Murphy Oil Corp (MUR) 2012 Q3 法說會逐字稿

Good afternoon, ladies and gentlemen. Welcome to the Murphy Oil Corporation third quarter 2012 earnings conference call. Today's call is being recorded. I would now like to turn the conference over to Mr. Steven Cosse, President and Chief Executive Officer. Please go ahead.

Good afternoon, everyone. Thanks for joining us on our call today. With me are Roger Jenkins, our Executive Vice President and Chief Operating Officer, Kevin Fitzgerald, our Executive VP and Chief Financial Officer, John Eckert, our Senior VP and Controller, Mindy West, our Vice President and Treasurer, Barry Jeffery, Director of Investor Relations, and Tammy Taylor, Assistant Manager, Investor Relations. Barry, you've got the customary cautionary statement?

Thanks, Steve and welcome, everyone. Today's call will follow our usual format. Kevin will begin by providing a review of third quarter 2012 results. Steve and Roger 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 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 2011 Annual Report on Form 10K filed with the SEC. Murphy takes no duty to publicly update or revise any forward-looking statements. I'll now turn the call over to Kevin.

Thanks, Barry. Net income for the third quarter of 2012 was $226.7 million or $1.16 per diluted share. This compares to net income in third quarter last year of $406.1 million or $2.09 per diluted share. For the nine months period of 2012, we had net income of $812.2 million or $4.17 per diluted share compared to net income for the first nine months of 2011 of $986.6 million or $5.07 per diluted share. During the third quarter of this year, Murphy's Board agreed to sell our UK Upstream operations, and as you know, our US refining operations was sold near the end of the third quarter of 2011. Accordingly all of these have been reported as Discontinued Operations in the respective periods.

Excluding these results income from continuing operations totaled $228.9 million or $1.17 per diluted share in the third quarter of 2012 compared to $347.3 million or $1.79 per diluted share in the third quarter of last year. For the nine months period ending September 30, income from continuing operations totaled $801.7 million or $4.12 per diluted share in 2012 and $847.4 million or $4.36 per diluted share for 2011. Looking at net income from continuing operations by segment, in the E&P segment, net income from continuing ops in the third quarter of 2012 was $221.1 million compared to net income in the third quarter of 2011 of $273.4 million. The lower earnings for the 2012 quarter were primarily due to lower North American natural gas prices, higher DD&A expenses and lower income tax benefits partial offset by the effects of higher crude oil sales volumes. Crude oil and liquids prices averaged $96.09 a barrel in the third quarter of 2012 versus $95.95 last year.

North America natural gas prices averaged $2.61 per Mcf his year compared to $4.20 last year, while in Sarawak third quarter 2012 natural gas price realizations averaged $7.59 per Mcf compared to $7.54 per Mcf last year. Crude oil and gas liquids production for the current quarter was approximately 105,800-barrels per day as compared to approximately 96,400-barrels per day in the corresponding 2011 quarter. The increase was mostly due to higher production in the Eagle Ford Shale and at Kikeh, partially offset by lower volumes from Terra Nova, which was undergoing a long term turnaround, and at Azurite. Natural gas sales volumes averaged 454 million cubic feet per day in the third quarter of 2012 compared to 470 million per day in the third quarter of last year. The decrease was primarily due to voluntary shut ins and deferred development activity for the Tupper area of western Canada due to depressed North American natural gas prices.

In the R&M segment income from continuing ops in the third quarter of 2012 was $42.8 million versus income in third quarter of 2011 of $68.9 million. Lower results in the US due to weaker margins for both retail marketing and ethanol operations were partially offset by improved performance in the UK where we experienced much stronger margins at the Milford Haven refinery. Additionally, a couple of weeks ago we announced a plan to separate the US Downstream business into an independent Company in 2013.

For the corporate segment, third quarter 2012 saw net charge of $35 million where in the third quarter of 2011 we had a net benefit of $5 million. Lower results in the Corporate segment was primarily due to foreign currency transactions where we saw an after-tax loss of $12.6 million in the 2012 quarter, largely as a result of a strengthening of the Malaysian ringgit against the US dollar, compared to an after-tax benefit of $28.3 million last year. Capital Expenditures for the year estimated about $4.4 billion. This is up slightly from the previous guidance of $4.1 billion primarily a result of a planned bolt on acquisition of properties we hope to finalize before year-end.

As of September 30, 2012, Murphy's long term debt was just under $1.2 billion or 11% of total capital employed. There is also one other thing I'd like to clear up from our conference call of a couple weeks ago when we announced various initiatives. None of the currently existing revolving credit or public debt of Murphy Oil Corporation will be allocated to the spun company. Any debt to be placed on the books of the US Downstream operations will be as a result of entering into its own banking arrangements, or of its own access to the public debt markets. And with that I'll turn it back over to Steve.

Thanks, Kevin. WTI averaged $92.20 in the third quarter. Stated Brent, which, as you know, is the market for the majority of our crude oil production continued to out pace WTI averaging $109.60 for the quarter, with the spread recently going beyond $20 a barrel. Crude prices have fallen off a bit recently on economic concerns. They still remain within our budget levels for 2012. Our natural gas prices in North America showed some improvement with Henry Hub averaging $2.89 in the third quarter, and, more recently, rising into the $3.50 plus range due to warm summer and strong demand for power generation with some impact of switching from coal to natural gas. US retail margins were challenged in a rising wholesale market during much of the third quarter and we have recently shown significant improvement.

We did see strong refining margins at Milford Haven which is a contributing factor to our overall Downstream results. As you know, we recently announced our decision to proceed with the spinoff of the US Downstream business, subject to confirmation of its tax-free status and other regulatory approvals. We expect the spin process will be concluded in 2013 and the new company will include all retail, US retail outlets, currently 1,154 stations, 2 ethanol plants, and 7 product distribution terminals. The UK Downstream business will remain with Murphy Oil Corp. until the sales process for those assets is complete. Roger Jenkins is going to give us now an update on the E&P business. Roger?

Good afternoon, everyone. First off in Exploration. In Malaysia, we drilled the Block H Bimban well and made another nice gas discovery. Our sixth in a row in this play encountering 262 feet of pay. Bimban has a resource level of 100 Bcf and we continue to work with our partner PETRONAS toward a 2013 sanction of a floating LNG project for Block H Malaysia.

In our shallow water Sarawak gas field Golok we successfully delineated a deep objective. This successful well will allow us to add 60 to 100 Bcf of resource to this long term asset. We drilled our final commitment well in Block P, offshore Sabah, Malaysia. The well did find oil and gas but the volumes were not commercial.

In the Gulf of Mexico we have an oil discovery on our DC134 Dalmatian South well. We encountered 50 feet of oil pay in the original hole and 86 feet of oil pay in a planned side track. We're currently performing studies as to the proper development options for Dalmatian South. The Miocene oil amplitude play is a focus area for Murphy in the Gulf with high returns.

Over in the Congo we're drilling the Opal Marine Number 1 well in the MPN block offshore in the Republic of Congo. The well should finish in December with a total projected cost of $65 million. The target zone is the carbonate which is a pre-drill estimate of 260 million-barrels. In Iraq we have completed drilling and testing in Linnava Number 1 exploration well and our Central Dohuk block in the Curt it Stan region. While the logs show numerous pay intervals we failed to produce hydrocarbon during the testing program and plugged and abandoned the well. We did encounter evidence of heavy oil that had a very high asphaltine content but were unable to achieve oil flow to surface. We're evaluating well results and what impact it may have on another prospect we have in this block. In Australia, we plan a November spud of our Euphene well in block WA423 P in the Browse Basin. We're in the final negotiations to enter into a new block in the Browse which contains several large gas prospects.

Our Business Development and new ventures efforts are focused in four areas. The Gulf of Mexico, deepwater, the Atlantic margin, Southeast Asia, and offshore Australia. This quarter we received official notice of award of Block WA481 in the Perth Basin of Australia. We continue to progress our growth opportunities along the Atlantic margin, Cretaceous Span Play in West Africa. This week we signed a production sharing contract to explore Blocks 144 and 145 in the Fukon Basin of Vietnam. These deepwater blocks encompass more than 4 million-acres and represent our first entering of Vietnam, a country we feel has many of the under explored characteristics that first attracted us to Malaysia. We hope to announce further PSE signings in the coming months, both shallow and deepwater.

As part of the ongoing review of our asset portfolio, we've decided to exit the UK Upstream business with the sale of Amethyst, Mungo/Monan and Schiehallion for a total consideration of over $300 million. We'll be foregoing 1,400-barrel oil equivalent production in 2013 and 24 million-barrels equivalent of proved reserves with the sale which is expected to close in the fourth quarter. We see the exit of the UK Upstream as an example of continued portfolio rationalization and will allow further focus in assets where we operate and add value.

In Malaysia our development work at Kikeh remains on track with two wells brought on in the third quarter and five planned for the fourth. Our new completion designs are working as planned. We've completed the subsea tie in work and have four new subsea wells flowing now that were drilled and completed earlier this year. Our production level at Kikeh is now exceeding 80,000-barrels a day gross and 52,000-barrels a day net, which has not been seen in this field since February of 2011. We have progressed the tie in up of the Kakup early production system and now have a complete conduit between the Kikeh FPSO and the subsea wells at Kakup. The major shut in of facilities at our Kikeh site is behind us and we're in the final hook up stages of surface equipment and that should flow these new wells later this month.

In the Eagle Ford Shale the development work continues at a steady pace. We have 10 rigs and three frac crews working continuously. We've now drilled 175 wells in this place with 108 on production. Our production rate today is 20,000-barrel equivalent net. We're planning on a December average net rate of 24,000 BOE per day and place our 2012 yearly average at near 15,000-barrel oil equivalent net. While the budget process is still ongoing, currently I expect we will produce 30,000-barrel equivalent a day next year in Eagle Ford Shale.

We continue to progress down spacing to 80-acres across our three play areas. We've selected our first pure soft shale location and we drill a vertical well and take conventional core at the Atascosa County location this quarter. We're now planning on drilling our first horizontal well in the play prior to year-end. At Seal in Canada, we currently have three rigs drilling horizontal wells and a fourth rig drilling water source wells for our polymer injection project. We expect to drill and complete 78 wells at Seal this year.

Polymer injection on Phase I of our commercial polymer project began in August. We have just received regulatory approval for the cyclic steam project with steam injections scheduled for the fourth quarter of this year. Additionally, in July we submitted an application for vertical steam project scheduled to start in the second half of 2014. In Southern Alberta, Canada our initial well to 15-21 completed in the Three Forks zone has now been on production for over 300 days and is still achieving rates near 200-barrels a day. We've spud an offset well to this location on October 16. Depending on appraisal success we plan to drill additional wells there next year.

As to production, the third quarter averaged 181,558-barrel oil equivalent per day missing guidance of 183,000 per day due to impacts of Hurricane Isaac in the Gulf. We were fortunate to not sustain any significant damage to our facilities but we're slow in coming back on production due to delays in the start up of third party Downstream facilities. The actual amount of loss production for the quarter due to the hurricane was 2,900 BOE per day so we were able to make up some of the shortfall with better than planned production from other operating areas. We are maintaining our 2012 annual production guidance of 193,000-barrel equivalent per day with production guidance for this quarter of 207,000-barrel equivalent a day. A significant ramp up of production will come from additional Kikeh wells just mentioned, the new subsea wells flowing from Kakup, additional wells at Eagle Ford and Seal, as well as Terra Nova, which has returned to production this month after a long period of planned down time. I'll now turn it back over to Steve.

The US Downstream business operated well in a tough market of rising wholesale gasoline prices. Overall, in the US Downstream third quarter net income was $17.3 million. We added 12 new stations to the US retail chain in the quarter, and today, our total station count is 1,154 with plans to end the year at 1,165, and we'll have 10 stations that sort of flop over into 2013. The UK Downstream business provided a positive contribution for the quarter and for the first nine months in an environment of strong refining margins, and the UK retail business continued its steady performance.

Now, looking to 2013, while we're still in the middle of our budgeting process, our budget gets approved in the December Board meeting, I see us maintaining our production target for 2013 of about 200,000 BOEs per day, but we'll have more details on that at the fourth quarter call in January. In summary, we drilled two successful wells, one in Block H Malaysia and the Dalmatian South well in the Gulf of Mexico. Our exploration program continues in the fourth quarter with the well offshore Congo and one offshore Australia. Development work is moving forward on our offshore Malaysian projects and the Eagle Ford Shale continues to show predictable production increases. We added acreage positions in two exploration focus areas, Australia and Vietnam, and as part of a continued review of our portfolio we've decided to sell our UK Upstream assets. We'll continue the sales process of our UK Downstream business. And lastly, we're continuing to execute on our plan to spinoff our US Downstream business. With that, we'll open it up for questions.

Thank you.

(Operator Instructions)

Blake Fernandez, Howard Weil.

Guys, good afternoon. A question for you on the UK sale, the Upstream sale. Obviously, this wasn't part of the conversation when you recently came out suggesting you were hiring bankers to evaluate Sin crude and Montney. Should we take from this maybe an increased appetite to maybe move ahead with some Upstream sales?

I don't think so, Blake. This sale at UK has been under way for a long time. We just weren't able to disclose it until now.

Okay. On the buyback front, I know we have a $1 billion authorization. Can you say whether that program has begun yet?

Well, obviously work on it has begun but we're constrained from executing stock purchases in the blackout period, run up to earnings announcements, so we haven't really done anything yet.

Right, okay, that's true. The last one I had for you is on the retail. Steve, I know in the past you were evaluating some of the performance, it seems like you were addressing that. I'm just curious this quarter's performance, obviously we had weaker benchmarks across-the-board, but I'm just curious, is there any underlying improvement that you've seen, whether it be market share gain or anything like that?

Yes, we have. Let me say we've had, I think I mentioned at the last call, that we had teamed up with a leading consulting firm to help us understand some of those under performance issues, and when we got their recommendation, started implementing in August, but as I noted earlier, it's a pretty tough wholesale gasoline market. We started seeing results though in some of the steps we took toward the end of September and I have to say now, looking at it currently, it's -- we're showing really significant increases, so we're pretty buoyed and pretty happy about it.

Okay, that's great. I'll hop off and let someone else have a chance, thanks.

Leo Mariani, RBC Capital Markets.

Hi guys. Just a question on Seal. Just looking at the numbers it looks like the production has been down like three quarters in a row there. Has there been any kind of maintenance or anything, and when will we expect to see some growth? I know you guys are running through rigs out there.

Yes, we got real behind, Leo, this is Roger. We got real behind on our rigs due to the extended breakup period there and really hit our stride. We've increased production just this month about 600-barrels a day net just in the month of October. There was a shut in of a Penn West facility, a gas handling facility that drove us into a shut down back to Upstream to us, so that's why we didn't have an increase this quarter was from a planned shut in there. But we see a pretty good build this quarter there of probably 1,000 barrels a day, and like I said, well on our way through this month of having that.

Okay, and where do we think Seal can go to as we get into 2013?

Well, we see next year, Barry, do you have the number for Seal next year? I'd say in the mid 7,500s this time. We have a lot of these projects going on with vertical steam drive and cyclic steam that could really help increase production down the line. We see a long term business there hopefully in the 20,000 range, going to stay with it way out in our long range plan. But I would say next year just a nobel small gain there as we build up these new pilot areas. But over long haul, this is a focus area for us for sure, Lea.

Got you, okay. Question on the US retail. Obviously margins were down pretty significantly here in the third quarter. Trying to get a sense of where those margins have sort of gone here in October.

They've widened. They really have. Let me just leave it at that.

Okay, widened as improved considerably for you guys?

Yes.

Okay, got you, and can you give us a little more color around Vietnam? You talked about how you thought it was an under exploited area kind of like when you got into Malaysia. Can you give us any details on sort of size of potential targets out there, have you identified targets you might drill and when we would expect to see a well possibly get spud out there? Is there seismic, just any kind of more color you have around your recent Vietnam deal would be helpful.

Sure, Leo. One clarification, Seal for next year we have probably in the 8,000 range, I misspoke at 7,000. As far as Vietnam, very under explored area, very large acreage position. If you look back to Malaysia, we went into that area with a shallow water and deepwater focus, meaning we would have the lower risk shallow water blocks accompanied by the deepwater riskier blocks. In the deepwater there we see a lot of 2D seismic and very large structures, very large stratigraphic trap features, but a long way to go to get to 3D ready status, but very, very large blocks, probably the same acreage we had in Malaysia.

We of course want to have other awards there. We find it going a little bit slow in getting to final PSE signature there, quite frankly, but continuing to progress both a shallow water and a deepwater focus. In the shallow water blocks there is previous discoveries that are there, similar to what was in Malaysia before where you can delineate off those and add in small oil accumulations in cluster environment. So all-in all we see it to be a mirror image of that but greatly under explored now with a big upside as to 3D and to structures down the road. I would say probably late '14, '15 sort of drilling time there.

Got you, okay. Just jumping over to Congo. I guess it's an area where you haven't sold any oil for the past couple quarters. When will we expect that to start to get back up and moving?

We do not have a low level of production there. Of course that's been a very troubled asset for us, we're making about 4,000 net barrels a day with a big old ship and we won't have a sale there until early '13 because we have other parties there, partners in government who take their share along the way of a pretty poor performing asset.

Got you, okay. You guys also discussed a bolt on acquisition that you're working on here to get done by the end of the year. Is that like a US asset? Could you give us just any color on sort of approximately where that might be?

It's North America, we're always constantly looking at our North American positions there, not a gas one but an oil and just not at liberty to talk about it today.

All right, thanks guys.

Evan Calio, Morgan Stanley.

Hi, good afternoon guys and good quarter. My first question is on Kikeh. I know you gave the number of wells that you plan to bring online in Q4 yet, are there any wells still to be brought online in 2013, and can you give just a year-end exit rate?

We don't really go into exit rate. Our December rate there is a gross number, it would be in the mid I believe it's mid 70s right now, and we're ahead of that today. As far as wells this quarter, we have four already flowing with what I mentioned of the five and next year, we'll have that ongoing program there in our platform rig, but our floating rig will off at Seacap North, another project we have nearby so we're probably over next year. What we have at Kikeh is an ongoing business there of replacing wells that have this older completion, which we have very few of those left, and we have wells where we accelerating, where reservoirs have flowed longer than they originally planned and finishing up our original field development plan work. So among workovers, recompletion, side tracks and wells to keep the platform rig going, I don't have it off the top of my head, but I would imagine about five to six wells next year, and it'll sort of keep the decline at bay hopefully in that project.

And maybe you could help me with the PSE, because I know that you've increased capital spending related to recompletions. At current oil prices when would you expect any material production impact post cost recovery within those PSCs? I guess I'm just looking at the 207,000 in the fourth quarter with I guess a 200,000-barrel a day which you tentatively talked about guidance wise to understand where the drop off is in the portfolio other than asset sales obviously.

Lots of things there, Evan. Just hang on a second. As to the changes in production from the end of the year to next year, we've got to keep in mind that in the third quarter alone, we had 300 shut in days of turnarounds on 6 facilities and 2 shut in periods at Kikeh. Next year, we'll have turnarounds and shut ins again, it's typically not very often happening in the winter, so we will cross into that. That's where you get from the 207,000 to the 200,000.

Okay.

And your question on Kikeh, I'm sorry? I don't recall.

Yes, just you increased capital spending related to recompletion so I'm trying to understand--

I'm sorry. We're under cost current there and we're recovering our cost through our PSC. We don't see a significant change in entitlement in the Block K area until probably 2018.

Okay, that's good enough. I have one other question on taxes if I could. I know there's a big, if you could discuss the bigger driver in the increase in deferred taxes in the quarter. And then secondly, in 2013 following disposition of US retail and UK refining, would you expect to avail more preferential tax expensing of IDRs as not being an integrated Company? I'll leave it at that.

Evan, this is Kevin. The deferred taxes in the third quarter related to the timing of drilling and spend in Eagle Ford and in the Gulf of Mexico so it's all US driven.

Yes.

Nothing unusual. It's just the timing. As far as next year, once we become a 100% pure E&P Company we'll be entitled to 100% of IDC instead of 70%.

Yes, good, just confirm. Thanks guys.

Okay.

Pavel Molchanov, Raymond James.

Hi guys. A couple about your exploration program. As you think about it on a year-to-date basis, what is your success rate, specifically in exploration?

Hang on one second. On this year, we have been successful at DC134 in the Gulf of Mexico. We have a dry hole in Kurdistan, we've been successful at three wells in Block H Malaysia, and we had a dry hole at Block P in Malaysia, and two successful wells at small working interest offshore Brunei. I don't know that percent but pretty high.

So five out of seven or something like that, and so it's obviously higher up front relative to 2011, would you agree?

That's correct. Much higher.

And as we look at exploration expense, which is down about 30% from a year ago, how much of that relates to lower interests in the exploration wells, and how much of that is a function of higher success rates, fewer write-offs?

We have really big spend coming at this time. We have a big well going on at MPN, we have to drill additional well at Block H in Malaysia, and we have some other international wells. We have a good bit of dry hole in this quarter so I think we'll get our spending up in the 200 plus range that we normally have. You'll see that as the year folds out at our next call.

Okay, and for next year, would you expect to maintain the current pace of exploration drilling or would you try to curtail that?

We're going to try to maintain it and keep the 10 well program and anticipate the spending to be similar.

Okay, appreciate it guys.

Thank you.

Guy Baber, Simons & Company.

Hi, Guy Baber with Simons, good afternoon guys. In light of your plans to strategically review your sin crude and Montney assets, just had a conceptual question here around your targeted reserve life for your portfolio, but currently proven reserve life is a little over eight years and a potential divestment of sin crude and Montney would obviously be dilutive to that. So can you just talk a little bit more about internal reserve life targets and the road map you see over the next couple of years for reserve growth above production and potential adds at some of your major areas?

Thank you, Guy. This is Roger. We, as you say are near an 8, sales have dropped into the 5.7 range, if you did both of them it would be quite significant. We outside of that want to target our sales being up in the 8 to10 range. And in our long range plan, without those significant sales, we would see that taking place, a place like Eagle Ford sail with well over 300 million-barrels net to us, and only 45 million booked, we continue to book at Kikeh every year, we have a very strong position of booking at SK Gas. So we've rode up here with some of the highest production levels in industry, so that's pulled us back a bit on all of it but over our long range plan, unless we do a divestiture in Canada of major assets, we see ourselves at the eight plus range over the planning period. And I consider decent shape with the level of production we have.

Okay, great and then I had a follow-up on the Eagle Ford. I think you mentioned the 30,000-barrel a day target or expectation for 2013, and it looks stronger than the previous guidance we have which is around 25,000. So do we have those numbers correct first? And then if so, can you talk a little bit more about the upgrade to production there, what the primary improvements revolve around? And then also could you maybe just conceptually talk around potential upside to some of your long term Eagle Ford projections you gave at the May Analyst Day earlier this year, maybe what's changed since then?

If you go back to that number it was probably lower. That's just a basis of going through our business and having another year of business there. We continue to do very well in the drilling, like most operators there, a 20% increase, we're able to drill the wells, we're in all pad drilling now, we're putting more wells online per quarter, if you look through our quarterly information it's continued to do well. I think it's just a matter of getting into the detail of drilling improving, pad drilling improving, EUR improving, and just a real solid.

While we have rigs now if you look back at the exact detail we had some new rigs we got late and that we ended up really this year with only an average of eight so it's a matter of better drilling, better EUR, and more completions per quarter. And just really into the detail after having a real good quarter of a big build behind us is the reason. As far as the long term there, of course, pure soft shale, we're in the middle of that area, other operators are ahead of us a bit, because we continue to protect the acreage that we have of course. We look for that to be growth and of course you see Buddha shale and other, Wilcox and other formations across the Eagle Ford down the road, and also I would assume further down spacing. We have delved off into 80-acres everywhere but of course other operators are talking 40 and that would be an additional upside. We probably won't show all that to our Annual Meeting in May which will have a lot of detail about the other additional things to happen to that long term profile, but obviously Eagle Ford is a place we're very happy with, very consistent, predictable growth. It's a place that allows us to add more wells and help with production guidance, and it's doing very well and we're very happy with it.

Great, very helpful, thanks.

Kashif Malik, Credit Suisse.

Yes, hi. Thanks for taking my call. Can you give us an update on your recent conversations with Moody's and just broadly speaking how you view your investment grade ratings? And also if you had any conversations with Fitch over the last couple of weeks, thank you.

Sure, this is Kevin. We are in discussions with all of the rating agencies. As we mentioned, the initiatives that we have will be funded primarily with some additional debt and so we are currently in negotiation, I say negotiations, wrong word, discussions with the rating agencies, and I don't want to get ahead of that. We're meeting with some of them next week. As far as the investment grade ratings, we would certainly like to keep the investment grade ratings, certainly it helps with raising the money, certainly at the times when you have like in 2008, when we had the credit crisis, it just makes your access a lot better, so we certainly like to keep the investment grade ratings. When we went into these initiatives, we knew we would be pushing the envelope as relative to debt to total cap, relative to some of our peers, but we certainly didn't think it was going to be an issue.

Okay, and Kevin, can you just give us some color in terms of, based on the conversations you've had, what Murphy has to do to keep the investment grade ratings as far as the rating agencies are concerned?

I guess you'd have to ask the rating agency. As far as we're concerned we're doing what we have to do to keep the investment grade ratings.

Okay, thanks.

Arjun Murti, Goldman Sachs.

Thank you very much. Just wanted to follow-up I think it might have been Roger's comments regarding some of the completion issues at Kikeh being behind you. If we look at the longer term outlook, I think before you had these issues we would have thought Kikeh would have been entering as kind of longer term decline after several years of plateau but you've now had a couple years of lower production. I'm just wondering if that bodes better for volumes over the next couple years or if you could maybe have updated outlook for Kikeh growth or net production over the next two or three years it would be great, thank you.

For the ability of the field, we see it to be similar and we'll probably I want to get through this build up in December and get into our January budget and talk about the timing we have of Seacap coming on and Block K in general but I do see a pretty good situation there through '13 and '14 and moving in there, Arjun. I do not see a big worry about the field in any way and its been performing probably a little better than we thought of late. I just feel real comfortable about where we are. If you want to talk about wells at risk and all of the completions of an 80,000 gross number, 62,000 is from new completions today. So we hardly have any production at risk anymore and our sand production issues are well in check compared to a few months ago, and just in pretty good shape at Kikeh long term. We will get back on a plateau drop in the outer years as you would anticipate, and those fields flowed for five years on August 17, so all-in-all I don't see a big worry with Kikeh and would prefer to get into the '13, '14 production when we talk about our budget further in January.

No, I appreciate that. It does sound like though that at least you should be able to maintain this production for longer than you might otherwise would have given that it wasn't producing at where it should--

Oh, yes, if you go back to '11, we had some really difficult issues with these completions and its been flat now for almost three quarters in a row, so we're doing pretty well there.

And is the 80 where it's going to be, or is there still more stuff to come on and you can end up higher than the 80?

When you get to 80, you constantly have decline in a field that's old and I don't see us getting above 80 for long periods of time. And then we have what we still have wells that come off line and wells that are planned to come off line as we replace them with timing, so in general, it's going to be hard to hold the 80s, but I would say when the facilities not have a tie in of another facility or something going on to it, it has an ability to be a 70 player next year for a lot of the months.

That's great and if I'm repeating an earlier question I apologize, but do you have total production Company thoughts for 2013 at this point?

Yes, we maintain our 200 that we've said in May and our current draft of the budget is holding up with all that we had going on buying, selling, et cetera.

That's great, thank you so much.

Thank you.

John Herrlin, Societe Generale.

Yes, hi. Just a quick one for me. You said you want to maintain your exploration exposure on kind of a dollar basis in terms of wells drilled. What about your risk profile? Are you going to stay high risk as you are losing free cash from some of the other businesses you're spinning out.

What I see is a, what we're trying to get at every year is a 10 well consistent program that's primarily offshore driven in four areas, the Gulf of Mexico, Atlantic margin, Southeast Asia, Australia. We want to get to a point to have a bigger portfolio which we will do see in '14 and '15 and get that mixture in to some lower risk opportunities such as the Block H gas where we've been very successful, shallow water Malaysia where we've been very successful. Gulf of Mexico amplitude oil plays where we've been very successful, so we're going to blend that in a mixture of a big 300 million barrel swings along with the smaller, and it's my goal to have a profile across that paradigm and not be all the big swings and have the high risk. On occasion, with rigs and things line up, in a business like this those things line up and have some dry hole risk more quarters than others, but our goal is to try to have a total yearly program of some lower risk blended in with the higher risk.

That sounds good. What about a capital split? Would that be even as well or more skewed to Asia?

I'm sorry the question again please, sir?

What about the capital split? Will it be kind of geographically distributed?

I would say, I haven't thought about it in that way but I'd say it's fairly evenly split. Next year a little more Gulf of Mexico than in the past.

Thank you.

Thank you.

Paul Cheng, Barclays.

Hi guys, good morning. Or good afternoon. A number of questions. Roger, can you remind me on the PSE terms or TKI, I believe the initial profit split is 80/20 and then you will move to 50/50 when you recover 300 million-barrel, so how many barrels that you already recovered at this point? Well first of all is my understanding correct?

Yes, you're exactly correct. There's a 300 million-barrel threshold in Block K and for the whole block and today we've recovered around 100 million barrels I believe, and the field's probably recovered 150 million, so no the field's cover 150 million, we net 100 million, so the total--

Right but the 300 million is for the total block for you?

We see that hitting in for the block, Paul in 2018.

And Roger, when Seacap come on stream because Seacap is actually at least partly in Block 3, how is that going to become?

How is it going to be I'm sorry?

How is that going to be-- Oh, it's a Block K development, it's totally, all the wells are in Block K, all the partners are in Block K. It's flowing into our facility starting hopefully this month. And all of that production would come in split through the partners, and go through the total PSC for the Block K so each partner will have his own Block K spending profile. We have ours, the other partners have theirs. We'll net the barrels and go through the calculation that way. But that will become in the 300 million barrel also, is it?

That's correct. All of Block K production counts, Seacap North, Kikeh and the Kakup.

I see, and if I'm looking at your exploration program over the last 10 years, Roger, do you have maybe a number you can share if we exclude Kikeh, because that will clearly, by itself will pay for all of the last 10 years of the exploration expense. Are you going to exclude that? What kind of internal rate of return for the remaining of your program has been, any kind of rough idea?

I don't know. I don't have that number, Paul. I look at many things all the time but I don't have that. If you look at a 10 year period by a very comprehensive study, you'd find that Murphy over the long haul is one of the top quartile, probably second place of all of the explorers, which means that is the power of one and when you start excluding Kikeh, that's really unfair. It's one of the big winners that we have and that's why we're out exploring to have that one other hit and I believe we will do that, so over, but I do know for the Gulf of Mexico for example, I did calculate it there. We have full cost all-in rate of return of 13% across all of our Gulf business, which would be an example of big exploration and discoveries.

So Gulf of Mexico is about 13%?

Yes. So I haven't calculated it globally. But overall if you look at the Wood Mac study we would be top quartile over the long haul and over the short period of five years we, being even as poor as we've been, are still in the middle of the pack. So I feel good about the benchmarking while I may not be happy with the result of late, it's a long term program of consistent drilling of low and high risk opportunity. If we stay with it we will be successful.

On the UK sales for the $300 million for Schiehallion, is that just for Schiehallion or is it including everything else?

No, it would be all of the fields combined and we are unable to say the split out, Paul.

And is that going to result in any cash tax payment?

Kevin, can you help me on that?

No, it will not.

So you're going to receive $300 million in cash and net to you after-tax?

Subject to some post closing adjustments, yes.

Okay, all right, and I know that you guys were coming out with a new CapEx number for next year. Any kind of rough estimate, is that going to be pretty similar to what you put out in your May Analyst meeting for 2013?

Well I think it's fair to say that the number will be somewhat similar to what you see in 2012.

In 2012, the $4.4 billion?

If you look overall, that's considering a full year of downstream and you won't get that when we conclude the spin, but I don't know how many months you'll have, but it will probably be a little bit less than that, but it's in that ballpark.

Kevin, I just want to make sure when you say 2012, you're not talking about the regional budget, you're talking about your revised budget 2012 which is $4.4 billion so you're saying that next year--

In that ballpark.

In that ballpark but okay, I just wanted to make sure. That is about I think, is that $600 million higher than your Analyst meeting back in May?

Paul I'd have to go pull the slide to see.

Probably so, Paul. Sounds familiar.

And is there any particular area that the increase is going to be?

Paul, I don't want to go there until we get the budget approved.

Okay, that's fair. Roger, can you give us some data about the Eagle Ford operation? Can you share with us what is the unit cash operating cost in the third quarter and is the well costs you're talking about in the $7 million to $8 million a piece?

They're going to dig up the costs for you. Let me walk you through this a little bit, Paul. We're in several areas in Eagle Ford. We're about 8.3 million in Karnes all-in, 7.7 million in Tilden area and 6.5 million over in the Catarina, which is shallower, that would be our drilling and completion costs, and what was the number you asked for earlier, I'm sorry?

The cash operating costs.

Third quarter OpEx was 2581.

And do you expect that that is going to trend lower as you ramp up your production over the next several quarters or would that, is actually may not, it would take you a couple years.

I'm looking at it now and what we have in our long range plan today is in '13 to be $16, for 2014 to be $13, and kind of leveling off in the $12 range, that's been a little longer than we had hoped to get to that number because of rental equipment and drilling so many wells and the building of all of our facilities. But like I say we do see that number coming down in '13 and '14 as a big focus area for us.

Final one. In the Eagle Ford, what is the CapEx you expect to spend in this year and next year?

Well you always give us the same questions, Paul but hats off to you. I think this year we spent $1.3 billion and when you run 10 rigs and facilities, we probably spend pretty close to that again.

Thank you. Bye-bye.

Okay, thank you, Paul.

Jason Gilbert, Goldman Sachs.

Hi, guys, thanks for taking my question. You know the Company has historically run with very low leverage and you're clearly going to lever up here a bit as a result of the transactions you recently announced. Do you have a target leverage level for the Company over time?

This is Kevin. I would say in the 30% range, once it gets beyond that, we really start looking at it, like to be able to point to things that are going to be paying that down. Like I said, we do like to keep it conservative. We like to keep dry powder around for opportunities, so it would be in that range.

That's 30% debt-to-cap?

Yes, and part of that you can't, in our situation, it's hard to go by the exact number. You almost have to look at net debt because typically, I tend to have some cash overseas that I could bring back. I could bring back that debt number lower but I choose not to voluntarily in a lot of cases, because it's just tax inefficient. And so it's probably more fair to look at it from a net debt position.

And then just sort of a related question. I'm trying to figure out how much we should view the share repurchase and special dividend as a one-time event, or just a real change in financial policy since you haven't done this before. Is this the kind of thing we could expect to see again in the future?

I think for now, I would characterize it as a one-time event. I wouldn't want to foreclose it entirely for the future because who knows what happens in the future, but for now, it's a one-time event.

Okay, thank you very much.

Blake Fernandez, Howard Weil.

Guys I'm sorry to re prompt in. Just two points of clarification. Roger you mentioned the reallocation of cost from Block P over to K. Is it fair to assume that there will be no ongoing spending in P?

That's fair. We have the lease will be expiring in early '13, Blake.

Okay, great and then Steve, I was just curious, can you give us some kind of feel for how we're going to get communication on the asset divestiture evaluation process? In other words is there a time frame that we should think to hear something from you guys as to whether you're actually going to market these assets or not? And basically, let's just say you were to decide to pursue a sale, should we think we're just going to get a press release one day where you've sold it, or we're going to hear beforehand your decision?

Let me say that work is just under way and I don't want to prejudice it by putting it on a timetable. And as to sale or no sale, how we disclose that, let's leave that to the future and how this work unfolds.

Okay, fair enough. Thanks guys.

Gentlemen it appears we have no further questions at this time.

All right, well thank you very much, everyone, and thank you moderator. Thanks very much.

And this does conclude today's conference. We thank you all for your participation.