Murphy Oil Corp (MUR) 2011 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Murphy Oil Corporation third quarter 2011 earnings conference call. Today's call is being recorded. Now I'd like to turn the call over to David Wood, President and Chief Executive Officer. Please go ahead, sir.

Thanks, 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, Assistant Manager Investor Relations. I'll 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 third 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 in the third quarter 2011 was $406.1 million at $2.09 per diluted share that compares to net income the third quarter of 2010 of $202.8 million or $1.05 per diluted share. For the nine months ending September 30, 2011, we had net income of $986.6 million or $5.07 per diluted share compared to net income of $624 million for nine months ending September 30, 2010, or $3.24 per diluted share.

Beginning in the third quarter this year operations related to the Superior and Meraux refineries which were sold September 30 and October 1 respectively have been reported as discontinued operations. Excluding these results, income from continuing operations totaled $335.7 million or $1.73 per diluted share in the third quarter of 2011 compared to $197.4 million or $1.02 per diluted share from the third quarter of last year. For the nine months period ending September 30, income from continuing operations totaled $854.2 million or $4.39 per diluted share in 2011 and $630.1 million or $3.27 per diluted share for 2010.

Looking at income from continuing operations by segment, in the E&P segment we had net income in the third quarter 2011 of $261.9 million compared to net income of $186.7 million in third quarter of last year. The higher earnings for the 2011 quarter were primarily due to higher crude oil and Sarawak natural gas price realizations partially offset by higher exploration expenses. The current quarter also saw net benefit of $11.1 million from income tax matters. Crude oil and liquids prices averaged $95.95 per barrel in the third quarter of 2011 versus $65.45 last year. North American natural gas prices averaged $4.20 per Mcf this year compared to $4.24 last year while in Sarawak third quarter 2011 natural gas price realizations averaged $7.54 per Mcf compared to $5.71 per Mcf last year.

Crude oil and gas liquids production for the quarter was over 96,400 barrels per day compared to approximately 119,900 barrels per day in the corresponding 2010 quarter. Decrease was mostly due to lower production from Kikeh offshore Malaysia where wells have been shut in or curtailed for work overs. Natural gas sales volumes averaged 470 million cubic feet per day in the third quarter this year compared to 371 million per day the third quarter of last year. This increase was primarily due to production from gas fields offshore Sarawak Malaysia and higher production from the Tupper West area in western Canada which commenced during the first quarter of 2011.

In R&M segment income from continuing operations third quarter of 2011 were $68.9 million compared to income of $45.2 million the third quarter of last year. In North America an earnings increase of $29 million was primarily due to higher fuel margins in the retail business. In the corporate segment the third quarter of this year saw a net benefit of $4.9 million compared to net charges in the third quarter of 2010 of $34.5 million. Improved results in this segment were primarily due to foreign currency gains where we saw an after tax benefit of $28.3 million in the 2011 quarter compared to after tax costs of $15.8 million last year largely as a result of the weakening Malaysian ringgit against the US dollar.

Capital expenditures for the year estimated about $3 billion. This is down slightly from previous guidance of $3.2 billion largely as a result of the timing of the spending such as in the Eagle Ford area where we have seen some delays in getting additional rigs onto our acreage. As of September 30, 2011, Murphy's long-term debt was $974.5 million or about 9.9% of total capital employed.

In early October outstanding balances under our revolving credit agreement of $725 million were paid off from proceeds of the US refinery sales. It is expected that by year end our long-term debt as a percentage of total capital employed will be in the low single digits. With that, I'll turn it over to Dave.

Thanks, Kevin. WTI crude prices recently settled back into the current $85 to $90 range after exhibiting weakness in the third quarter. Dated Brent the mark-up for 80% of our production continued to outpace WTI with the spread averaging just under $24 for the quarter. The recent contraction in the WTI Brent spread is likely to remain through year end and doesn't appear to have a single cause.

North American natural gas prices suffered through the summer shoulder season averaging near $4.00 an MMBtu for the quarter and more recently dropping to the $3.50 range ahead of the start of the winter heating season. Consistent with our pricing strategy, we have sold approximately half of our monthly gas production for this year.

Our exploration program restarted late in the third quarter with the non-operated wells being spudded in the Gulf of Mexico and Brunei. In the Gulf, drilling of the Deep Blue sidetrack continues. We have found some oil pay but plans are to finish the drilling phase and move toward further evaluation.

In Brunei, the first well in the CA-2 block was expensed as a dry hole, the objective section being largely devoid of reservoirs. The rig has moved and spud Meranti No. 1, the second CA-2 prospect. Filling operations at the first well in block CA-1 are still ongoing. Both Brunei blocks have multiple prospects featuring very large structures with the biggest risk related to this play associated with mass transit deposits that erode and influence reservoir distribution.

Through the next few months we will see a number of other impact wells started with Iraq early in the new year as well as the testing of deeper targets offshore Republic of Congo. Drilling in block H in Malaysia will start up in the fourth quarter of this year and be timed for the return of our rig from Indonesia. In the Gulf of Mexico we have finally gained approval from the Thunder Hawk No. 4 infield development well and hope to secure a rig to spud this before year end.

Global production for the third quarter averaged 174,803 barrels of oil equivalent per day just ahead of guidance of 173,000 per day. This positive variance was attributable to higher production from the Eagle Ford shale and Tupper West as new wells came on stream. We also experienced less down time at Syncrude, Hibernia and Terra Nova in Canada and better on-time performance at the non-operated LNG facilities in Malaysia. This was partly offset by lower production at Azurite due to field performance and from the Gulf of Mexico which was impacted by a tropical storm system in the quarter.

Plans to reposition our Company remain on track as we executed on our strategy to exit the refining business having closed on the sale of the US refineries located at Superior, Wisconsin, and Meraux, Louisiana. Cash proceeds were approximately $960 million and were used to pay down our revolver while we look to redeploy these funds.

We have moved our focus on to completing the divesture of our downstream assets in the UK. The Northwest Europe refining market remains challenged and it's likely to take a little longer than originally planned to divest the Milford Haven refinery.

Our US downstream business turned in a solid performance for the quarter with $88 million of net income. The UK downstream business continues to deliver reliable operational performance in a difficult market environment with the UK retail providing consistent returns.

Production guidance for the fourth quarter is estimated to be 198,000 barrels of oil equivalent per day up just over 23,000 from the third quarter. This increase over the third quarter is primarily attributable to recovery of production in Malaysia with ongoing re-completion work at the Kikeh field. Additional development wells at West Patricia and ramping up of new wells on stream from the North American resource plays at Eagle Ford, Tupper West and Seal as well as less down time in the Gulf and also the UK where maintenance work at Schiehallion is completed are also part of this. This will put overall 2011 production just below prior expected levels due to slower than expected ramp of new wells coming on stream in the fourth quarter and unplanned down time at Schiehallion and Syncrude.

The work over program at Kikeh remains on track to restore production from that field to 80,000 barrels a day in the fourth quarter. We have re-completed and flowed back two wells to date with the new gravel pack technique, both with expected results and have executed re-completion work on three other wells all without issue and are about to flow those three back within the next week. We also recently completed the work over on the well with a down hole mechanical issue again successfully.

Looking forward, I expect to see 2012 production levels to show attractive year on year growth as we ramp up activity in the Eagle Ford shale and Seal areas of our North American resource portfolio with the emphasis on oil and liquids. While the budget process is still ongoing, I expect we will average 200,000 barrels of oil equivalent in 2012 and 225,000 barrels of oil equivalent per day in 2013 as we march towards our 300,000 barrel a day target for 2015. Low North American natural gas prices remain a factor in the short term as we balance growth in our Montney and Eagle Ford shale dry gas developments with oil-weighted opportunities.

Updating our North American resource program, we currently have 11 rigs active with 5 working at Eagle Ford and 6 in Canada. Reorganization of our North American business unit is well underway bringing expertise and compliments from our Montney development team to our fast growing business in the Eagle Ford shale. Activity in the Eagle Ford shale continues to ramp up where we plan to add two more rigs near term. To date, we have drilled 45 wells with 8 awaiting fracs. Well results continue to be very encouraging and are trending better than our tight curve for wells in the play.

Gross production is currently 9,375 barrels of oil and 9.4 million cubic feet of gas. The region continues to be impacted by take-away capacity, although we've seen improvements and we look for this to get even better as infrastructure projects move forward into next year. In western Canada we have six rigs operating between the Montney acreage at Tupper and our heavy oil operation at Seal with the first phase of appraisal drilling in the southern Alberta Exshaw play just concluded. The Tupper area continues its good operational performance with rates currently over 200 million cubic feet per day as the buildup continues to fill out the new Tupper West gas plant.

Heavy oil production growth at Seal is moving forward at an accelerated pace as we focus on additional development drilling, down spacing opportunities, multi-leg laterals and advancing our EOR projects. We are fortunate to have the flexibility to redeploy capital to Seal as we manage the pace of development from the Montney pending some support there in natural gas prices.

In southern Alberta our actual Bakken appraisal program has completed the first phase. We have drilled a total of 6 wells. The last well is awaiting completion, 2 wells are showing productive capability in line with expectations, 1 well is producing at very low rates and 2 wells are shut in to evaluate. Overall production results from the first phase of wells have been mixed and we continue to evaluate the play to identify sweet spots and areas for improvement.

In business development we are finalizing the terms for a PSE on two blocks offshore Vietnam and are close finalizing a new block offshore Cameroon in West Africa. We continue to evaluate bolt-on opportunities for our resource plays and are adding to our land position in the fifth North American resource play bringing our total North American resource acreage to over 800,000 net acres.

Our US retail chain broadened its partnership with Walmart and extended the current $0.10 per gallon rollback program on gasoline prices through December 24. We have added 20 stores year to date bringing the current station count to 1,119 and should add 6 new sites before year-end. Longer term, we are excited about the opportunity to expand both within and outside our current footprint with Walmart.

In the renewable fuels business the crush spread average $0.35 a gallon for the quarter despite easing off in to the $0.20 range in September as corn prices moved off their highs near $7.50 a bushel falling $1.50 as markets sold off in response to global economic concerns despite supported fundamentals for corn with lower yields and tight supply. Our ethanol plants at Hankinson and Hereford continue to focus on safe, reliable operations with production rates in the range of 120 million gallons and 105 million gallons per year respectively.

In summary, the third quarter showed good performance and our repositioning is on track. We completed the sale of the two US refineries and efforts are now focused on the sale of UK assets. Our North American onshore business is moving forward under reorganization with accelerated development in both Eagle Ford and Seal heavy oil property. I see both gaining strength and making even greater contribution going forward.

Drilling continues in the Montney to fill out the Tupper West facilities with a continued focus of managing development and production growth from our dry gas opportunities pending some level of price support. We should end the year within sight of our re-calibrated 2011 production target and should exit the year near 218,000 barrels of oil equivalent per day. Our budget and long range plan activities are well underway and we remain focused on the 300,000-barrel target by 2015 from our existing resource base. Project execution remains very active with 7 projects sanctioned this year that will provide nice production growth starting in 2013. We already have plans for a further 3 field sanctions next year all helping build towards our goal along with active development across our Eagle Ford shale position.

The exploration program is back in action with impactful prospects to be tested near term in Brunei, Congo and Iraq. Our prospect inventory continues to develop with the addition of new exploration blocks and new country entries witness Vietnam and Cameroon. The US retail continued with excellent performance and provided a solid contribution in the quarter and is very well poised for future growth.

We are still working through our 2012 and 2013 budgets for next year, as we spend close to $3.5 billion and at budget price decks that puts CapEx just ahead of cash flow. Of course, if current prices are maintained through next year, that position will be helped. That concludes my prepared remarks. I'm now happy to take your questions.

(Operator Instructions) We'll go first to Blake Fernandez with Howard Weil.

Good afternoon, guys. Congratulations on the strong results. Two questions for you, if I could. The first is on the exploration side. Given the discovery that Tullo had in French [giarnare], I'm curious if that changes your view or the prospect opportunities that you may have in Surinam?

Okay. Blake, how you doing?

Doing well, thanks.

Good. Yes, we're doing pretty well here. We entered that play recognizing that the margin had the type of opportunity that Tullo had found success in French [giarnare] and we tried two different prospects and they didn't work or really upped Seal issues which we knew going in was a main risk. We're back looking again at our current acreage and we're back looking at other acreage in the play to see where to go next. I'm not discouraged. Dry holes happen in our business, but I am encouraged that the play has been shown to work by somebody else and so we were there and I think now our exploration guys have just got to find out is there other things for us to do on our block or on the other pieces of acreage that we would like to have and so that process is ongoing.

Okay, great, thanks. And then the second question was on the production side. You've lowered the exit rate by a couple thousand barrels a day, although it sounds like you're fairly optimistic on the work-over wells in Malaysia. I'm just trying to get a sense. Where did the, I guess, shortfall, if you, will come from and can you give us saints of what volumes may look like in Malaysia overall into next year once all of the work-over wells are on and producing?

Yes. Blake, it's a good question. The simple answer is that we got a little bit behind on one well at Kikeh where we had a poor cement job and we lost some timing and then we did not factor in down time in Schiehallion and Syncrude to the level that actually took place. So October was a bit of a delayed month for us and that's really where the problem lay which is why we're a little off here in the fourth quarter. Third quarter was good. I was very happy with where we were in our new processes and in our ability to predict.

As we look at Kikeh and I'll just kind of jump into Kikeh, I think probably other questions will probably be answered by this. We're currently just under 63,000 barrels a day today. We said at the last call that we had 6 wells to bring on by the end of the year, we brought 1 on. As I look in front of us, we've got 3 wells ready to come on within the next week and if we hadn't had the delay that I mentioned earlier, they would be on today and so I think that's really the issue. And so by the end of the year we see ourselves being at the 80 number, and so feel real comfortable about it. We've had good results from the well that we brought on for some period of time with the sand finds migration. This gravel pack technique has worked well. The jobs to do the same on 3 wells that we're getting ready to bring on here in the next week have also gone well and so we expect those wells to perform as expected. And so feel overall very good about where Kikeh is going.

If I look at where we're going to go from today to the end of the year, we've got actually 48 wells to come on between now and the end of the year. So that drives that exit rate at the end of the year. We've got 19 at Tupper, 11 at Seal, the 5 at Kikeh I mentioned, 11 at Eagle Ford, 1 at west pad and 1 at Front Runner and so that drives the curve and, Barry, why don't you break down the pieces there and maybe give a little more granularity to it.

Blake, this is Barry. Current production today is right around 190,000 barrels a day. So to get to the 218,000 exit rate, basically you've got the Kikeh work-over program over 9,000 barrels a day. Our resource plays here in North America they're all ramping up with additional wells coming on, you've got Tupper west 5,000 BOEs a day, you've got Eagle Ford at 2,500 BOEs a day and you've got Seal at 1,500 barrels a day. So those are the resource plays.

On our non-operated Canadian projects at Terra Nova, Hibernia and East Coast you've got another 3,000 barrels day coming on there with less down time maintenance this quarter and the same can be said for Syncrude about 3,500 barrels a day there with less maintenance down time. And, finally, in the Gulf of Mexico we've brought on (inaudible) a front runner so at 1,500 barrels a day there, and then finally the UK with Schiehallion and Amethyst coming off their maintenance programs and back on, that's 2,000 a day. So that gets you from the 190,000 to the 218,000.

Appreciate the detailed color. Thank you very much.

You bet.

Thanks, Blake.

Next up we have Evan Calio with Morgan Stanley.

Yes. Good afternoon. Nice quarter, everybody. My first question is on Kikeh realizations. Are there higher in the quarter, maybe a function of tapest differentials but also probably a partial function of cost recovery through the PSC and so kind of given the spend level, how could you kind of guide us through your elevated realization in Kikeh in 2012 would be helpful?

Evan, I'll take that call -- that question. This is Mindy.

Hi, Mindy.

Our actual price for realizations that we got in Malaysia on the oil side was just under $120 a barrel this quarter. That differs from last quarter it was $125 in the second quarter. Our supplemental payment, however, was lower this quarter versus last quarter because due to our work-over programs more of our barrels are being recovered as cost barrels and, therefore, are not subject to that supplemental payment and our overall realization or entitlement has been in the high 60s versus the low 60s and we do expect that to continue into this quarter as our work-over program continues, but probably should level out some next year and be closer to where we have been previously, so entitlement in the lower 60s.

Okay, great. That's very helpful. Also on the realization side the Sarawak Gas volumes and the realizations were both higher and there's been recent articles discussing a sharp increase in Malaysia natural gas demand year to date. Does that accelerate maybe your potential expansion plans or how does that influence that pricing formula? Is there any -- I presume it's partially a component of pack basin and LNG pricing.

It's a function of LNG prices. We can't discuss particulars about the formula and there is a little bit of lag to the formula as different cargos get priced in but, yes, it's due to strengthening of the overall price for LNG globally with the lag built in.

Evan, it's a very good project for us. We've been averaging north of 250 million a day there, good operational results. Have found additional resources to bring on to be able to extend the plateau there or if we're asked, to be able to produce more. So we have great flexibility there and the fact that, that gas price has got an oil-weighted index clearly as oil prices have moved up, gas prices have moved up. I think this time last year we were talking $5.70 and now we're in the $7.40 range. So that's what's happened over the last 12 months.

So the production levels are somewhat a function of demand, so you could produce at a higher rate than you did this quarter?

Well, we're producing pretty steady state. If we're asked by Petronas to produce more once we do a little bit of change around, we certainly could do that. So it's not a resource or deliverability issue per se, but we budget around this 250, 260 level.

Okay. And lastly if I could, you touched on this in your opening comments, but given the natural gas prices how should we think about your Montney expansion here? Are you going to grow to fill the new gas plan or potentially just run third party volumes and shift some capital to other more liquid portions of your portfolio? Thanks.

Evan, it's kind of the key question for us. We believe we have very nice resource up there with good oil and costs around 350, but it's just smart I think to hold that program flat. So if you look at our budget next year and the year after, we don't really show any growth there. We have the technical capability and the desire to do that but absent any gas price support will not. So we'll be averaging about 230 next year and the year after absent any price improvement and so that gets us to filling the plan say for some third-party production that we already have going through. So that's kind of where we're trying to get to.

Great. Appreciate it, guys.

You bet. Thanks, Evan.

Next we'll go to John Herrlin with Societe Generale.

Some quick ones. With Kikeh, what were the work-over costs and were they all absorbed by the PSC or did you have some direct costs?

All costs get put through the PSC, John. So as far as exact costs, I'll have somebody here dig a number for you. So go ahead to your next question.

Okay. Sure. In terms of the new concessions in Cameroon and Vietnam, are you looking at (inaudible) type targets in Cameroon and what about Vietnam?

Cameroon is a turbidite play. It's a (inaudible)by us to accompany part of the acreage. It doesn't have access right now. We've just actually yesterday got our agreements done. We think that it's highly prospective for oil in an area that has worked for other people for a play that's worked for other people. So we're very pleased to be there. Vietnam is in deeper water off the East Coast. We think it's largely untested play, but with our knowledge in the south China Sea, which is pretty good knowledge, we think it's quite prospective and so I see these first blocks in Vietnam be the first of a few and I'd like to see us grow our footprint there because I think there's other opportunities to explore.

Okay, great. With the Eagle Ford what are your well costs running?

Eagle Ford costs vary by area, but let me look at my little cheat sheet here so I don't give you an incorrect number. Drilling runs between a little over 3 to a little over 5 and completion costs a little over 4 to a little over 5. That's kind of what they've been running. Some areas we're down at 12,000-foot to the Eagle Ford and some areas we're as shallow as 6,000. So that's the reason why there's a wide range.

How long are the laterals and how many stages are you using for the fracs?

Usually 15 or 16 is the number of fracs and we'll usually go 3,500 to 4,000 feet, that kind of range.

Okay. Last one for me. Do you think in the future you might break out your North American non conventional plays in your disclosures?

Break out so that --

Like Eagle Ford just list the production so we can watch it.

Oh, believe me, I'm watching the production. We've got some pretty nice growth for Eagle Ford. So we'll end the year a little over 9,800 barrels net. In 2012 we should exit a little over 20. In 2013 we should exit a little over 36.

That's why I'd like it disclosed.

2014 a little over 50. So that I think gives you a sense as to where we're going with that program.

Thank you.

You bet. Thanks, John.

(Operator Instructions) We'll go to Pavel Molchanov with Raymond James.

Thanks, guys. First on the Eagle Ford, can you just update us on the acreage position and whether you're still adding acreage either through just additional bolt-on deals or anything else.

Pavel, we'd like to. It's getting pretty pricy in the oily plays. We're just a little under 240,000 net acres in the play and as we see opportunities to add, which tend to be small, we'll do that.

Okay. Any particular target or just entirely opportunistic?

It's pretty frothy there and so I would say opportunistic. There's some cases small pieces of acreage and some larger deals to be done and so we're in the game. We're active, but I don't have one that's right in front that I can say we're going to do it today, but we're looking to grow that footprint.

And then lastly with regard to the UK refinery sale, how is the level of interest from potential buyers been compared to your two domestic plants?

I'd say today we've got three or four folks that are talking to us about the refinery and quite a bit more than that, that are interested in our retail business. And so the question is and, of course, end of the year December is a very difficult month to do anything anyway, which is why I've suggested that maybe it's going to be more of a first quarter next year kind of business, and then we always have the option with Milford Haven of looking at turning it into a terminal which is something that we've thought about and have that option as well. So I think it's a 2012 decision on all of that.

Okay, very good. Appreciate it.

Thanks.

Next up we have Mark Gilman with the Benchmark Company.

Hi, Mark.

David, how are you?

I'm good. How are you?

Good, thanks. Let me see if I understand what you were saying in terms of Tupper west correctly. Are you deferring Tupper west Phase II?

We don't have to make that decision until next year. So if gas prices stay the same, I would say that it's more than likely that we would not do it, but we don't have to make that decision today.

Okay. What working interest number should we be applying to your gross Eagle Ford volumes as you discuss them or quote them?

When I give you net, it's net, but our working interest varies from 90s down to something in the 50s throughout, but what I tried to do, Mark, is give you our net production number.

Yes. But when you quoted where you are currently, David, and this was similar to I think the comments that were made in the prior call, you talked about it on a gross basis.

No. I gave net today, Mark. So let me give that again.

Yes. Let's try that again if we could please.

Yes. So we're looking to exit here. So at about 9,800 barrels a day net, equivalent net.

Okay. The 9375 that you quoted earlier in your prepared remarks I believe was a gross figure, was it not?

That's gross today. The 98 figure is the end of the year exit net.

Okay. What is the net on the 9,375 and the 9.4 million feet a day?

It is 6,951 barrels of oil equivalent per day net.

Okay, thanks. Can we talk a bit about the Cameroon for just a second? Is this the same play as the -- and I'm probably going to mispronounce this, but the [Supel] discoveries that you're looking at there?

Yes. I think --

2011 discoveries.

Yes. I mispronounce things, too, Mark. I think they call it [Supel] and it's quite similar to that. So, yes, you're right.

David, I want to see if I can understand correctly the Suriname situation. It was my understanding that the two wells you drilled there were separate play types and only one of which was analogous gas to the Tullo French [Giena] discovery. Is that accurate?

Well, I don't have any data on Tullo discovery, Mark, so all I have is data on mine and what's been publicly said about Tullo's discovery, but what we were looking at in the two wells we tested was to drill fans that were very near or within the Turonian source rock interval and that's what we did and it's my understanding from what's been publicly said is that was the equivalent interval in age that Tullo were testing. So in that regard I would say that they were similar. As far as geometry, et cetera, I only know what the issues were with ours and we believe our (inaudible) Seal was not present in both cases. We did have oil shows, as we reported in the section, and believe that the leakiness of the trap was the primary risk for us.

Okay. Can I just move to Seal for a sec and what you're seeing in terms of the polymer pilot? Being.

Mark, it's going very well. The voidage is very good and the incremental rates basically we're taking wells and doubling the rate. So they've gone up from 50 to 80 barrels to two times that and so that's all very positive and we will go through next year with a beyond pilot and have an actual development in an area. So that's very positive. We've also had a couple of multi-lateral wells come on. These are 6 laterals drilled from one vertical borehole and have over 400 barrels a day from those wells which is very positive. So there's a lot of things associated with our Seal work that are very attractive for us and we like what we see.

When do you think you might be in a position to sanction the major polymer project?

We're going to break it down and probably do three or four or five areas with the polymer and as soon as they get on my desk, I will approve them. So I expect the first one to be next year, Mark. The other thing that we're working on which I think is important for folks to remember is that the thermal component of EOR we believe will work nicely at Seal and through the course of next year that will be something that we will be working on. Of course, we have to go through a series of approvals to do that, but that's got some nice upside for us.

David, who is the operator on CA-2?

CA-2 is Petronas.

And the second well I think what you referenced in your prepared remarks, is that a different play type from the first well?

No. It's similar age section. It is a separate (inaudible) structure a little further outboard than the first one. It's called [Merante]. I refer in my remarks to these mass transit deposits. We've seen these along the Sabah margin. They're basically shallow water sediments or shelf sediments that are redistributed into the deepwater and they either wipe out the reservoir that's already there or they influence the deposition of reservoir that takes place and so the first well that we've drilled in CA-2 saw a thick section of these MTDs. They generally are not reservoir quality themselves and so that is one of the risks going in that we are aware of and so understanding the MTDs and where the MTDs are not is a critical element, I think, in exploration in all of Brunei.

Thanks very much, David.

You bet, Mark. Thank you.

We'll go to Katherine Minyard with JPMorgan.

Hi. Good afternoon, everyone.

How are you?

Good, thanks. Just a couple quick questions. As we think about your production growth to 300,000 barrel equivalents a day through the middle of the decade or in 2015, I know we've got a few projects or some of those volumes that will need to come from additional project sanctionings. What might we be looking for over the next say 12 to 15 months or so in terms of milestones, in terms of sanctionings that would kind of bridge some of that delta?

Well, really the first thing is the projects that we sanctioned this year that start to come on in 2013 are going to have as big of impact as any and we sanctioned 7 this year, Siakap North in deepwater Malaysia, [surrender] Patricia South access [permits] in [Indow], in Sarawak and then Schiehallion redevelopment and that will be a little later, that will be 2016, but those fields were new fields to be brought on. Next year [Dalmatian], potentially Tupper west Phase II if we get some gas price assistance and then what we were just talking about earlier which is Seal will all add in the 2014 kind of range. So those are some of the milestones that we're looking at and then we have some things that we're working that we hope to bring forward through the course of next year as well. So it's those this year and next year that I think really will drive that 2015 target and what I'm not including in there is our Eagle Ford which, for me, is just kind of an ongoing development of the footprint that we've already got. So it will add on top of that.

Okay. All right. And then I apologize if you guys already addressed this, but I'm looking at your exit rate for the year of 218,000 and then your 200,000 barrel equivalent per day as your full year guidance for 2012. Am I missing a big maintenance project or a big maintenance undertaking or something that kind of results in that drop from the exit rate to full year next year?

No, Katherine. It's kind of like my golf game. On any one given shot I can make a good shot, but you got to put all 18 holes together to get the full picture. 218,000 barrel equivalent per day at the end of the month doesn't reflect normal down times, normal work overs, et cetera. The 200,000 is the average for next year and so you should compare that number I think to the 185,000 or the number close to 185,000 for this year and to me that's the year-on-year number and then compare that to the 230,000 number or 225,000 number that we're talking about for 2013 on average. I think that's really the comparison that I would point you at.

Okay. All right. Great. And if I could just squeeze one final one in here. Just thinking about your cash balance, clearly you guys have maintained a pretty strong balance sheet and you're looking at debt to cap in the low single digits by the end of the current year if I got Kevin's remarks correct. Are there any other potential uses of cash? I mean clearly developments are one of them. You've got the dividend, but should we be thinking about looking for anything like, for example, funding maybe some under funded pension liabilities or any other uses of cash that we might be looking to see are or you going to try and retain that strong cash position?

Yes. We don't have any under funded pension liabilities and we do have an exceptionally good balance sheet here. We have all things kind on the table, Katherine, is the way I would look at it. We clearly are prepared for success in our exploration game for developments. We would like to acquire some things that will help bolster our growth and asset base in our upstream business and so we're working that actively now and other things that will help our overall business we're actively looking at. So it's a nice position to be in and we feel good having executed on the refinery sale that allows us to be in this position, so --.

Okay, great. Thanks a lot, everyone.

Thank you.

Take a call from Blake Fernandez with Howard Weil.

Guys, sorry to re-prompt in, but I had one more question for you on the western Canadian gas prices. I know Shell is exploring the potential for LNG export from the West Coast. Just curious, have you had any discussions with them and is that something that you think is it on the horizon that you could participate in?

Blake, I'm happy to sell gas to anybody for more money. So if there's opportunity to do that, we would look at that and have looked at it. I think LNG export from Canada is a little way down the line and there is a lot of gas that's there, but I've talked before. I actually think there's probably a better opportunity for some gas price appreciation in Canada because of that versus the US. So I think we're positioned, but I don't know that it will be a 2012 piece of business or a 2013 piece of business. It probably is beyond that.

Thank you.

You bet.

Let's take a call from Joe Citarrella with Goldman Sachs.

Thanks. In terms of assets I think you mentioned want in past that you don't believe you're getting enough credit for namely the retail marketing business and Syncrude. Any update there on how you're thinking about realizing those values going forward? Where do you stand on the potential for the retail marketing business to be on its own and how at this stage are you thinking about Syncrude in the context of your E&P portfolio?

Yes. Syncrude, I think, is a great asset and if you generally believe in increasing prices longer term given the long life of resource there, it's a nice thing to have. So I don't feel very motivated to do anything with that other than keep it and enjoy it.

As far as the retail business goes, I've said that it's, in my view, reached critical mass. It is a great business, has got good results as we talked about. I think it has a very, very bright future, but I also think that it's something that we as Murphy Oil Corporation necessarily don't get full value for and, as I've commented, I think at some point in time we will look very hard at seeing whether we want to make that a separate business or not and that isn't a 2011 decision, but I will say that I will look very hard in 2012 at that business and bringing that forward as a possible thing for us to do. So --.

Okay. That's very helpful.

You bet.

Quickly apologies if I missed this, but in that 200,000 BOE a day number for 2012, how much of that is Kikeh?

Kikeh will be near 80 on a gross basis, gross basis. That's not net.

And the net basis in that number?

Would be -- somebody?

Low 60s typically.

Got it. Thank you very much.

Thanks, Joe.

All right. We have a call from Paul Sankey with Deutsche Bank.

Hi, David. Hi, everybody. David, I was wondering on -- you've been very clear about the 300,000 target for 2015 for some time now. I was wondering, for example, at the time of the analysts meeting was 200,000 your anticipated rate for 2012 or is that now a lower number than you would have thought mid year?

Paul, I don't have the number in front of me, but I believe it's lower because of what has taken place at Kikeh and, yes, I think it's lower because of that, but I believe that the work at Kikeh has shown that we can address the problems and now get some stability there and I think going forward I think we're in good shape.

Yes. I mean I guess the issue is there's an implied acceleration kind of later in the period. We can infer sort of a 2014 number from your -- I think you said 225,000 for 2013, didn't you?

Yes.

Obviously if you go to 300,000 by 2015 the kind of treadmill is going to get quicker in the 2013 to 2015 time frame, but your confidence in Kikeh and your sanctioning ability is making you stick with the 300,000.

Yes. We have moved forward some of the projects that I mentioned that we sanctioned this year, Paul, which helped that. We also are climbing the curve faster on Eagle Ford than we had before. We have more rigs now and that's really our rig function. So we have made compensation within the rest of our program to be able to meet that target and I think the important thing here is that we're not looking for things that we don't have to make that contribution.

We talked a little bit about dry gas and gas prices and I think if we pulled out Tupper Phase II, we'd probably take out 30,000 BOEs equivalent out of that number, but we're working to make up that production with more liquids production to accelerate Seal, to accelerate Eagle Ford. So all of those things are kind of working around here so that we can kind of move towards that target. So there is some flexibility in there which you would expect from a program with many different things.

In the level of detail, David, suggests that you're happy with the portfolio as it stands and that you can clearly get there organically. Would we then infer that acquisitions are unlikely from you?

No. I think it's always good to make additions to your portfolio. As we talked about before I have, I really want to be focused on returns per BOE produced and you kind of have to have new things keep coming into your program to help you drive that be it through exploration, be it through acquisitions, be it through growing programs. So I'm happy where we are today, but tomorrow I would like to keep growing what we're doing and get better at what we're doing and so -- but today and on track to get to this number, Paul, I feel pretty good about it.

Thanks, David, and a separate followup, if I could. The retail, you're talking about the retail and potential long term for that part of your business. I was wondering whether you see it remaining within Murphy as such as whether that could become a separate company. Thanks.

We've had a -- I think it's a good topical question, Paul. In the past we had a timber business that we spun to our shareholders and that business, even though it's external, we spun to our shareholders and that business, even though its external business, is a difficult environment I think has done well and so I think our shareholders getting rewarded for really creating this retail business is a great way to go. I do believe it's a different business with different drivers than an E&P business and so I would say one logical step, one thing for us to consider seriously is that we would spin that to our shareholders and so as I address the question that was asked earlier, that's something that is not a 2011 look, but certainly will be looked at and pretty heavily in 2012.

Thank you, David.

You bet.

Thanks, Paul.

All right. We have Gene Gillespie with the Gillespie Consulting Group.

Hi, Gene.

Hi, David. Great quarter.

Thank you.

In terms of investment options going forward is repurchase of your stock at all on the radar?

It is on the radar, Gene. It gets looked at like a whole bunch of other things, so, yes.

All right. That's it. Thank you.

Thank you.

We have a question again from Mark Gilman.

Hey, David, the prospects that you're looking at in Cameroon and Vietnam, stratigraphic or structural?

The play in Cameroon is turbidite fan off the margin, so primarily stratigraphic and Vietnam has both elements to it.

I had thought per some comments either you, Sam or both made back at the May analyst meeting that going forward the focus would be almost solely on structural-type projects.

Yes. I think he was talking about as an overall weighting, Mark, and not on a kind of in total. So I think picking up both Vietnam and Cameroon is entirely in context with where Sam was going because we --

Same question.

Yes. CA-2 has mainly structural prospects to it, but there are stratigraphic opportunities there that we'll have to evaluate as we go down the drilling program, both there and CA-1 and in CA-2, and so we don't rule that out as being an important element given what I said about MTDs and how they influence reservoirs.

Okay. Thanks, David.

You bet, Mark.

That was all the questions we had for today.

Operator, thanks a lot and everyone, appreciate you dialing in and we look forward to our next call and talk about fourth quarter. Thank you.

Once again, that does conclude our conference call for today. We thank you for your participation.