Murphy Oil Corp (MUR) 2011 Q2 法說會逐字稿

Thank you very much for joining, ladies and gentlemen, and welcome to the Murphy Oil Corporation's second quarter 2011 earnings conference call. Today's call is being recorded.

I would now like to turn the call 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; Barry Jeffery, Director of Investor Relations; and Tammy Taylor, our Assistant Manager Investor Relations. I will now turn the call over to Barry.

Thank you, 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 2011 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 2010 Annual Report on Form 10-K filed with the SEC. Murphy takes no duty to publicly update or revise any forward-looking statements.

I will now turn the call over to Kevin for his comments.

Thanks, Barry. Net income for the second quarter of 2011 was $311.6 million, or $1.60 per diluted share. That compares to net income for the second quarter of last year of $272.3 million, or $1.41 per diluted share. For the 6 months ending June of 2011, we had net income of $580.5 million, or $2.98 per diluted share, and that compares to net income for the 6 months of last year of $421.2 million, or $2.18 per diluted share. The 2011 quarter and year-to-date results included an after-tax gain of $13.1 million, or $0.07 per diluted share, from the sale of natural gas storage assets in Spain. There were no unusual items of real significance in the 2010 quarter or for the 2010 6-month period.

Looking at income by segment, in the E&P segment, for the second quarter of 2011 we had income of $243.3 million and compares to net income in the second quarter of last year of $219.1 million. Higher E&P earnings for the 2011 quarter were primarily attributable to higher crude oil and natural gas price realizations. Crude oil and gas liquids production for the current quarter was approximately 94,200-barrels per day as compared to approximately 132,000-barrels per day in the corresponding 2010 quarter, with the decrease mostly attributable to lower production at Kikeh, where several wells were shut in or waiting rig workovers.

Natural gas sales volumes were a Company record 457 million cubic feet a day in the second quarter of 2011 compared to 348 million cubic feet a day in the second quarter of last year. This increase was attributable to the continued ramp up of production at Tupper in British Columbia and higher production from fields offshore Sarawak, Malaysia.

In our R&M segment, net income for the second quarter of 2011 was $91.7 million compared to the net income in the second quarter of last year of $83.8 million. Earnings increased in the 2011 quarter was attributable to operations in the US where we experienced improved refining and retail margins. Additionally, both US refineries were enrolled during the quarter, processing a Company record of just under 170,500-barrels of crude oil per day.

In the Corporate segment, net charges in the 2011 second quarter were $23.4 million compared to net charges of $30.6 million for the second quarter of last year. The lower charges primarily related to favorable impact on transactions denominated in foreign currencies. As of June 30, 2011, Murphy's long-term debt amounted to just under $1.2 billion, approximately 11.8% of total capital employed. During the quarter, the $350 million 10-year bond maturing May 1 of next year was reclassified as a current maturity. Cash and short-term investments at the end of June totaled a little over $1.3 billion.

And with that I'll turn it over to Dave.

Thanks, Kevin. Second quarter crude oil prices peaked in late April with WTI approaching $115 a barrel before backing off into the $90 range by the end of June. Dated Brent continued to outpace WTI with a spread surpassing $20 in June and averaging $15 for the quarter as WTI remained somewhat landlocked and regionalized. Concerns over slowing US economic recovery coupled with lower demand led to the commodity sell-off. The IEA's decision to release 60 million barrels of crude and products to the market from strategic petroleum reserves, had a momentary affect on prices even as they had already started to fall. That impact seems to have passed and we continue to forecast $95 WTI for the remainder of the year.

North American natural gas prices remain range bound near $4 and we see this trend continuing throughout 2011. Consistent with our plans, we have managed to sell approximately half of our Tupper gas production for the remainder of the year at $4.90, helping to bolster returns from that business.

In the Gulf of Mexico, the permitting process remains uncertain. We did obtain a single re-entry permit for a well at Front Runner last quarter and have just received a second permit there. Efforts to gain additional permits at Thunder Hawk are ongoing but unlikely to be timely enough for us to see work there this year. Our exploration program is off to a slow start in 2011 with now only 2 wells having reached TD. The second exploration well, this one drilled on the Lengkaus prospect in the Semai II block offshore West Papua, Indonesia, found the primary objective Jurassic sands. Logging showed them to be hydrocarbon-bearing but wireline MDTs were unable to confirm this. We have expensed this as a dry hole but left the well capable of re-entry for possible future evaluation. There are a number of other prospects on our acreage and we are using this new data to help plan our next steps.

As exploration well timing is constrained by rig schedules, we should see a much more active program in the second half of the year with significant targets being tested in several countries. This and next year we'll see 30 wells drilled including impact targets in Brunei starting this year, as well as deep targets in Congo, surface feature wells in Iraq and further targets in Indonesia.

Global production for the second quarter averaged 170,457-barrels of oil equivalent per day, well below our second quarter guidance of 187,000 barrels of oil equivalent per day. This is disappointing for us, and we have reorganized our upstream business and processes to do a better job of meeting and beating future production targets. This variance of 16,500-barrels equivalent a day is attributable to a number of factors including lower production at Kikeh, the impact of wildfires in Alberta on Seal heavy oil production, lower than expected production from the final development well at Azurite, acceleration of turnaround work on a vacuum distillation unit at Syncrude, unexpected downtime impacting Sarawak Gas and an advanced turnaround at Hibernia.

In US retail, margins recovered nicely in the quarter making good contribution. US refining margins continued to be supported by improved crack spreads and both US refineries exhibited steady operations to capture what the market provided.

The UK downstream business remained focused on operational performance in a continued difficult market environment, the UK retail remaining that geography's bright spot. Plans to reposition our Company and to divest the refining business are moving forward with the reported sale of the Superior refinery earlier this week. An announcement on the Meraux sale is expected in this quarter. The UK assets will now be split up with separate parties interested in the Milford Haven asset and in UK retail.

Production guidance for the third quarter is 173,000-barrels of oil equivalent per day. This increase over the second quarter is primarily attributable to improved production from our resource plays at Seal, Tupper and the Eagle Ford Shale. We have revised our production outlook for the year to 185,000-barrels of oil equivalent per day down from the previous forecast of 200,000-barrels of oil equivalent per day, as we factor in the shortfall in the first half of the year along with planned second half operations. For the remainder of the year we'll see production increases from Kikeh, Tupper West, Eagle Ford Shale, Seal and Canadian non-operated properties. The first workover well at Kikeh using a gravel pack technique has been successful with that well now making over 7,000-barrels of oil per day without issue. Unfortunately, we had an offset to that with a different well suffering a near surface mechanical problem that caused it to be sharply curtailed. A second rig is scheduled to arrive in that field in August and help with that workover program.

Important single wells still impact our near-term production forecasts but we are encouraged by the work at Kikeh. I expect us to be at 80,000-barrels of oil a day in this field by November and have an overall end of year exit rate of 220,000-barrels of oil equivalent per day for the Company. Longer term as we increase producing well count, we remain focused and comfortable with our goal of reaching 300,000-barrels of oil equivalent per day by 2015.

Our North American resource program is actively growing with now 13 rigs active across 4 plays. This will grow to 16 rigs by year end. To help bring excellence and leading performance to that program, we have reorganized our North American business to enable best practices and talents to come to bear. The Eagle Ford Shale play continues growing from strength to strength witnessed recently announced deals. Subsurface we see strong results across our acreage footprint. We currently have 5 rigs drilling and plan to add 2 more in the second half of the year. To date we have drilled 35 wells with 25 producers and 10 awaiting fracs. Well results continue to be very encouraging and we are trending better than our tight curve for wells in the play. Gross production is in the range of 7,000-barrels of oil at 6 million cubic feet a day. The region has been impacted by take away capacity and we look for this to improve as infrastructure projects move forward into next year.

In Western Canada, we have 9 rigs operating between the Montney acreage at Tupper, our heavy oil operation at Seal and appraisal drilling in the Southern Alberta Exshaw play. The Tupper area continues its good performance with rates currently near 200 million cubic feet per day as the build up continues through 2011. Heavy oil production at Seal is recovering from the severe forest fires and recent flooding from heavy rainfalls. We have started to see encouraging response on our polymer flood pilot with impacted producing wells adding 50 to 100-barrels of oil per day each. This is almost 100% increase per well and points to nice upsides here. Applications for a steam pilot and a commercial polymer flood have been submitted.

In Southern Alberta, our Exshaw/Bakken appraisal program continues with 4 wells drilled and the fifth expected to spud shortly. 2 wells are now producing in line with expectations, the third well is under evaluation and the fourth well is awaiting completion. For us certainly identification of the sweet spots, where we can expect a tight well to produce 200-barrels of oil a day with an EUR somewhere in the 200,000 to 250,000-barrels, is key and our program is focused to that end. We now plan to drill up to 8 wells this year.

In Business Development, we have finalized an agreement with the Kurdistan regional government of Iraq to acquire a non-operated 20% interest in the Barranan block. This block covers an area of 178,000-acres and sits 25 miles south of the city of Sulaymaniyah. We're also working to close new acreage positions in West African Vietnam and continue to evaluate bolt-on opportunities for our resource plays, and are adding to our land position in a fifth North American resource play.

In the US, the retail chain expansion continues with 20 stores added year to date bringing the current station count to 1,119. The end of this month also witnessed a new step forward as we again partnered with Wal-Mart this time to announce a $0.10 per gallon rollback on gasoline prices across much of our network. That program has been well received and is scheduled to run through September 30. High prices have had an impact on year-on-year station volume by almost 10% but the recent fall off in wholesale prices have supported margins in the sector contributing to a solid quarter.

US manufacturing margins remain relatively strong in the quarter despite the higher premiums of water borne crudes and into the dislocated WTI for Gulf Coast refineries. Both refineries ran well to take advantage of what the market provided. Milford Haven refinery posted its sixth crude processing record in 10 months with runs in May exceeding 136,000-barrels per day. The focus there remains on operational performance in a difficult market environment.

In the renewable fuels business, the crush spread returned to positive territory in June as corn prices fell over $0.90 from the beginning of the month on fund liquidation and better crop ratings overall, providing a boost to ethanol manufactured margins. In Hankinson, production continues to remain very consistent in the 120 million-gallons a year range. At Hereford, the performance test has been completed at the name plate capacity of 105 million-gallons per year and the focus turns to stable, reliable operations.

In summary our repositioning is well underway with the announced sale of the first refinery. It's a little slower than I would have liked but understandable given the market. Our onshore US resource program continues to impress and grow, witness positive news at Seal, Eagle Ford and Tupper. We have stepped back to recalibrate our production profile for this year given our poor start but see a stronger finish as our workover program kicks in. We remain focused on the 300,000-barrel a day target by 2015 from our existing resource base. The streamlining and refocusing in our upstream business will help us on our goal to meet and beat future targets.

The exploration program is weighted to the second half of this year and proceeds at a steady pace going forward with impactful prospects getting tested in Brunei, Congo and Iraq. Our prospect inventory continues to develop in addition of new exploration blocks in new country entries. US retail made solid contribution in the quarter and US refining turned in a steady performance to take advantage of the market.

That concludes my prepared remarks, and I'm now happy to take your questions.

All right, well, thank you very much. (Operator Instructions) Evan Calio with Morgan Stanley.

David, can you walk us through the 220,000-barrel a day Q4 exit rate guidance? I know it's almost 30% higher than 2Q and 3Q, and maybe run asset by asset to get to that current exit growth rate. I mean I'd presume a primary element is Kikeh, but it must include a host of other lifts.

Yes, Evan, it does. Let me kind of get you there. So from the 164 number to get to the 220, I'll run down kind of in order of increase here. Kikeh will be just under 29,000-barrels add, and there we've got basically 6 wells, 2 new subsurface wells and 2 new subsea wells and 4 workovers. And I'll talk about Kikeh at the end of this so that it kind of gets everybody up to date.

Tupper and Tupper West lead about 9,500-barrels a day. We've got some 13 additional wells coming on. Eagle Ford a little over 6,000-barrels a day, we have new wells coming on there. And just under, right under 4,000-barrels a day at Seal, we have some additional wells coming on there. And then there's less down time at Terra Nova in Syncrude or again just under 4,000. The UK and Hibernia again less down time 2,800 in the UK and 1,600 in Hibernia. And so when you add all of that up with a little bit of oil production from South Alberta, you end up at the 220 exit rate.

And then on the -- you were going to walk through Kikeh, I mean I guess just with the first recompletion finished and you had 2 rigs doing workovers, what gives you the confidence that you can reach those levels, particularly in light of some -- a string of production disappointments from Kikeh and even from just 90 days ago?

Yes, let me kind of -- I'm sure this question is probably -- other people have too, so let me kind of walk through Kikeh. Today Kikeh is producing 58,206-barrels of oil and 72.6 million cubic feet.

Is that gross?

Yes, these are gross numbers. And we currently have 3 of the shallow horizon wells shut-in and in addition there's a fourth well that is really curtailed because it has a mechanical, a near surface mechanical problem. And in total, those 4 wells were producing 29,000-barrels of oil immediately prior to their problems. And so all of those wells will be worked over this year plus we have 2 new subsea wells to be brought on. And you've got to remember that Kikeh is not fully developed yet and we still have wells as part of the field development plan to be drilled. Right now we have 1 rig, it's a semi working in the field on one of the shut-in wells. And a second well will come and be put on the spar and operational late August. And so our goal is to reach 80,000-barrels of oil a day in November and the actual year-end rate will depend on well timing and we've just assumed that it'll be at that 80,000-barrel a day rate.

So let me recap just I want to make sure that people understand from what we talked about last time on the call and this call is to kind of what the changes are. Since we last talked, we had a fourth shallow horizon producer that was shut-in due to fines production as a precaution. We have worked over one well, it's been on production for a couple of months. It's making over 7,000-barrels a day and has no issue, so that open hole gravel pack is working nicely. Unfortunately at the time, in the same time frame but not related, we had a well that was producing over 10,000-barrels a day that developed a mechanical problem and we have it choked back so it's making a small amount now. And so that well has to be worked over. So we in effect took a step forward and a step back during the time that we were conducting that workover operation. And so what gets us from where we are today to the 80,000-barrels a day is basically 6 wells. The 4 wells that are being worked over, 3 with a recompletion gravel packs, 1 a mechanical well, and then 2 new subsurface wells, subsea wells that will be done as part of the original field development plan for Kikeh.

And with the fourth shallow well that you mentioned that you shut-in because it began producing the fine sands, I mean, does that mean that -- I mean do you anticipate having to recomplete most of the Kikeh wells or --? Because it kind of went from 1 to 3 to 4 here. (multiple speakers) Or how should we think about that?

Yes, last time we spoke there was 3 and there's been 1 more and these are related to the shallow horizons. We've not seen the issue with the deeper horizons, Evan, so we're going forward with these 4 wells and recompleting them.

And how many other wells are on the shallow horizon that are not shut-in and not yet producing sands?

One. (multiple speakers) Now 2 of the new, just to be clear, 2 of the new wells that we're drilling are going to be in the shallow horizon, but clearly, given our experience here, we'll just go ahead and either frac pack or gravel pack them at the beginning without going through the expandable screen steps. So as I said, the whole field is not fully developed. These 2 new wells, which are going to be in the shallow horizons, we'll complete differently than we originally did with the others.

Okay, that was very helpful. I'll let someone else go here.

Okay, thanks, Evan.

Joe Citarrella with Goldman Sachs.

Thanks. My question is on the Eagle Ford. You mentioned that results have been exceeding your expectations. I'm wondering if you can update us a little bit more on your non-Karnes County acreage in particular, specifically thinking the Tilden area. Last I think we've heard you're expecting results there to be fairly similar to Karnes. First is there any change to your thought process there? And second it would also be great to get just general thoughts on what drives your confidence in the well results and IPs you're expecting across your position in the play. Thank you.

Yes, Joe, we're concentrating our development in the Karnes area because we sanction that area first so we have more data there, more productive history there. And what we've seen is as we've brought these wells on -- and we don't open them up wide now, we tend to choke them back -- and what we've seen as we've had these wells on for longer periods of time is well performance, when you choke the wells back, is better. So we actually beat the tight curve quite handily and these wells tend to be relatively flat.

We're a little younger in our program in the Tilden area but we see nice well results there also. And I think overall, that whole swath that runs down from Karnes into Tilden are going to be somewhat similar and probably part of the sweet spot of the overall play, and so we've been very, very pleased. We have taken the opportunity here to pick up some additional acreage. We're now closer to 250,000-acres in the play. That's something that we've said all along that we want to identify opportunities and so those areas are the ones that we're looking at to add to the play. So I'd rather not get into specifics of individual wells because we have that as a strategy but I will tell you that well results are nicely beating our expectations.

That's helpful. And then just on that point on the additional acreage acquisitions, are those sort of bolt-ons to some of the existing areas or any indication what counties or what areas those additional acres are in?

Yes, they are in the oil play and they are around areas that we are already active. And beyond that, I'll just be mum.

Okay, that's helpful. Thank you.

Thank you.

Paul Sankey with Deutsche Bank.

The dry hole that you had in the quarter, can you talk a little bit about the overall expense of that, David? I think it seems very high and I wondered why it had been drilled for so long and very specifically, I just wondered if there was any additional expense to you in Q3? But if you could just talk a little bit more in general terms about what's on there that would be helpful, thanks.

Yes, the Lengkaus well came in pretty much as prognosed, it just took longer to get there. We had extra strings of pipe set and we had a section that was very difficult to drill and took much longer. So gross costs for the well was close to $200 million, it was significantly higher than when we started. That rig has now moved off and so it's gone to somebody else, so I think we're done as far as our costs go. The well did have pretty decent oil and gas shows. We did log what we, a log analyst would say it looked like pay on a log, we couldn't get a sample, a wireline sample. We think the zone is tight, but that was not definitive. So I view that as being something to follow on. It's certainly a dry hole but I think there's a glimpse of future promise and more work needed on that well and more work needed on the block. So that's kind of where we are. And we're trying to take all of the data that we've got and re-evaluate and high grade where we want to drill next on that one.

Right, and so there's no further expense for the July period?

There's just the further $1 million net to Murphy expense. That will be in the third quarter.

Understood. David, in the exploration portfolio, I assume -- clearly not in Iraq, but I assume there's nothing else of that scale of risk reward, if you like, in the next year or so program that you talked about?

No, I wouldn't say that. If you look here, we've got -- and so it's going to depend when wells start to when they finish as to whether they're in this year or not. But if I kind of look at the 18 months exploration program, we should probably spud 10 wells between now and the end of the year. If I look at the most notable, clearly in Brunei both in the CA-2 and the CA-1 block, these are big high potential oil type prospects. We have a couple of blocks in Iraq in Kurdistan, one in Central Dohuk, where we just finished 2D seismic and I'm making drilling plans there; and then one, we did a non-operated block in Barranan which has spud a well right at the end of the year. And then we're going to do some drilling in Malaysia probably on Block-H, and we're working on our timing now. So I think we have a number of pretty good sized prospects to be started this year.

As I look into next year, I see things carrying on in Brunei, pretty active program in both blocks. I see a sub-salt well in Congo which we're waiting on the rig to come back, the Ocean Confidence that is off working for somebody else should be back to us about the end of the year; have a sub-salt well in there for a very big nice target. So I think the quality of the program is as we've talked about before. I think we've had a little bit of time slide here to the right but this is pretty attractive mainly oil based prospects within the program.

And I guess the exploration chart we're looking back is -- had its knocks, what makes you more confident going forward that you should continue pursuing an exploration strategy this aggressive, given the struggles that you've had over the past few years?

Yes, I've been doing this for 30 something years and you go in streaks and patches. I think one thing you have to recognize that these are programs and we spend about the same amount of money here each year, and I'm comfortable with that level of spend. What we've been working on is the quality of prospects we've been drilling. The unfortunate thing for us is these last 6 months we haven't been drilling many wells. And so we tend to go through the highs and lows of individual wells and less focused on the quality of the program. I think as we start to get into a more active part of the second half of this year and next year with the quality of prospects that we've got in basins that have already been proven, I feel very, very good about the program that we've got.

So I think exploration for us is part and parcel of our growth story but today, it's not the only part of our growth story. Two, three years ago we didn't have a resource program like we do today and going forward, our resource program is very good and very important. I'm real excited about what we've seen at Seal. I'm very happy with where we are with Tupper. Of course I'd like higher gas prices, but I'm very happy subsurface and I think Eagle Ford is a home run for us. Looking at our Eagle Ford position now, we probably have 2500 locations, probably have 500 plus million barrels and probably 4 TCF there recoverable and feel real comfortable with that. And so I think that provides a very nice balance and perhaps missed by many in our overall program. So the balance there, the predictability from that I think overall helps us a lot.

Great. The final question for me, you mentioned that you had I think you said restructured regarding your target setting, if you like, and you've now given some very specific targets for this year. What did you mean by restructuring and what is the difference between this new sets of targets and the methodology and the confidence you have in them against the prior system?

Yes, in all things when you don't do things right once, you can look at it and when you don't do it right the second time, you've got to change something. So we have lots of smart capable folks in our organization and that want to succeed and want to deliver. So we've changed the emphasis, changed some of the processes, changed some of the ways that we look at things and the end result of that is this revised production guidance for this year. And so I feel very good about the buy in and I feel very good about where we're at. And the proof is going to be in the pudding going forward, but I think that we're off to a good start.

If I look at production today, or here we are in July, as a month, it should kind of be a gauge, we've been on a per barrel day 161 to as high as 184, and this last week we've averaged 177,000-barrels of oil equivalent a day. Against the target that we set for the quarter, I think that's in the right direction. So the things that we've done and the things that we've seen so far here in almost the first month gone of this quarter, I think is directionally correct. So but the proof will be as we go forward. I don't think it's an issue of the quality of the resources so much, I think it's how we've been going about the process. That's why I feel very good about the 300,000-barrel target by 2015 which is from the things that we already have. So -- but we'll have this call at third quarter and Paul, I'm happy for you to ask me again.

I appreciate that, David. Thanks for your answers.

You bet.

Blake Fernandez with Howard Weil.

Good afternoon, guys, and congratulations on some progress on the refining sale.

Well, thanks, Blake, it's one step.

Yes. David, a real quick one with regard to Evan's question on Kikeh, I know you gave a comprehensive answer, I just wanted to confirm if I could that still no concerns with regard to the reservoir or ultimate recovery?

These issues that we've been dealing with are to do with these fines migration and this one mechanical issue, so we've not seen anything that would cause us to change any of that flight in this first well that had a workover and has been producing without incident here for 2 months, I think kind of supports that.

Right, okay, thanks.

We still have some other wells to drill in the field, as I mentioned when I was addressing Evan's question, so I mean we're still working in a long -- and drilling wells and drilling out the field.

Okay, that's great. Secondly with regard to third-quarter guidance, I thought maybe it would have been a bit higher. I'm trying to gauge, do you have any hurricane risk factored into that number?

This is Barry, Blake. In terms of the guidance number here, if you look at the production forecast at 173, I think Dave did a good job of showing you where we're at today and feeling comfortable with where that is, so they've got their regular conservatism in for the Gulf of Mexico. But if you need any specifics, in terms of where the number is itself, you've got some higher workover costs in terms of OpEx that are going to bring some extra OpEx here, about $30 million, that's about $0.15 a share. And then you've got some UK tax impacts, so there's some catch up. And then third quarter view of UK tax that's about $15 million, or $0.08 a share. And then you've got some downstream earnings that are lower by about $30 million, or $0.15 a share. So that kind of takes you from where we were in Q2 to where we're forecasting the $1.10 midrange here in Q3.

Okay, great. Thank you, Barry. Last question for you, David, I know in the past you had kind of maintained a very flexible balance sheet with the idea that if you had some success in the high impact exploration front, you wanted to add some dry powder to develop that. Obviously, unfortunately, that hasn't really come to fruition, so I'm just curious does the appetite for M&A increase now?

I think we've been looking at M&A all along and if we can find some things that fit, we will do it. I mean we picked up some additional Eagle Ford acreage here and that fits. I would like to, as we've talked about before, add something meaty to our program and so we have an effort underway to do that. I do believe that we will be successful in exploration and maybe in something on the sheet that I'm looking at that I may rank differently than others but that's the nature of exploration. But yes, we're a looker and hopefully we'll be a buyer.

Okay, thank you very much.

Yes, thanks, Blake.

Pavel Molchanov with Raymond James.

Thanks for taking my question. Is it fair to say that the sale of the UK assets has proven more challenging than the sale of your domestic refineries?

Pavel, no, I wouldn't say that. I think what we've seen here in the US, so I'll give my comments, we've seen the crack spreads improve throughout the year. And so when you're negotiating to sell something in that environment, things tend to take a little longer. And here recently, we've actually seen more players come to the table because of that external situation and of course whenever you do that, things take longer. In the UK specifically, we had hoped to be able to do that as one package, but we realized now that we need to look and talk to companies and there's several interested for each individual package. And so that's really the change from our perspective.

Okay, and just as a follow up on that, you've said at the beginning of your downstream divestiture program that you intend to keep the US retail assets for the time being. Have you had any parties that are inquiring about purchasing that perhaps in conjunction with Louisiana or separately?

No, we really like our US retail and I've talked before about how we like that business and want to grow that business. And at some point in time, not now, we look to see how that future of that business would be. But people approach us about buying all sorts of things that we have and I'm not particularly a motivated seller, so I'm happy to keep the retail business a great business growing well and has a very, very bright future. So I'm selling the refineries here in the US, I'm selling stuff in the UK and that's the plan.

Understood, thanks.

Thank you, Pavel.

(Operator Instructions) Evan with Morgan Stanley.

Yes, just a couple follow ups, guys. Do you guys have a rig lined up to commence block CA-2 exploration? Is that a hand off of the Total rig?

No, it'll be a different rig but it's not finalized yet, Evan. But it's kind of looking at an early fourth quarter spud would be my guess, so don't tie me down to that but getting hold of rigs, but that's kind of the timeline we're looking at.

Is anything lined up for the 2 Congo wells also planned this year?

Well, what we're looking at is the Ocean Confidence which we took out of the Gulf and sent to Africa and is being used by somebody else. We want to get that rig back and we're real excited about the sub-salt prospects that we have and that rig would be ideal. So when that rig comes back to us, that's when we'll drill and it's probably going to be the end of this year.

Isn't there another -- doesn't that person have another slot option for that rig? I mean, could it come back later than you expect?

Possible but for our planning purposes here, we're assuming that we're going to get it by the end of the year.

Okay, any -- do you share any pre-drill estimates? I know you shared in the past on the -- at least on your kind of more near-term prospects on a P-50 basis?

No, you can end up with some really big numbers, some people counsel me to say I should say everything's just 100 million barrels and be safe that way. But we don't run that way. I think the big prospects clearly on a gross basis are going to be in Brunei and sub-salt Congo, and in Iraq, and in both Central Dohuk and the Barranan block. I mean these are all very big oily prospects and multi-hundred barrel individually, so I would categorize them that way.

Good, good. And just a follow up on Blake's question, I mean any color on the use of proceeds for the first refining sale? I mean you're going to have I guess late 3Q, early 4Q you get the proceeds from that sale, any -- is it debt pay down or what the kind of immediate the uses might be?

No. What I'd like to do is get the second one done and I don't feel in any rush to spend the money. Mindy will tell me that she'll take the money from us and pay down some debt and I'm happy for her to do that. But I think we've got a program here to identify things that we want to buy and hopefully in the next year, we'll be able to close on some of those. So I don't feel in a rush that we have to rush to spend the proceeds.

There's been a lot of activity also with the juniors in Canada and kind of unnamed major partners. Any comments on how your footprint or attractiveness of terms you're seeing for land positions kind of in and around your actual Upper Bakken stuff?

I would say as far as the extra goes, I'm reasonably pleased at the very beginning of a play. I don't think we know where the sweet spots are yet, hence we've stepped up our program this year from 6 wells to 8 wells. Put a couple of wells that kind of fit what we thought they should be, we've got 1 well that we're looking at, we've got another well to bring on, and we've got a drill in another part of our acreage footprint that we don't know anything about yet. So early days, some encouragement and we clearly need to get our costs down. I would still pick up acreage up there but I think we need to get a little technically smarter to understand where the sweet spots are going to be.

The other areas around Tupper, around Seal, around Eagle Ford, for our strategy all along is as our knowledge grows and as opportunities arise and as we find them, we will add acreage. So I'm actively trying to get more acreage in all of those plays.

And you also I think made reference to a new kind of unconventional play, but when should we expect to kind of hear maybe the identity of that, or did I mishear that?

No, you deliberately didn't miss it because I didn't say it. What we like to do is get into some of these plays relatively early and relatively inexpensively, and this is one of those we think, it is very early days. We're below in terms of acreage acquired of what I think is critical mass, and for us that's about 150,000-acres, so we don't have that amount of acreage accumulated yet. Once we get to that level and I think we'll be perhaps comfortable to talk about it. And so that'll be either this year or early next year I think is kind of where we get to. But it just demonstrates, Evan, that what we want to have is we want to have a certain value and amount of resource play in our program and adding another play further out in time helps us have that continuum, and so that's what we're trying to do.

Great, great, thank you.

Thank you.

[Lynn Dome] with Bloomberg News.

Hi. I just had a couple questions on the Meraux refinery. I know that the Company had said a little earlier that the flooding did not affect the production there at all, just wanted to confirm that. Also see if the maintenance scheduled for the SCCU in the [Acolation] unit over there is still on for January.

No, we did not get any impact from flooding which I think we've talked about before. And I don't have anything in front of me that has any different schedule than what you've talked about, Lynn.

Okay, thank you.

Thank you.

Monroe Helm with Barrow Hanley.

Thanks for the detail on the improving production profile. Just wondering when you get out to the 300,000-barrel a day target, what would that imply for Kikeh's gross production at that point in time?

In 2015, Monroe, Kikeh will be much smaller than it is now and actually Eagle Ford will be larger than Kikeh. The Block-K production, which will include Kikeh plus Siakap North plus Kakap, is really what we'll be looking at. So there'll be more production actually coming from Siakap North and Kakap and Kikeh will just be a part of that. And as we've talked about before, we're looking to keep that production on a net basis from Block-K, which includes all those 3 fields, as flat as possible. So it should overall for that block be flat to where it is now or where it's going to be here this year but it won't just be from the Kikeh field.

Okay. Since you talked about the increased importance of the Eagle Ford at that point in time, can you kind of fill in the blanks as to what the other 80,000-barrels a day is from the 220,000 you expect to be at the end of this year?

I don't have anything right in front of me that steps you up there but Monroe, I can get -- if you call into Barry, he'll -- we've done -- we've talked about that before at the (inaudible). I don't want to mistalk here, I don't have my curve in front of me but if you give Barry a call, he'll break it down for you.

Okay. But any event, it doesn't include any exploration success at this --?

No, no, Monroe it does not and that's why we feel pretty good about where we're going. And so if you were to ask the question, so what risks are there in that number? Then I would say gas price. If gas prices were $4 or less by 2013 or 2014, I may be not so enthusiastic to allow gas to grow very much. But other than that, I think the acreage footprints in place and I think we have the opportunities to get there, and exploration would just be a nice plus on top of that.

Okay, terrific. Thanks for the answers.

Monroe, thanks.

(Operator Instructions) Mark Gilman with The Benchmark Company.

David, I thought I heard the word when you were going through the upstream reorganization which in my mind implies personnel. Were there any personnel changes that you had been making recently as part of this change in process?

We've moved some people around. It's part of career development for folks and part of trying to make our business better. We have a lot of smart capable people here, Mark, and we're just trying to make sure we're doing the best that we can here and so that's what it is.

We have now kind of a North American piece of business. We've operationally done a great job in developing our Tupper Resource. We want to bring some smarts and expertise from that learning curve down to Eagle Ford, so that's one case. We think that how you frac wells and how you drill wells has a degree of universality. And so we have talented folks in our Company and want to get them involved in other projects.

Okay, David, I believe in the last call we talked about the level to which on a gross basis, Eagle -- Kikeh would recover, that a 90,000 a day figure was utilized. Am I comparing apples and oranges by comparing that 90,000 to the 80,000?

The 90,000 was the exit rate at the end of the year so end of December, the number I gave you was a November rate. And I said that the assumption was I would hold flat and not have any additional wells come on and contribute by the end of the year. And so it's an apples/apples because I'm not looking at the same time line, Mark. The real issue going forward with new people and new processes is to make sure that we're comfortable with the targets that we're setting. And timing of wells is clearly end of year thing; can get you a number one way or the other. And so real comfortable at the 80,000 number in November, don't quite know where we'll be at December.

Okay, what happened with the fourth well at Azurite and what do you think has plateaued, now it's increasingly looking like plateau might have been achieved already and it's in decline?

Azurite has been a little bit of a surprise sub surface. This last well we did -- let me get this right -- we did a side track and the pay looked good, have to do another side track to make sure it was in connection with a water injection well. And when we got the well on, we didn't see the performance that we expected. And so now we're in the process of re-evaluating that. We believe that the oil in place number isn't the question, it's the connectivity between water injection and the producer, I think that's the issue. So it's a question for us today and we're working it today.

So it's a recovery factor issue?

Well, I can't answer that, Mark, until we get to understand why based on our up to drilling the well work, we thought we were drilling the well in the right place related connectivity wise to a water injector that we thought was in the right place. We just have some more work to do there.

David, you referenced in your comments take away capacity constraints in the Eagle Ford. Are you addressing that through choking the wells back or how is -- is there a capacity number in place that would suggest capacity currently is greater than the 7200 you're producing?

I think we've got full wells that are producers that we don't have on, so unconstrained I think we could produce more. We have a number of field [bactories] being developed. We have a number of pipelines. This is not a all flow into one place sort of development. And so I think that the off take capacity is going to have to be improved through this year and into next year for us and for a number of other players to start removing some of the bottlenecks. And so we've got some growing pains and I think the infrastructure in the areas that we're developing has some growing pains. But I'm pleased to see that there's commitments being made for new off take arrangements and pipelines. So I think all this will be worked out here certainly into next year.

David, with the exploration program in place, are any of the prospects stratigraphic as opposed to structural?

Let me see. Probably the one in South Barito in Indonesia is and everything else that we're dealing with is a bump.

I'm sorry everything else is --?

A bump (multiple speakers) -- [structure].

Okay. And just a final one for me on the UK tax. I'm a little bit confused as to what the $15 million charge in the third quarter is going to be. Is that a deferred tax remeasurement? Is it the prior period impact, or is it the current period impact? Kevin, maybe you could clarify that for me?

This is John. It is an adjustment of our deferred tax liabilities going forward due to the 12% increase in rate, Mark.

Well, don't you have to book a prior period, given that the effective date is March?

No, you're talking about adjusting prior period numbers?

Well, no, the effective date of the increase, John, is March.

That's correct.

You haven't been accruing it I don't think, have you?

No, no, but you book it as when it's enacted, Mark, and it was enacted in July. So you take your adjustment when it's enacted officially by the UK government and that happened in July.

Mark, the $15 million gets us up to date through September.

So it includes both deferred tax remeasurement and the prior period?

Yes. I mean the $15 million includes the impacts from March 24, don't hold me to that day, I believe that was the day, but it does include some impacts of that 12% increase on pre-tax earnings from March 24 forward.

Okay, but (multiple speakers) --

(multiple speakers) [It's not] a deferred tax liability adjustment.

Okay, but it does not include the normal third quarter impact?

No.

Was that a no? I'm sorry, I didn't hear it.

That's a no.

Okay, thanks very much, guys.

Mark, thank you.

Paul Sankey with Deutsche Bank.

Hi again, sorry it's me again. David, there's been direct press speculation about a potential merger or takeover by Husky with you guys. Are you in any whole Company negotiations for Murphy to either merge or sell itself to Husky or anyone else?

Paul, we don't make any comments on market rumors.

Understood. That's now been reported in the press, so I can raise it. But thanks, I understand.

Okay.

(Operator Instructions) And it appears that we have no further questions at this time.

Operator, thanks very much. I appreciate everybody calling in and look forward to our third quarter call later in the year. Thank you.

Thank you very much. Well, again, ladies and gentlemen, that does conclude today's conference.