter was primarily attributable to the US retail segment, where fuel margins average $0.162 per gallon, up from $0.078 in the 2009 quarter. In the corporate segment, in the second quarter of 2010 we had net charges of $30.6 million, and this compares to a net benefit in the second quarter of 2009 of $14.8 million. These higher charges were attributable to a combination of unfavorable foreign exchange results in 2010 relative to the gains realized in the second quarter 2009 and also had higher net interest expense due to lower amounts capitalized at development projects. As of June 30, 2010, Murphy's long-term debt amounted to a bit over $1.2 billion, which is approximately 13.8% of total capital employed. And with that, I will turn it over to Dave.

Thanks, Kevin. For the second quarter of 2010, crude prices remained range bound at the upper end of the $60 to $80 band, despite financial turmoil and high inventory levels. Natural gas in North America is in plentiful supply and prices reflect that. Absent the stronger economic demand, these conditions are likely to persist. The moratorium in the Gulf of Mexico is causing a reaction. Absent a clear way forward on approvals and requirements to operate, industry is in a holding pattern.

We have mobilized one deep water rig to Africa and have a platform rig working haltingly and only as we can obtain approvals. We are fortunate to have the preponderance of our upstream business activities outside the US and, as such, can keep our main growth initiatives moving forward. Our US retail had very good quarter. Late last month we announced our intention to divest our refining business. Those plans are well underway.

Second quarter results are showing signs of support as crack spreads improve, aided by better operational performance. Global production for the second quarter averaged 189,951 barrels of oil equivalent per day, slightly ahead of our guidance for the second quarter of 188,000 barrels of oil equivalent per day. This increase is mostly attributable to higher output across our Malaysian operations, somewhat offset by lower than expected production from Azurite, where our batch drilling operation is behind schedule. Plans are to bring two producers online in the second half of this year to help catch up that production level.

In Malaysia, our Sarowak gas project is at plan and selling 250 million cubic feet per day gross, with recent operational issues at the third party facility behind us. In Canada, production remains steady in the second quarter, supplying over 47,000 barrels of oil equivalent per day, helped by continued strong performance from the Tupper main development, where production is near 90 million cubic feet per day. We are making positive strides to increase production further at Tupper West when our 180 million cubic feet per day facility commences operation in the first half 2011. We currently have six rigs running in western Canada between our Montney acreage and our heavy oil crop (inaudible) In the Gulf of Mexico, our non-operated Deep Blue prospect in Green Canyon 723 remains suspended due to the moratorium.

We further delineated our South Access gas discovery in SK 311 block in Malaysia and found (inaudible) three reservoirs, leading to us consider development options through our West Patricia facility. Our exploration program, with some very attractive needle-moving oil targets, is poised to begin in earnest in October. We will drill three oil prospects in the Congo, two on the NPS block and our first well on block MPN. We will also spud two prospects in Suriname and one in Indonesia, all starting in the fourth quarter.

Onshore in the US, our operations in the Eagle Ford Shale in south Texas are moving ahead nicely. We are continuing to add to our land position, now well over 200,000 net acres. In well operations, we initiated flowback on the JOG unit number 1 well in Karnes County. The well was drilled to a total depth of 15,500 feet for the lateral section of 4,205 feet. This well is currently flowing at 524 barrels of oil per day in the initial cleanup stage. This well is five miles from our previously announced Drees oil well that IPd at 1,476 of oil per day and now, five months later, that well is still producing at 435 barrels of oil per day. Plans are to continue to appraise this area with likely sanction of an oil developed later in the year.

Also in the quarter, we completed two wells in the dry gas portion of the play, both wells in LaSalle County. The Oasis Minerals M number one well was completed in May and came in at a rate of 7.6 million cubic feet per day over a 72 hour flow period. The well was completed with a 3,392 foot lateral and 13 frac stages. The crescent C number one well was drilled to a total depth of 16,550 feet with a 3,360 foot lateral section and 15 frac stages, and that well had an IP rate of 13.9 million cubic feet a day. Overall, the results have been encouraging, and we will add a third rig very soon and accelerate drilling in the oil prone areas of the play.

Production guidance for the third quarter is estimated to be 180,000 barrels of oil equivalent per day, down from the second quarter. We are impacted by the previously mentioned slow build at Azurite and temporarily lower production from Kikeh, where the failure of a coil tubing unit during the workover on one well has caused us to wait on a rig to arrive in the fourth quarter to complete the workover program. The drilling moratorium in the deep water Gulf of Mexico will also impact production in the second half of the year due to delays in rig operations, particularly at Front Runner.

Turning to downstream operations, US retail ran well for the second quarter, capturing solid margins, while maintaining high fuel volumes. Refining saw positive net margins earlier in the quarter grow, and asphalt sales of Superior allowed US manufacturing to make a nice contribution. In the UK, our retail group continues to perform well, the Milford Haven refinery was coming out of turn around during the quarter with increasing throughput. In our biofuels business, the ethanol plant in Hankinson, North Dakota continues to operate optimally and make positive contributions to net income, despite challenging corn and ethanol prices. We have signed an intent to purchase a partly completed corn based ethanol plant in Hereford, Texas. Murphy will complete the facility, which is expected to have production of 115 million gallons per year and start up in the first quarter of 2011. This is another attractively priced asset to bolster our retail supply business, where our two plants will cover close to 50% of our ethanol requirements. Our table is set for the second half of the year, led by some exciting and potentially impactful exploration.

In recap, onshore drilling in Texas should lead to a planned oil development in Karnes County, good progress is being made in the evaluating the upside of our Seal heavy oil acreage in Canada, and in the fourth quarter, we should see results of our EOR pilots. We have also been named operator of the [Seacap] North oil development in deep water Malaysia, and we'll be stepping up on our plans to bring that important resource back through Kikeh. US retail is operating well, and we are looking for the second half to duplicate the first half of the year. That concludes my prepared remarks, and I'm now happy to take your questions.

Thank you, sir. The question-and-answer session will be conducted electronically. (Operator Instructions) And we'll take our first question from Arjun Murti with Goldman Sachs.

Thanks. David, wanted to follow up on some of your comments on the Eagle Ford where you had mentioned, I think the second well in Karnes County. How many of these exploration or appraisal wells do you think you will need before you will move forward with developments? You suggested you will, but a couple more wells, three or four? Any comments there?

Yes, Arjun, thanks for calling in. We drilled and tested now two wells in Karnes, we have a third one drilling. We're very encouraged, of course, with the first well. The second well looks like it's a strong well. We've only been flowing it for six days. The third well should be down here in mid November and have results. Once we get those kind of dialed in, I think we will be pretty comfortable to sanction it. And for us, what that means is going from gathering data, how to frac a well, how to drill a well, to actually starting to get a sharp pencil on it and start dedicating equipment. I see a couple of rigs staying there throughout now, and we're talking about plans for next year for our total Eagle Ford position. And without having gone through the budget process, we're probably likely to have five rigs running in the Eagle Ford through next year. So, pretty much a stepped up program for us.

That's very helpful. Can you talk about where your drilling costs are and where you think you can take them in the Eagle Ford and most notably, the Karnes County area? Thank you.

Yes, we've been spending more money on the wells because we're drilling them straight, for the most part, doing some coring, a lot of logging and then turning them horizontal. So, our well costs are in the $11 million plus to drill and to frac them. I expect that our costs will come down for drilling from about the $5.5 million now on average to something less than $4 million, and I expect our frac costs, which are kind of in the $4.5 million to $5.5 million range to get down below $4 million for the same types of fracs that we're doing. The issue, and I think other people have clearly recognized that, in the play, broader play of Eagle Ford, there's like 85 rigs but only 18 frac spreads. So, one of the things we want to do when we get ourselves comfortable in development is get dedicated frac equipment lined up at the same time we have rigs. I think that will drive costs down, and I think it will put more efficiencies into our program.

That's great, and if could do just one last one, David, just in terms of the implications of Macondo, Gulf of Mexico has been a portion of your global business. As you mentioned,you do assets all over the world. Does the oil spill your desire to continue exploring in the gulf longer term? Will we see it wind down further, or just any thoughts on strategically whether the Gulf of Mexico will remain a component of Murphy going forward? Thank you.

Arjun, I think that's a question that everybody is being asked now. And we did have a visit by Secretary Salazar to our offshore Front Runner facility here just recently, and that is the only facility that we're aware of that has a rig on it that has any approvals under MPL05 to actually conduct operations. So, I think that says two things. I think it says great credit for the folks that we have, to be able to pass all of the approvals necessary to allow it to go back to work for one particular recompletion. But the second thing, it underscores what the real problem is. The real problem here is less to do with the spill, I think, than it is to do with all of the approvals, some now unknown and some steps unknown to be able to get back to work. And I think that is going to dictate how the gulf is going to look like here over the next 24 months.

We still think we have a good business in the gulf. It is not a super large piece of our overall business, as you point out. We have some developments to do, we made a nice discovery in DeSoto Canyon we'd like to appraise. We've got some other things like Samurai need appraising and brought to production. So -- but until we get very, very clear understanding of what the approvals are, it's very difficult to make any plans in that business, so that's the seminal question that we're facing. But for us, I like the business, and I would like to keep going in that business. We sent our rig overseas because of the fear that I just expressed, which has actually started to come to fruition here. If we can keep our rig -- deepwater rig busy in west Africa, then we probably won't bring it back. But our plans right now, when I have the option to bring that rig back sometime in the second quarter of next year, but I'm going to have to be real comfortable. We've got all the approvals necessary, and it won't be changed to get our work done.

That's really helpful, David. I appreciate your thoughts, thank you.

You bet, Arjun. Thank you.

Alright, and next we'll take a question from Ryan Todd with Morgan Stanley.

Hello, Ryan.

Hello, David, how are you doing?

Great, how are you?

Great, thanks. If I could follow up with one more question on the Eagle Ford, thanks for the detail on the Karnes County. On the condensate and the dry gas windows, is there an ideal sense as to how those projects would be staggered if you sanction the oil window later this year? How much time would you like to wait, or how much data do you need to gather before you could sanction something in one of the other sections of the Eagle Ford?

Yes, the way I would think of painting our acreage holding, we have Karnes County acreage, which we've got the two wells, drilling a third, getting after it. And that's the most advanced in the oil window. We have two other groups of acreage. The second one is in Dimmit County, which we just got a well going now, and so naturally, it's going to be behind in the schedule there. We are drilling in our LaSalle McMullin acreage, primarily in the gas condensate and gas window. I preferentially would develop Karnes, then Dimmit and then our other oil holdings before the gas, but I need to understand, and we need to understand what kind of potential we've got there. So, I think we can run these simultaneously, but they're actually setting themselves up so they're actually sequentially, which is good for us in terms of managing equipment, both rigs and frac equipment, which I as I mentioned, is pretty key. So, that would be the sequence, Ryan, that'd I'd look at.

But would you expect that will you will -- you would you have enough wells to drill that you would be able to sanction that sometime in 2011, or is that a --

No, as we have the discussion a lot here, we make no money in science. We've got get wells producing here. And so yes, no, we're definitely the on that track.

Okay. And if I could switch over to exploration, in the Congo, you're drilling two wells in the MPS block. Should we look at those as being fully independent of one another, or is there something, as you drill the first one, you could learn that could actually change plans for the second well? Or are they completely separate?

Yes, the wells that we're going do, the first well will probably be prospect in the southern part of MPN, I'll call it Titan. And it's another one of these middle Miocene channel reservoir, full (inaudible) features that we like a lot, pretty good size, and then we're going move around the Turquoise Marine area where had some success here about a year ago. They're in different channels, one on the same bump, one on different bump, so we think that Turquoise area is somewhat derisked, because we already know that some of the channels work. In prospect, key sizes are in the 100 million barrel type range. Then going further outboard on Turquoise, the same channel that worked at Turquoise goes over another bump that we call Cobalt. So -- and again, that's about the same size. So, we're trying to focus in on that area because we believe that the main risks which were top seal and charge appear to be better understood there. And also, it's a logical place to bring them all together in any development that either want to do standalone or tie back to Azurite.

Okay, thank you. And in Indonesia, are you rig constrained where you can only drill one well there, or is there plans to drill more than one?

No, we have the option to do that, and it will just be sequenced in with our program and rig share with other people, so we're not constrained in that regard.

Okay, great, I appreciate the color. Thanks, David.

Thanks, Ryan.

And our next question comes from Anthony Guegel with Upstream Newspaper.

Yes, hi. Just following up on the -- in regards to the post Macondo word in the Gulf of Mexico, I'm just curious what sort of changes you have already had to make as a result of the NTLs -- or will have to make to your offshore drilling practices. And related to that, how much will these changes raise the hurdle rate for determining the economic viability of your exploration prospects in the US gulf going forward?

Those are broad strategic questions. What I would say is I don't know what the future of permitting or access or timing is going to be in the gulf. And so that raises uncertainty and makes it very difficult for us to plan. We try to run a very safe and very appropriate organization. We're willing to respond to any changes that the MMS or the BOEM or whatever they call it now and the new authorities have to help our operation get better, and so we work that way. And I think when the Secretary has visited our facilities, he's visited both Medusa now and Front Runner, I think he can see why though our Company is rated one of the safest companies conducting business in deep water. And so we want to continue doing that, and we want to continue operating in the gulf, but the degree of unknowns are still very, very large there, and so it's very difficult to quantify increased costs. It's very difficult to put together what the timeline would be to get back to work. And so any frustration that's in the industry centers around the timeline and what's required more than anything else.

Okay, we'll take our next question from Blake Fernandez with Howard Weil.

Good afternoon, guys. Thanks for taking my question.

Hello, Blake.

Hello. My first question was on production. With regard to the delays at Azurite and Kikeh, do you envision that having an impact on your 2011 production, which I belive is guided at around 225,000 barrels a day?

No, let me give you some color and maybe a little detail on Kiheh, Blake. It's a great field, it's currently producing about 96 -- when I looked up my screen before I came in here, about 96,000 barrels a day of oil. We've got five main reservoirs, we inject water down that, we maintain the pressure, we sweep the oil. We have excellent connectivity between those water injectors and the producers, so over a long distance. Our wells are designed that we can shut off water when the water starts to come to a well. We actually have been surprised that for some of the wells, we've not seen any water at all, and so it's a little bit of a good news in that regard.

We were running a production log on coal tubing here to try to find out in one zone, has water started to come to the well? Because we started to see the first early signs, and we actually saw that the water levels was at the very bottom of this zone, which we regard as being good and starting to make a little bit of sand, which often is a precursor of water leaking into these wells. At that point, the coal tubing frame kind of failed, so we decided not to continue with that operation, but just wait for a rig that we had got coming in the fourth quarter. And so we put that well offline. So the reason why our production is down now is because we switched that well off, which was making close to 13,000 barrels a day.

We have seen on a couple of other wells a small amount of sand and very small amount of water, and so we've choked those back because what we want to do is go in and replace the screens on these wells, and we'll do that when the rig arrives. We'll bring in some new technology and do some things there. So, it's kind of a natural history, we've produced now 94 million barrels in this field, the field is performing great, and it's so it's just a natural step to do that.. That we should have the first worked over well back early mid-November. It will add, I don't know, 12,000 plus barrels back into the mix here, and we should have the whole program done in about four months or so. So, really, it's a this year event and not a next year event, and we'll be back up to focus on here once all this is done, if that gives you a bit more color.

No, absolutely. Thanks for that color, David. The other is on Suriname. I know you have two different wells, and I apologize, I don't think I can pronounce the names, but as I understand it, one is bigger than the other. Could you talk about which one is going to spud first and assuming there is success, could you talk about maybe the timing of first production or reserve booking?

I always love reserve bookings and timing of production, but we've got drill them and find it first. The first well would be [Harakari], these are named after the local birds, and it's 200 million plus barrel. You get pretty exotic with size here, because these are physically quite large. And then the second is called Caracara, and it's another bird. And it's actually a much larger prospect, and so its size is quite large, much bigger than 200 million barrels potential..

These are shallow water in the sense that 200 to 300-foot water depth. So clearly, a discovery would require appraisal. But it's not inconceivable to see the timeline from discovery to first oil to be four, five years or less. And the reason why I'm hesitating there, there's not much exposure and experience to offshore developments there in that country, so there's a natural approval process that has to go through, and there's an education on how things happen there, so that's the reason. But post discovery, we've got a pretty good experience of getting on with it, and I don't think that we would get anything other than great support from Suriname to be able to do that. And so again, like we did with Kikeh, because it would be a new province, I think the schedule of booking would probably be relatively slow. You get an initial booking, I believe, and then I think you'd have to see some performance going forward. But those are nice problems to have, you make nice discoveries of that size (inaudible).

Indeed, thanks for the color. Appreciate it.

You bet, Blake. Thanks.

And our next question comes from Paul Sankey with Deutsche Bank.

Hi, David.

Hello, Paul.

Just to follow up, forgive me if I missed it, but what is the timing on the spudding of the first Suriname well now?

Yes, we're lined up here with a rig share agreement, and so our first well is in October. And so if I look down the list of wells here, the first well that is kind of on the exploration run actually is in the UK. So I'm glad you're the person that actually called in, is in around our Mongo and field for a pentacene channel. We should do that sometime in August. In September we'll spud the first Congo well, late September Titan and NPN. In October, November and December, each of the wells run about 30 days, well view the two Turquoise wells, and then Cobalt. In Indonesia, Semai should be a November spud, Suriname first well should be in October and the second well in December. That's kind of the schedule as it is a looks for us right now, and that's getting pretty tied down there, Paul.

Yes, that's great, that's very helpful, thanks David. It sounds like a swing a fortnight. The -- could you just update us on the farming Congo? Any news that you've got about what you're trying to do, both in the pre-salt posts? Thanks.

Yes, we've not been looking at farming out -- the pre-salt primarily for us is in the NPN block, so we have 100% -- we're just finishing up 3-D acquisition there. We will go through a process of evaluating that, and I suspect if we can light a little fire under our geophysicists, get to see some prospects here in the third quarter next year, which is going to be pretty important. All the work we've done so far suggests that that play is there, that we have leads -- strong leads there, and we'll be trying to get a rig onto those prospects next year. So, that's the timeframe.

Yes, I think the angle I was coming at was more others trying to farm in with you.

Yes, we've had, how should I say this, we've had quite a few inquiries, but we need to see the data first.

Fair enough, okay, thanks, guys.

Thanks, Paul.

Our next question comes from Gene Gillespie with Gillespie Consulting Group.

Hello, Gene. Hello, David, how are you doing?

Great,

It was indicated that you are going to drill a, what was described as a commitment well on block K in Malaysia in the third quarter. You have been producing there a number of years. I'm kind of confused about the commitment description.

We have a well that we're -- want to drill in deeper water on block K, and we've tried to decide when it should fit in our program. And so when we renewed block K, there was an extra well that was added, Gene, and so that's the well. It's not that we don't have prospects or ideas, it's just timing it with the other things that we're doing. So that's why it kind of moves around a bit.

Can you give us some color? Is it an oil prospect, the size?

Yes, it depends which one. We've got some -- we've got a play that we've not tried before that is quite shallow in flank to some of the features that we've drilled. So it would be in the pliocene, pleistocene type age, size, very large, but then quite a bit more risky than the other stuff that we know, so there's a lot of technical support for us to drill that. It would be a very quick well, but we need to spend a little bit more time. We're doing some reprocessing, trying to understand is there some sort of geophysical help that could help us choose that over doing something else? But that would be a completely new play for that margin.

It's a pretty inexpensive well apparently, given the spread between your (inaudible) exposure.

Yes, Gene, it's very, very quick. Drilling in offshore Malaysia doesn't take very long, particularly for the shallower targets, it wouldn't take very long at all. So relatively inexpensive well. Higher risk, of course, but something we certainly would do at some point in time. So that's probably the leading candidate.

Great quarter. Thanks for your time.

Yes Gene, thank you.

And our next question comes from Danielle Diamond with Barclays Capital.

Hi, thanks for taking my call. I was just wondering if you would give an update on Millford Haven and if we should be assuming normal run rates in the third quarter.

Millford Haven is still coming back from the turnaround, which was quite an expensive turnaround. We did a lot of stuff there, and I think the best rate that we've had is 128,000 barrels a day, and we had said prior to turn around that we wanted to be at 130,000, so not quite there. Still got some things to iron out. We have been optimizing what we're doing there, and so I think given another couple of months or so, I think that machine will be doing much better (inaudible).

Okay, great. And then also on the downstream, the tax rate. If I try to back into it using the reported resigning margins and net income per barrel, it would suggest that both the US and UK had an abnormally low tax rate. Could you walk us through that? Am I missing something here?

No, the tax rate in the US in the second quarter was 37%. So it was relatively normal. You'd expect in the 37%, 38% rate range. So there's really nothing in the US that creates any unusual items. In the UK, we did refer to a tax adjustment that was made relating to prior years. It had a bit of an impact. It was only a percent or so on a consolidated basis. It wasn't really that large, not material.

Within the US, if I look at your reported resigning margin of $0.69, then net income per barrel would be about $0.68. That would suggest about $0.01 per barrel on tax. Is that not the way to think about?

No, our tax rate was 37%.

If you give a call into Craig here, we can walk you through whatever your calculation is and help get on that page. That will be helpful.

Okay, great, thanks.

Great, thank you.

And next we'll take a question from Mark Gilman with The Benchmark Company.

Hello, Mark.

Folks, good afternoon. Had a couple of things. David, could you characterize the reservoir performance at Azurite?

At Azurite?

Yes.

Let me kind of give you some flavor on that, Mark. I think in terms of the reserves, we feel pretty good about the reserves where we're at with Azurite. The issues for us there have really been mechanical in nature. We had a delay in getting wells completed because we had a persistent issue with these formation integrity valves, F IV valves that basically keep your zone away from all the stuff you're doing up hole before you put the well on production, and these things wouldn't open as they're supposed to. So, we had some delay there.

Other down hole issue that we've had that has impacted production on one well is a very poor frac pack. But we -- I would say that the performance of the zones are kind of in line. I wouldn't say that they're better than we thought, but I would say they're in line. But those have been the main issues there on that particular field.

David, are you further enough along in terms of days of production to have a type curve on the Drees well? And give us an idea of the EUR there. Also, EUR thoughts you might have on the two dry gas wells.

Yes, the Drees well is a pretty nice looking well. I'll get myself some data here in front of me. I have to say it's a pretty straight line decline, and we originally thought that these wells would recoup something in the 350,000 barrels per well. We've recovered well over 100,000 barrels from that well so far in the first five months. So, that's clearly not the right number. I would think that we would be well north of 500,000 barrels from that well, and if this well, the JOG well that we're really just starting on now does anything like that, I think it too will be a well that will ultimately recover north of 500,000 barrels. So the two data points we've got, and then there's some other data, suggests this may be somewhat of a sweet spot. And so I'm very encouraged by what we're seeing.

How about the dry gas?

Dry gas, a little too early yet to see what we've got. What we've been doing there is drilling the wells and testing them and then flowing them at reduced rates. I think if you were to call around to most operators in the Eagle Ford, the general tendency now is not to unload the wells very quickly, but to allow them to come on much slower. And so we need a little more time with our wells to be able to get a good indication of what they're going to ultimately do.

David, you made a comment regarding [Seacap] North. I assume that there's been a unitization. Can you give us some parameters in terms of reserves, development cost and your interest in the thing?

Yes, in the unitized areas, at the outset will be 32% in operator. And reserve range, there's still range yet, but I would focus in on about 100 million barrels. Could be a bit more than that And we've got to meet with other unit participants and get ourselves all on the same page here, but I think it's going to be a very nice development. I think the data from the wells that have been drilled by us from the partners on the other side are very good, and I think it will be a very nice tie-back through the PK facility. And so I think it's a -- I think it's going to be a very, very nice add. It's going to keep the block K production profile out flat even longer, and that's what we've said in the past that we want to do, and then this is just another great way to do that.

Okay. Just one more from me. I think you said that the Sarawak gas has reached a plateau at 250. What should we think of in terms of your entitlement at a 250 gross level?

Our entitlement, Mark, ranges around 58%.

Okay, so something short maybe of 150?

That's right.

Okay, thank you.

Thanks, Mark.

And our next question comes from John Herrlin with Société Générale.

Yes, hi, just some quick ones. With the Montney leasing issues, at all in terms of expiration, all crown acreage?

I'm sorry, the question was are we all crown acreage at the Montney? Was that --

Yes, yes.

Yes, pretty much. I'm trying to scratch my head and think exactly what the distribution is. But we don't have any issues there in terms of expiring or anything like that.

Didn't think you would.

Yes, we do drill and hold, as you know, in that part of the world, drill a well and hold a certain acreage spread, and so we're in the process of doing that. So I don't see any lease expiring issue for us.

I didn't think you had any. I was just curious. With the R&M sale, if the potential purchaser said, gee, I want the marketing operations associated with Wal-Mart, would you part with them?

The way I look at is if someone is willing to write a big check, they can have a lot of things. We really like our retail business, and as you can see from the results, it's a great business with great future, we think. And so I can't stop anybody from coming and saying they're interested in anything we've got, but what we've offered for sale today are the three refineries and the UK retail.

With Suriname, is that the old Burlington/LOMA concession? I'm dating myself, but.

No, I'm also old, I remember those companies, but no, it's not.

Okay, last one from me. When you look at your upstream portfolio, do you think you need more short to immediate term project opportunities rather than the longer lead time stuff? Or is that what the Eagle Ford and ultimately, the Montney become for you?

Yes John, you've hit on one thing I think that they do bring to us very nicely, particularly given the success, I think in Karnes County, we were talking about before for oil, and also recognizing that we don't know what the timing is going to be in the Gulf of Mexico, given all the new potential requirements for getting that back to going. So, the Eagle Ford play, the Montney play allows a sustaining level of activity that I like. I like the fact that the Eagle Ford is oilier, because I think there's a better value proposition there tight now in the near term.

Our goal is to drill at the dozen exploration wells a year, and as long as we can keep our game rolling there and then feeding back into our development hopper things, then I think we'll be okay. So I'm pretty pleased. Things like [Seacap] coming off are very helpful. South Axis, which I mentioned earlier, now an oil development rather than a gas development, next to infrastructure we hold, So, I feel pretty good that our program is going to oscillate up and down here, but I think it's going to have lots of stuff for us to play with. We do have a very active business development effort, and we are looking to add two to three more countries here between now and the end of next year. Not willing to talk about them, of course, but so we do have that to add to our hopper here, and I'm very comfortable where we're at.

For the country issue, want to add, are they non-OECD? Will you specify that much?

How about I don't specify, and we'll announce them when we got them.

It was worth a shot. Thank you.

Thank you. It was a good shot John, good shot. A for effort.

Alright, and next we'll take a question from Ray Deacon with Pritchard Capital.

Hello, Ray.

Yes, hello, David. I was wondering if you had given any detail regarding the -- what you believe is kind of oil in place per section in Karnes and trying to back into what you see as the per well recovery there, if it's not too early to ask that.

Ray, it's alarmingly early, but I'll give you my thought. I think that based on the data that we've seen, probably 50,000 acres is probably going to get you something on the order of [80] million barrels. That's kind of my number that I would have, but I wouldn't want to break it down any more than that, because it depends on quality and a whole bunch of other issues, but you kind of to have bracket what you think you're looking at here, and that's kind of the way I feel.

Okay, great. That's very helpful, thanks. Well, I guess one more, to ask you to elaborate a little bit more on your comments with regulation in the gulf and inability to quantify costs. What about in the rest of the world? Have you seen increased costs in other countries where you operate offshore? What have you seen there so far?

No, I wouldn't expect there to be an increase in costs outside of the US. I think part of the issue in the US is if there's less capabilities here, then there's likely to be an increase in costs, particularly as you cannot string programs together. One of the big efficiency drivers in our business is to be able to hire equipment, then keep it working constantly and plan that way. And so if you remove that, these one-off opportunities, particular from deep water, become quite expensive. Overseas, the sense is that equipment has started to trickle away from here in the deep water, and as it starts to become available around the world, I actually expect there to be a little bit price push down, so we've started to sense that in parts of the world that we know of.

Great, thank you very much.

Thanks, Ray.

(Operator Instructions) Our next question comes from William Ferrer with W.H. Reeves & Company.

Hi, good afternoon, lady and gentlemen.

Hello, Willie.

Two questions. One just generally about Suriname. What kind of rig do you need to drill it? What do you think the well costs might be for the first couple of Wildcat wells? Just a little bit of how much you will have in capital-wise in the play before you know?

Yes, let me give you a sense. It's jack-up water tap, so we've actually already got a rig lined up. It's an Atwood rig, and well costs are in the, little less than $20 million to a little less than $30 million, depending upon how deep you're drilling. So, our first well is closer to $20 million and our second well is closer to $30 million.

And again, depending on success of the first two, but would two wells be sufficient to give you as much information as you might need, or are these multiprospect areas that would be more intensively drilled regardless of the first two wells?

There's actually, if you look at the different play horizons that play pipes there, there's at least a handful to play with. And so early this appointment wouldn't necessarily rule out trying some of those other prospects or other plays. If we were successful in one of these first two given their potential size, we'd clearly have to appraise with multiple wells, because these have the potential to be quite large. And I think we'd also want to come back and do some flow testing to get an idea of what the crude is and what kind of raid and how good the reservoir is, et cetera, et cetera. And so I think early success here is really what we would like, and that would allow us to focus in on what we're going to do as the next phase of drilling here. Because we're sharing this rig with other people in that region, there is the opportunity to cycle back into our acreage with the same equipment, and so we have built into our thought process here, if we had early exploration success coming back next year, relatively soon, and doing some appraisal work there, so that's kind of the thought (inaudible).

Good, and I know it's early days, but could you just provide a little color on the refining sale process? Have you had expressions of interest ,or your sense of perhaps timing and the ability to sell assets as a package as opposed to perhaps different or multiple buyers, one versus the mob, I guess.

Yes, it's a great question, and I'm going to defer it to kind of how my golf swing is. I find if I look where the ball is going to go before I hit the ball, I usually end up with lousy results.

So, kind of like Gillespie, frankly, but that's another story.

So in this case, I will defer any comments on an ongoing process. And when it comes appropriate I will make some comments about how we're doing it, but we're not ready to do that now. We've got a process that's moving along, and I'll reserve comments to a little bit later.

Do you think it will be a 2010 event or a 2011 event in terms of reaching some conclusion, perhaps not necessarily the final settlement or check?

Yes, we set out a timetable there at the beginning, and there's nothing that causes me to question what that timetable is. So I'm happy to keep (inaudible).

Thanks very much.

Thanks.

Alright, our next question comes from Mark Gilman with Benchmark company.

Hello, David, the US gas production is jumping around an awful lot quarter to quarter. Can you give some color as to what the variances there are being caused by?

When you say jumping around, Mark, you got anything specific you're focusing in on there?

No, just up one quarter, down the next. There just doesn't seem to be any consistent pattern.

Well, Mark, in the second quarter, we did have nicer production, not a lot of hurricane days in there obviously, and what we're forecasting for third quarter though includes 16 days of hurricane downtime for the quarter, and that includes the sump downtime that we already have for hurricanes Bonnie and Alex. And so that's going to cause a decline in both the gas and the oil side in the US. And then we expect it to bounce back up in the fourth quarter as hurricanes are primarily behind us, although we do have a few days still planned even in the fourth quarter for hurricanes.

Was that where you were going, Mark, or were you looking backwards in what we were (inaudible)?

I was actually looking more backwards, but if there's nothing in particular that you can identify, then that's fine, too.

Let me -- Mondo was a well that -- its rate goes up and down because it's in competition into a pipeline. So as another well in that same pipeline system is on or off, then Mondo will either produce at a higher or lower rate. And so, I think that might be what you are seeing there, Mark.

Okay, David, thanks. Is there anything that's on the horizon in terms of any pending changes in Kikeh entitlements?

No, we expect our entitlements to stay about where they are, which is in the low 60% range. It's been there fairly consistently here for a while, and we project that for this quarter as well.

Okay, finally, it looks to me as if from a roll reliability, this still isn't very good across the entire plant, looking at some of the product yields, and at least that's the interpretation that I get. Distillation run rates seem to be all right, but yields don't. Any comment on that, David?

No, I have to say that Meraux is running a lot better than it has, and we see some very good consistency in operations in that plant. There are some natural tweaks and changes that are going on, but I think overall, it's probably us moving things around rather than the facility itself. But the guys are doing a great job with Meraux, and I'm very pleased, the track that we're on.

Okay David, thank you.

Thanks a lot, Mark.

Okay, and at this time, we have no further questions. I would like to turn conference back over to Mr. David Wood for any additional or closing remarks.

Operator, thanks a lot. I appreciate everybody calling in, and thank you for your attention, and we'll look forward to talking to you next time. Have a good day. Thank you.

Thank you, sir. That does conclude today's teleconference. We do thank you all for your participation.