Murphy Oil Corp (MUR) 2012 Q2 法說會逐字稿

Good afternoon and welcome to the Murphy Oil Corporation's second-quarter 2012 earnings conference call. Today's event is being recorded. I'll turn the conference over to Mr. Steven Cosse, President and Chief Executive Officer.

Good afternoon, everyone, and thank you for joining us on our conference call today. With me here in El Dorado are Roger Jenkins, our Executive Vice President and Chief Operating Officer; Kevin Fitzgerald, our Executive Vice President and Chief Financial Officer; John Eckart, our Senior VP and Controller; Mindy West, who is our Vice President and Treasurer; Barry Jeffery, Director of our Investor Relations; and Tammy Taylor, Assistant Manager for Investor Relations. Barry, you've got some statement to make?

Thank you, Steve. Welcome, everyone. Today's call will follow our usual format. Kevin will begin by providing a review of second-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 that these events will occur or that the projections will be attained. A variety of factors exist that may cause actual results to differ. For a further discussion of risk factors see Murphy's 2011 annual report on Form 10-K 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 for his comments.

Thanks, Barry. Net income for the second quarter of 2012 was $295.4 million, or $1.52 per diluted share. This compares to net income in the second quarter of 2011 of $311.6 million, or $1.60 per diluted share. For the six months ending June 30, 2012, we had net income of $585.5 million, or $3.01 per diluted share compared to net income for the same period in 2011 of $580.5 million, or $2.98 per diluted share.

There were no unusual items of significance in the 2012 quarter or for the 2012 six-month period. However, the 2011 quarter did include $31.6 million, that's $0.16 per diluted share, of income from discontinued operations related to the two US refineries and associated marketing assets that were sold at the end of the third quarter of 2011. 2011 year-to-date results included income from those same discontinued operations of $62 million, or $0.32 per diluted share and an after-tax gain of $13.1 million, $0.07 per diluted share, from the sale of natural gas storage assets in Spain.

Looking at income by segment, in the E&P segment, net income for the second quarter of 2012 was $230.1 million compared to net income in the second quarter of 2011 of $243.3 million. Lower E&P earnings for the 2012 quarter were primarily due to lower crude oil and North American natural gas price realizations.

Crude oil and gas liquids production for the current quarter was approximately 104,000 barrels per day, as compared to approximately 94,200 barrels per day in the corresponding 2011 quarter. The increase mostly attributable to production at Kikeh and in the Eagle Ford shale area of South Texas.

Natural gas sales volumes averaged 507 million cubic feet per day in the second quarter of 2012, compared to 457 million cubic feet per day in the second quarter of last year. This increase was attributable to higher production at the Tupper West area in British Columbia.

In the downstream segment, we had net income from continuing operations in the second quarter of 2012 of $80.5 million compared to net income from continuing operations in the second quarter of last year of $60.1 million. The increase in the 2012 quarter is primarily attributable to operations in the UK where we experienced improved refining and retail margins.

In the corporate segment, second quarter 2012 saw a net charge of $15.2 million, compared to a net charge in the second quarter of last year of $23.4 million. The lower charge is related to favorable impacts on transactions denominated in foreign currencies and to a higher proportion of financing costs being capitalized to ongoing oil development projects offshore Malaysia.

Capital expenditures for 2012 are currently estimated at $4.1 billion. The increase over what was projected at the time of our annual meeting is mostly attributable to the sanction of the Dalmatian development in the Gulf of Mexico, no farm outs of any of our acreage in the Eagle Ford shale or of the drilling of our MPM prospect offshore Republic of Congo and an active leads acquisitions program.

As of June 30, 2012 Murphy's long-term debt amounted to just under $800 million, which is approximately 7.8% of total capital deployed. During the quarter, our existing $350 million 10-year bond matured, and was effectively replaced by a new $500 million 10-year bond due 2022. And with that I'll turn it back over to Steve.

Thanks, Kevin. Before we get into operational matters, I'd like to emphasize that the recent management change here at Murphy is a change in personnel only. It's not a change in strategic direction of the Company. We will continue our international exploration. And as you will see in a little bit, we've got four big wells to spud here in the next two months, so it's going to step up significantly.

We will continue our Gulf of Mexico exploration, where we were recently very successful at the lease sale. And that exploration program is going to be balanced by our continued development of our resource plays here in North America, particularly the Eagle Ford shale and, gas price permitting, the Montney. Now, we will also continue our efforts to divest of the downstream in the United Kingdom. It's been a very tough market, but we will continue those efforts.

In the United States, we regard our retail business as a very good business. However, the question remains whether it stays part of Murphy or whether it continues its growth as a standalone, held directly by Murphy shareholders. But that's the decision to be made. But before we get to that decision, I have to say that we have to understand and address some of its underperformance it's sustained here recently. We don't believe it's performing up to its capability. We need to understand that and address it, and that work continues.

With that, I'll skip to operational update. Benchmark WTI prices average a little over $93 in the second quarter. Dated Brent, the marker for much of our production, continued to outpace WTI, averaging near $108 for the quarter. In our latest outlook for the rest of the year, we're forecasting $85 WTI and $100 Brent, which is in line with our original budget for the benchmark crudes.

Natural gas prices in North America continue to be under pressure, with Henry Hub averaging $2.36 per MMbtu in the second quarter, although recently prices have shown improvement due to warm weather across much of the United States. With weak North American natural gas prices expected to continue over the mid term, we've continued to cut spending on our North American dry gas and move capital to our oilier North American plays.

US retail margins bounced back in the second quarter as crude and wholesale prices fell. And improved refining margins at Milford Haven provided a solid contribution from our downstream business for the quarter. Roger now will address the exploration production update.

Thanks, Steve. First an exploration update. Our 2012 exploration program is continuing on track for the year, with all of our wells being successful so far. We've completed drilling of our Linnava exploration well on our Central Dohuk block in the Kurdistan region of Iraq and are preparing to test observed oil shows across six potential intervals, which total 278 meters of net pay in Jurassic- and Triassic-age reservoirs. Over the next six weeks we'll be conducting detailed core analysis and production testing.

In the second quarter, drilling was completed on the Julong East side track and the Jagus East 1 well in the CA-1 block of Brunei. Each of these wells were discoveries. Later this quarter, we will spud the Opal Marine number 1 well in the MPN block offshore Congo to test a 250 million-barrel [singey] carbonate target. In the Gulf of Mexico, we plan to spud a Miocene amplitude test in the Dalmatian South prospect in DeSoto Canyon 134 in August.

In offshore Sabah, Malaysia, this year, we anticipate drilling three additional exploration wells. We'll drill a Miocene targeted structure on Block P. And we will drill two additional low-risk gas prospects as a follow-up on our two recent discoveries in the Rotan area of Block H, which is slated for floating LNG development. Petronas, the owner of the proposed floating LNG vessel, continues to progress the project with recent placement of feed awards.

Rounding out this year's program internationally will be the Eupheme number 1 well in Block WA-423-P in the Browse Basin offshore Australia, which is scheduled to spud early in quarter four. We are back to work in the Gulf of Mexico where our board recently sanctioned the Dalmation development. This project was sanctioned as a 40 million barrel equivalent resource, which will be developed at a 70% working interest. It's scheduled to have first oil in quarter one of 2014.

To develop this project and for our other exploration plans, we signed a long-term drilling contract for a DP drill ship. We are in the completion mode on a new well at Thunder Hawk, which should produce in September at a rate of 8400 barrels per equivalent per day. Further in the Gulf of Mexico, we were successful in adding 14 blocks in a recent central Gulf of Mexico lease sale where we focused on Miocene amplitude plays, the Norfolk play in DeSoto Canyon, and sub-salt Miocene plays.

Today we are closing on the purchase of an additional 25% working interest at our Front Runner and Thunder Hawk fields, bringing our working interest to 62.5% in each field. This will add approximately 2,100 barrels equivalent production for the year. In this development we've been very active in strengthening our global exploration portfolio. Recently we have been awarded as operator a Vietnam shallow water Block 11-2 in the Nam Con Son Basin, with a 60% working interest with our partner Petro Vietnam.

We signed an MOU to form a new PSC, offshore Equatorial Guinea, at a 40% working interest as operator. We farmed out 50% of our 100% working interest to Inpex in the AC/P36 block in the Browse Basin of Australia. And planning an exploration well in the first half of next year. We have been awarded our first block in the Canarvon Basin of Australia, WA-476-P at 100% working interest.

We continue to be very active in southeast Asia and West Africa where we hope to announce continued acreage entry in the near term. Unfortunately the initial exploration program of our Baranan Block in the Kurdistan region of Iraq has expired. It could not be extended as our partnership group was not able to spud a well by the lease expiration date. An application to extend the lease was not approved.

I'll now move into our North American onshore business. We have 14 rigs working today in North America; 10 in the Eagle Ford and 4 in Canada. In the Eagle Ford shale, we are operating 10 rigs, 2 dedicated frac spreads and a call for a third crew. We drilled 118 wells in the play this year to date, with 81 of those wells producing, and 37 wells in various stages of completion and/or flowback.

In our latest outlook for the rest of the year, we expect to drill 149 wells and complete 123. We are currently producing near 16,000 equivalent net production, which is up from 11,500 the last time we had a conference call where we were 80% oil production in the Eagle Ford. We see our 2012 full-year average near 15,000 BOE per day.

We continue to see drilling records set in improvements in fracture placement. We also see positive results from an 80-acre downspacing in the Karnes area following a 100-acre downspace plan. We're now moving to 80-acre downspacing in Tilden and Catarina. In the Seal heavy oil project in northern Alberta we will be adding a third rig in the area by mid-August and expect to drill a total of 71 production wells this year.

The prolonged breakup period prevented a number of wells planned for the first half of the year from being drilled on schedule. Regulatory delays, along with unseasonably wet weather, contributed to putting us behind our drilling schedule and production targets. Production for the year should average approximately 8,400 equivalent per day, which is around 2,000 below our forecast.

We continue to progress our EOR projects in Canada, as we work through the regulatory and stakeholder processes to achieve the necessary approvals. We have received approval on our commercial polymer project, with phase 1 injection to commence in August. We have received regulatory approval for a cyclic steam project, with steam injection scheduled for the fourth quarter of this year. Additionally, in July we submitted an application for a vertical steam drive project scheduled to start in the second half of 2014.

At Tupper and Tupper West we've implemented our plan to reduce capital spending in these assets. And we continue to focus on North America oil positions. Our Montney acreage is an excellent low-cost asset. However, we need price support to resume its growth trajectory.

In southern Alberta, we continue to see positive results from our first well completed in the Three Forks zone, with production rates of 280 barrels a day of light oil from a well that has now produced over 200 days. Our second Three Forks well has now been on production for more than 70 days and is producing near 100 barrels a day. A third well has been selected and will be drilled in the fourth quarter of this year. As we gain better understanding of the Three Forks reservoir and refine our completion techniques, we expect to continue seeing positive results in this play.

Moving down into our global production. Second quarter averaged 188,575 barrels a day, exceeding our guidance level of 185,000, primarily due to favorable production performance and less down time at Kikeh, Sarawak Gas, and [Shihaley] in the UK, offset by lower production from Seal.

Production guidance for the third quarter is 183,000 equivalent per day, down close to 5,500 barrels equivalent a day from quarter two, primarily due to the impact of production curtailments at Tupper and Tupper West, planned maintenance programs at Sarawak Gas and also Terra Nova. We also have down time at Kikeh to pull in risers for some off-site production into our FPSO. These downfalls will be offset by production ramping up at Eagle Ford shale, Syncrude and Thunder Hawk.

We are maintaining our yearly production target of 193,000 barrels equivalent a day for the year. Key fourth-quarter production growth in the range of 22,000 barrels per day will come from Kikeh, with the addition of six new wells.and less planned Kikeh down time, continued ramp-up of Eagle Ford shale, a new well at Thunder Hawk number 4 online for the full quarter, and our East Coast Canada projects, Terra Nova, and Hibernia, returning from long-term down periods in that quarter three and the planned maintenance at those facilities.

We also have additional wells coming on at Seal and the early production flow from Kakap through our PK FBSO vessel. I will now turn the call back over to Steve.

Thanks, Roger. Our US downstream business rebounded in the second quarter as US retail margins improved in a falling wholesale price environment, averaging $0.197 per gallon for the quarter. Overall, in the US downstream, second-quarter net income was $73 million. We added six new stations to the US retail chain in the quarter. And today our total station count is 1,142. And our plans are to end the year at 1,175 outlets.

In renewable energy, our two ethanol plants at Hankinson, North Dakota, and Hereford, Texas, continue to operate reliably but in a tough, tough market environment. Crush spreads remained in negative territory as corn prices climbed to near all-time highs due to drought conditions impacting the domestic crop. Cattle feed prices, however, continue to be strong in a rising corn market, and help us offset operating expenses.

UK downstream business provided a positive contribution for the quarter and the first half in an improved margin environment with UK retail business continuing its steady performance. Retail margins benefited from improved market conditions associated with the recent idling of several northwest European refineries.

In summary, 2012 is moving forward on pace. The exploration program is well underway, as I alluded to earlier, with our Linnava number 1 well in the Kurdistan region of Iraq having reached total depth, and has begun testing. We have important wells to drill in Congo, Australia, Gulf of Mexico and Malaysia all to spud in this month or the next. Second-quarter production exceeded guidance and we remain on track for the remainder of the year at 193 BOE per day.

Our Eagle Ford shale project continues to show strong production growth, and we'll continue to appraise our southern Alberta acreage. Our downstream business has benefited from improved margins in both the US retail and UK refining segments in the second quarter. Both the sales process in the UK downstream assets and evaluation of the US retail business is ongoing. With that, I will open it up for questions.

(Operator instructions). Leo Mariani with RBC.

I wondered if you could give us a little bit more color on the CapEx increase. You guys talked about moving higher to $4.1 billion. Does that include the Gulf of Mexico acquisition that you guys talked about there? And just looking for the amounts in terms of what you paid for that.

Yes, it would include that. It's wrapped up in there, Leo. This is Roger. Today is the closing for that sale and we're really not at liberty to talk about it. I would say that it's a situation where we are the operator there and it's approved reserves that we are comfortable with. And the comparable price to that was something that was attractive to us. And we executed that deal. To answer your question, the purchase of that is included in the roll-up of that additional CapEx.

Okay. And you guys talked about 2,700 barrels a day being added. Is that a number for the rest of the year or is that a full-year average? Any color you have around that would be helpful.

It must be a mistake. It may be on my part. It was 2,100 barrel equivalent a day additional, that's included in our guidance from that purchase. It's an annual average number.

Okay. Got you. And just in terms of Kikeh, all the workovers done this year?

No. We will continue on with the programs there. Kikeh, just to back up for a second, August 17 will be the fifth year of production there. So it's a long-term project for us. We have an ongoing program there of adding additional wells, working on wells that will one day need to have a new completion. And then we will be working that through all of next year, as well. So Kikeh, however, did have a good quarter. And the way I look at it, from call to call, the Kikeh production is very flat without adding a well. And I think it's in a good stand for our forecast that we have. And we have maintained the forecast two calls in a row now at Kikeh.

In your ethylene business, you talked about it being very challenged here in the second quarter, which hurt results. Can you quantify that in terms of a cash flow type of number in terms of how much you guys might have lost versus the previous quarter?

We are searching for that now.

If you just want to go on a net income basis -- and this is Mindy talking -- the ethanol business for the second quarter lost approximately $3 million, which is a little bit under what it lost in the fourth quarter where it lost between $4 million and $5 million. Fourth quarter was really the last good positive quarter it's had.

Got you. So it didn't really dramatically affect the sequential results, then, is what you all are saying. It's been similarly weak for a while.

That's correct.

Okay. And in terms of the retail spinouts, I think you guys are still going through a decision there. Is there any key factors in your mind, are there one or two things that would lead you to move one way or the other on that?

Before we get to it, actually before we get to the spin, no spin decision, we've got to understand this underperformance we saw in the first quarter. It improved in the second quarter, but still we felt like it's underperforming its capabilities and really need to understand that and address why that is.

Okay. Makes sense. Thanks.

Evan Calio with Morgan Stanley.

Good afternoon and welcome, Steve. Maybe just a follow-up on, on your last comment. I thought you had real strong margins in the quarter in retail. Could you help us understand what you think the operational issues might be that you're seeking to?

Let me say first off, yes, we did have margins. But on a relative basis, we underperformed the competition. We really did. And while others were gaining volume and margin, we weren't. And we need to understand that.

I got you. And maybe also on the same strategic side, I know with regard to the cash position, as well as other potential receipts from the downstream sale, I know there was originally an intent to look for attractive assets to acquire to further diversify the production base. Is that still the plan, as well, as you see it going forward?

Yes. I think we are always in the hunt for attractive oil and gas assets. I'll say that. So, yes, that remains unchanged.

Okay. Maybe just shifting to Canada. I know that you were reducing the spend in Canada in Tupper, yet 2Q volumes were flat. I thought you just had one rig running. Was there a big well backlog or what am I missing there?

We didn't start our curtailment of gas in Tupper West and Tupper until July 1. So we won't see that until the next quarter. That's actually why the third quarter has less production. Our rigs in Canada today are at Seal. We have a rig in Tupper drilling today because we have to do some downspace drilling before the wells deplete further. So we have some small activity in Tupper, but primarily our focus in Canada is in our Seal heavy oil asset.

Maybe just one last one, if I could. And it's related to Tupper. With more interest in securing gas in the Montney for potential LNG exports, do you see any opportunity there to either participate in an emerging or newer export LNG project or monetize your position to someone who does?

Right now I wouldn't say we have immediate plan of that. Of course we are taken back at some of the price recently paid for LNG in the recent acquisitions up there just northwest of us. I think as we go into this upcoming budget cycle and get ready for next year, a realization of where we are going to be on gas price and inability probably to invest in that business, we'll be more than likely to take another look at that. Quite honestly, we are just not the size or the perceived size of some of these acquisitions. We probably are bigger than we have on our books for that. But we need to look at that probably. But to be frank with you, Evan, I don't think we have the TCFs they are looking for right now but we could probably dovetail into another one over some period of time.

Right. Appreciate it. Thank you.

Guy Baber with Simmons & Company.

I had an exploration question on two of your potentially high-impact prospects you were considering drilling later this year previously. And that's Cameroon and at your higher working interest block in Brunei. But can you share whether you have lined up the rigs you need to drill those prospects? And should we still be thinking about those as 2012 spud dates? And then can you share any info on potential size of those early prospects you're targeting there?

This is Guy, right? I'm sorry, is that your name, Guy with Simmons?

Yes.

Yes, first in NTM we get solidified on our rig schedule. We have the Ocean Confidence rig in western Africa that's coming to us to drill a required well we must drill this year at MPN. It will go back to another operator. And we will get that rig around a year from now probably, and which we are going to drill somewhere in Cameroon. We have different opportunities there. NTM is one of those. We will go through our budget process to decide where we put that. It's quite a large prospect, definitely on the significant side, if you will.

As far as the Brunei CA-2 where we are 30% working interest, we should go back there near the end of the year and be drilling some prospects there that are being pulled out of a list. We have many partners there to work with. We are not the operator of that block. But we should get back in the drilling business at CA-2 right at the end of the year, with probably one well and probably a well next year there, as well.

Okay. Great. And then I had one more just on financial priorities. And I think you guys touched on this in the prepared remarks. But obviously you have a conservative balance sheet here, a lot of cash, a lot of liquidity. With a new CEO, I'm just wondering if the financial priorities for the cash and for the balance sheet have changed at all. And if you could just outline for us what the priorities are there, just with respect to excess cash. And maybe just touch on dividend, CapEx, acquisitions as a means to drive growth and how you rank those things.

This is Steve Cosse. We see no change in priorities. As you know, yesterday we increased our dividend about $0.15. We have a pretty hefty CapEx program in front of us. And I think that's going to pretty much keep us busy, as well as our cash flow and probably our cash, as well. Kevin, do you have anything to add?

No. I think what you have to keep in mind is that a lot of the cash we have on the balance sheet is in foreign locations. And it's there just because of tax efficiencies or inefficiencies, whatever is the game that day. We look at bringing that money back when it is tax efficient. Since we have a strong balance sheet, I'm not forced to bring that money back. I can always just borrow a little bit under the revolver or something like that. So it gives us a lot of flexibility and that will just continue. It's the same MO we've been operating under for several years.

Thanks, guys.

Paul Sankey with Deutsche Bank.

Listening carefully, it seems that you're essentially reiterating everything that was said at the analyst meeting in May, which had a five-year outlook for Murphy, as presented by David Wood. We were surprised by the resignation. But it seems to me, if I understand what you're saying, including your targets for volumes this year, every other element of what you outlined at that analyst meeting essentially you stand by, with the possible exception of the retail spin where you seem to be saying that the operational competitiveness of the business needs to be looked at harder before you can make a decision on that. Is that fair?

Yes, I think you have summed it up very well.

Okay. And Steve, for you, I believe you had previously retired. Is this a long-term position that you see yourself holding as CEO?

Paul, I serve at the discretion of the board and business [Ko-Sie]. And neither have yet expressed any great dissatisfaction.

That's a very correct answer, Steve. So is there a time frame now that we can think about for the retail spin? Because if that's the one thing that's different, can you give us parameters?

As you know, we've got some work to do to understand exactly this underperformance. And Paul, I'd really like to stay clear of a timetable that undoubtedly will be wrong. We'd like to proceed with our work, get it done, proceed to a decision on spin or no spin and then announce it.

Okay. All right. Thanks, Steve.

Arjun Murti with Goldman Sachs.

Thank you, Steve. Maybe just a little bit of a follow-up to the last question. So you're not interim CEO? The board is not actively looking for a replacement? We should think about you as the ongoing CEO for Murphy?

Yes, thank you.

And you mentioned the reiteration of the strategy. Is it operational execution, maybe it's the retail thing? Or is it just being more aggressive in pursuing things that sparked wanting to make a change here?

Are you talking the management change?

The management change, yes, sir.

Yes, let me address it this way. Let me tell you what it's not. It's not some great scandal that's going to break. There's no other shoe to drop, no other events of any significance to be announced. And I really think, Arjun, it's more just an accumulation of little things over time, probably communication being one. And I think both sides were astute enough to see the trend and where this was going and to realize that now is the time to change, now is the time to part amicably before it got worse. That's probably the best way I could express it. But again, I want to repeat that the management change is absolutely no change in strategic direction.

I appreciate the candor. Just two quick production-oriented questions. I think you basically reaffirmed the guidance going forward. Is that true for '13, '14, '15, the production numbers outlined in the analyst meeting?

Yes, Arjun. This is Roger. That analyst meeting was my presentation. And Paul a few minutes ago asked if that was where we are headed. I still assume it is. Of course, we have to roll up our budget. And we are ever mindful, Arjun, of all your e-mail on capital efficiency. And we will be looking into that and rolling up our budget and see if we can maintain that level of growth. I'm not worried about the subsurface or ability to get to the targets that were shown at the AGM meeting. But the pace of that, as you know, can go up and down, especially when you're an Eagle Ford player. And so overall that general direction is absolutely there. Same direction, same presentation that I gave. And we are in the middle of our budget for next year and rolling through that process, but in general heading in that direction.

I appreciate it. And then just very lastly, I know you addressed it in part in the prepared remarks. But just Kikeh, maybe where do you think production will level out once you're through all the workovers, et cetera? Where do you feel Kikeh ends up oil production?

Kikeh is a very complicated field. We have 21 producing wells, 8 reservoirs, we've made 150 million barrels, we probably injected 200 million or 300 million barrels of water. It's going to reach, we think, around 75,000 gross near year-end and maintain that for some into '13. And then we will need to reiterate with our budget where that goes. We have a good handle, though, on the forecasts. We have maintained the same forecasts now for several months. We've had some operational problems on a rig on our spar that was hurting getting the production higher. Those are getting better. Overall I think it's in good shape. But I don't think we will ever get Kikeh back to some 100,000 barrels a day and just let it ride for several years. I don't think that's where it's going because there's always an element of decline and things of that nature as we get all these wells drilled. But I don't see anything going on in the operations that's a grave concern. And we look to add a good bit of production here in the fourth quarter.

Thank you so much. It sounds like there's nothing to really meaningfully change your estimate of the reserves there. It's more some of the operating issues and oilfields have natural declines, obviously.

That's right. Yes, I would say that's a fair statement.

That's great. Thank you so much.

Paul Cheng with Barclays.

Several questions. On TK, have you guys already replaced all the sand screen?

Paul, this is Roger. I've heard your voice for many years but never spoken to you. Looking forward to it. TK today, we have four wells that have expandable sand screens in them. And they are making cumulative probably around 19,000 barrels gross of oil. When water is projected to hit those wells at various times we feel that those wells could fail. So we are in there now drilling twins to those wells to ultimately replace them as new wells and better take points for the reservoir next to, if you will, those producers.

That means, Roger, that you learned from the last mistake so we are not going to see all of a sudden that you have, say -- Oh, the production is down because that sand screen failed. So now that you are going to mitigate on that by drilling the additional well already.

Yes, that's true. I guess the wells could fail now as we are in the middle of drilling the well. A couple of them are more prolific than others. So naturally we replaced the more prolific ones first, right? So we are in the middle of doing that. We think we could still have a catastrophic failure there of a well. And when we do it's hurtful to Murphy. But we are in the process of getting ahead of that and have four of those wells left. Then we have some additional wells to complete our field development plan, workovers, et cetera, to any big major field with its ongoing multiple reservoirs and water injection that you'd find anywhere else in the world.

Okay, that's great. And, Roger, do you have an average 30-day IP run rate that you can share in Eagle Ford for the second quarter in the well course? As well as what is the unit cash operating cost that now you are running in Eagle Ford?

That's a lot of stuff there, Paul. Hang on there, just a second. In the Eagle Ford, one thing unique to Murphy is we are across four plays. We're in Karnes, we're in a field we call Tilden, North Tilden, Catarina, all in oil focus. All of those are different levels of depth of Eagle Ford, different cost structure. I would say our wells, we are drilling and completing wells around $8 million in Karnes, maybe $8.4 million there, $8 million in Tilden and in the $7 million range in Catarina. Our drilling costs have reduced about 14% this year. Our OpEx there is probably a little high, in the probably 20s, moving down long term into the 10s. We have a lot of rental equipment because we have a lot of expansion, new areas where we are drilling. And as we build facilities, we remove the rental equipment. And we think we are trending down the OpEx that will get into next year after that to improve. All in all, one of your other questions on EUR, I would say -- is EUR or IP was your question?

The 30-day IP.

30-day IP in Karnes is probably 500 to 700 average for us. Let me turn to that here in just a second since we have four fields. It's a lot to keep up with there. We are around, I would say, 300 to 400 in the Tilden area, and in the 200 range in the Catarina area for 30-day IPs, would be pretty normal. Really have pretty good performance there. The subsurface and the IP rates are really not a concern for us there.

Okay. And then maybe, I think it's both for Roger and Steve. This year with the $4.1 billion in the CapEx you overspend your cash flow, if we including the dividend you have to pay, more than $1 billion. Yes, you have a very strong balance sheet but how many years that you can continue that to overspend by $1 billion? So how should we look at in terms of the Company strategy that you really want to continue with that, trying to hit the growth target by overspend that dramatically? Or that you think you need to scale back your CapEx that you live more within your means?

I think our projections show that if we fund our CapEx program over the years, I don't think we get to debt to cap ratio very, very high. It's very, very manageable. And with our development projects and our production coming on stream, it reduces over time very, very nicely.

Yes, Paul, even with what we are projecting for this year, we would end, even with additional capital, we would end the year with a debt to total cap in the low teens. And then Roger has got a pretty aggressive exploration schedule. Hopefully we will have some success there. And then we will start to develop those. We've run debt --if we've have had development projects, which the Eagle Ford itself could be considered a big development project, we've run debt up into the low 30s before. So if you've got a good project to do -- and that's why we keep the balance sheet the way it is, to go ahead and take advantage of those opportunities. That being said, a lot of that money is being spent in the Eagle Ford, and that'll start winding down as we get out to '14 and '15.

So, Kevin, should we assume that the five-year plan, you present in your analyst meeting in terms of the CapEx, though, say, in the $3.5 billion to $4 billion for the next couple of years, that still is what you guys have in mind at this point?

At this stage I think the numbers that we showed at the annual meeting are probably a good go by. But like Roger was mentioning, we are in the middle of a budgeting process and a new five-year plan roll-out where we are looking. Roger mentioned signing up quite a few new concessions in PSC and different areas. We've got to see how that fits in on the longer, as you go out three, four, five years. And so we are rolling up that plan. We will have a much better feel as we get into October, November of how that's playing out. Probably on the next call we'll have a little bit more color we can add there. The thing to remember is, in the Eagle Ford, the beauty of the resource plays, as you know, is that you can ramp them up and ramp them down a lot easier than you can some big project like a Kikeh. When it's oil projects that we have in Malaysia, you just need to keep developing those. And if oil prices would diminish or something, you can scale back in the resource plays. So we have a lot of flexibility and that's the reason we keep that balance sheet the way it is.

And then two final questions. One is for Steve. Steve, on the UK downstream sales, is there a time line that you will decide, say, it's not really going to happen so we are going to turn it into a terminal. Or, yes, that the price is not good and that we are going to keep it running as an ongoing entity. Is there any time line that you can share?

There's no specific time line, Paul. As I've said earlier, it's a tough market to sell refine -- As Mr. Icahn noted here in the United States. But converting it to a terminal, I think, is probably the last thing we do. And as long as it's performing, the refinery is performing as it is now, with margins and not particularly a drag on earnings, I think we continue operating it until we do find a way to divest ourselves of it. But again, the terminal is probably the last thing we do.

I see. A final one, maybe either Barry or Roger, if you're kind enough to give us in terms of your third-quarter production guidance. Can you break out more in detail the oil and gas by regions? Thank you.

Okay. Quickly, Paul, here we've got third quarter US oil is about 28,000 barrels of oil a day and about 51 million cubic feet of gas. Canada is about 27,000 barrels of oil a day, 195 million gas. Malaysia --

Can you break down the Canadian oil into offshore, heavy and syncrude?

Yes, heavy is about 7,000 oil. East Coast Canada, Hibernia, about 5,000, because Terra Nova is on turnaround. And syncrude is about 14,500. Then we go to Malaysia, you've got 48,500 on oil, Kikeh being about 42,500 of that. And you got Malaysia gas at about 202 million cubic feet with Sarawak being 155 million of that. Those are the big ones.

And Congo?

Congo is like 2,000 barrels a day, Paul.

What's the corporate expense that you guys assumed in your EPS guidance?

Corporate charge was $23 million.

Thank you.

(Operator instructions). Blake Fernandez with Howard Weil.

Steve, welcome to the party. I hate to dig in too deep on the retail. I know you've covered the underperformance there. But I was hoping, I'm just trying to understand, is that more of a cost or operating issue or is it simply a function of losing market share which could be related to maybe a slowdown of foot traffic at Wal-Mart?

No. It can be all those things, probably. Until we do the work, it's hard to assess. I wish I could have some more clarity for you on that but I don't right now, but we hope to soon.

Okay. So it sounds like you're really in the initial stages of evaluating that? All right. And then, secondly, on the Kurdistan well, I understand it's early days. I know during your analyst day this seemed like one of the larger prospects. You gave quite a large range of anywhere from 100 to 1,500 million barrels. Can you give any color on the initial indications of where you may be falling in that range? And then maybe talk about when we might see first production and potential monetization of those barrels?

Blake, yes, I would say on a gross basis all those ranges are still accurate that we had at that time. You see a lot of news come out of wells there, up and down. I think you walk through a stage of gross net pay. And you start hearing about cumulative tests among many reservoirs. And you also want to get into oil in place. This is a fractured carbonate, Middle East type reservoir. So, if you notice by the other folks that are slightly ahead of us in the play, it's a good while to get to reserves. So we're going to be a good while getting to reserves, as well. Plus, we need to flow test this well and have no oil back to surface in the flow tests. We are in the middle of running the perforating guns on the first one. We will be about six weeks there. And I anticipate that it will be a slow march there where we go, as I said, through pay, through cumulative testing and hopefully oil in place, and those things, to determine if we have a discovery and onto the sizing.

The monetization there is a long-term issue that's political. You saw where KRG was off production for several months now. Today, they say they are going back on production into the Iraqi/Turkey pipeline system. There's a lot of discussion in KRG about pipelines to join that major pipeline that has a lot of capacity. There's also talk of a pipeline inside KRG. But clearly over time those two regimes have to agree on a monetization. Until they do, we won't be able to do so. We don't have this in our plan, in any of the growth plans that were shown. It's an exploration well and will remain so until monetization is clear. But I still take a little solace in that the super majors follow us in every day. So the insight of the large value and size of the structures, along with the ability to ultimately monetize it among these two governments.

Agreed. All right. Thanks. I'll leave it there. Thank you.

Pavel Molchanov with Raymond James.

One high level one, if I may. You mentioned your new entry into Vietnam. By my count, that's country number 11 for you outside North America. Do you have any concerns that you may be getting a little bit stretched too thin just in a geographical sense?

No, not really. This is Roger. Thanks for that. I thought it was 10, so you helped me out up to 11 there for me. We are a strong player in Southeast Asia. A big office in Kuala Lumpur. Offices in Jakarta. We are used to working in that region. We have been working there for a very long time to get these concessions. What we are trying to do in Vietnam is mimic, if you will, our success in Malaysia where we start with a shallow water block and hopefully attain some deep water acreage and try to go into shallow and deep water like we were before. I don't see the country count getting much higher because we are continuing to work in the same places. But it is right at the cusp of where we probably want to go. But I'm not concerned with adding a new country in that particular region.

Okay. And then of the countries that you currently have in the portfolio, you're obviously not drilling in all of them. Surinam, I think, comes to mind. Any of them that you are considering perhaps for an exit?

No. Some of them still have commitments at wells here and there. And we usually, if we have commitments, we go through the commitment stage and then make a decision on leaving the block. In Surinam, we are shooting seismic there this year. We are excited about that block. It's a lot of interest from farm-in nearby. So we are active there. And active in the other countries that you add up for me, and happy to have them all. But it's not going into a much longer list than you prescribed.

Appreciate it.

Ray Deacon with Brean Murray.

I was wondering if I could ask a question about the Eagle Ford and Tilden results, to date, and how you would compare returns to what you've seen in Karnes.

This is Roger, Ray. I would say that Karnes, of course, is one of the sweet spots of Eagle Ford. We are seeing some -- in Tilden the way we've described it, Tilden is quite big. We have a north Tilden which has a shallower Eagle Ford. So you have wells of lower IP. But still economic, of course. But we haven't drilled a lot of wells in that area. But if you talk about the meat of the Tilden area, which is near many of our competitors, I would say it has strong returns, as well, slightly subordinate to Karnes but in pretty good shape there. When you have shallower Eagle Ford, naturally, you drill the wells $0.5 million faster. And we are happy about expanding out of Karnes. And we have been doing well away from Karnes. That's one of the areas we're focusing. If you look at our rig plans for the rest of the year, where we carry 10 rigs we will have 3 at Karnes, 2 out in Catarina out west, and the 5 rigs in Tilden. And so most of them there in a small area that's in a heavily competitive area with competitors all around us. So I see it to be a very nice growth area for us and also an area we have a higher working interest in Karnes.

Got it. Two more quick ones. Do you see any opportunity to test the Pearsall on your acreage? Do you think it's present? And how long before you expect to see some signs of success on the polymer injection at Seal?

Let me take the Seal first. We have done a polymer injection pilot and it's been very, very good. Now we are going with the phasing in of 10 wells at a time and 20 wells in groups of phases. It will take maybe eight or nine months to do that, to see that impact there. But it's been very good in the pilot. Moving down to Pearsall, back into Eagle Ford, we do see opportunities with Pearsall shale having (inaudible) (technical difficulty). Careful of thousand acres. (technical difficulty) and players and nearby on the (technical difficulty) We'd be glad to have it. We may see another play there and we think we would have an opportunity to participate in it. We have a plan next year of working in the Pearsall. But this year we're going to try to drill the wells we have in our plan (technical difficulty) for the time being.

Thanks, Roger.

Mark Caruso with Millennium Partners.

Thanks for taking my question. This question is more of a strategic question and the follow-up on the retail. One of the hurdles in the past when we have talked about it has been the cash flows and the dividend. And we got a great dividend update last night. And I wanted to get your thoughts on that going forward. Is it better to keep everything integrated, given the cash flows of retail can be strong at times to help fund the dividends? Or can both entities pay a dividend separately. I just want to see how that influences your thoughts.\\54.03

Let me say, first of all, I wouldn't pre-judge. If we do decide to spin, I wouldn't pre-judge that to [spinco's] board on dividends. But I think our capability to continue our capital expenditure program post-spin, as well as the dividend, are eminently sustainable.

Thanks.

It appears there are no further questions at this time. I'd like to turn the conference over to Mr. Cosse for any additional or closing remarks.

Thank you very much, everyone, for participating in the conference call. As you may have detected, Roger and I are very, very new to this process and if we stumbled a bit please forgive us. I hope we'll will get better as we get on with the process. Once again, thank you all for participating, and that's it. Thank you.

That concludes today's conference. Thank you for your participation.