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Murphy Oil (NYSE:MUR)

Q2 2012 Earnings Call

August 02, 2012 1:00 pm ET

Executives

Steven A. Cossé - Chief Executive Officer, President, Director and Member of Environmental, Health & Safety Committee

Barry Jeffery - Director of Investor Relations

Kevin G. Fitzgerald - Chief Financial Officer and Executive Vice President

Roger W. Jenkins - Chief Operating Officer, Executive Vice President of Exploration & Production and President of Murphy Exploration & Production Company

Mindy K. West - Vice President and Treasurer

Analysts

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Evan Calio - Morgan Stanley, Research Division

Guy A. Baber - Simmons & Company International, Research Division

Paul Sankey - Deutsche Bank AG, Research Division

Arjun N. Murti - Goldman Sachs Group Inc., Research Division

Paul Y. Cheng - Barclays Capital, Research Division

Blake Fernandez - Howard Weil Incorporated, Research Division

Pavel Molchanov - Raymond James & Associates, Inc., Research Division

Raymond J. Deacon - Pritchard Capital Partners, LLC, Research Division

Raymond J. Deacon - Brean Murray, Carret & Co., LLC, Research Division

Mark Caruso

Operator

Good afternoon, and welcome to the Murphy Oil Corporation Second Quarter 2012 Earnings Conference Call. Today's event is being recorded. I'll turn the conference over to Mr. Steven Cossé, President and Chief Executive Officer.

Steven A. Cossé

Good afternoon, everyone and thank you for joining us in 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, who's our Senior VP and Controller; Mindy West, who's our Vice President and Treasurer; Barry Jeffery, Director of our Investor Relations; and Tammy Taylor, who's the Manager of Investor Relations. And Barry, you got some statement to make?

Barry Jeffery

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 obtained. 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 10-K filed with the SEC. Murphy takes no duty to publicly update or revise any of forward-looking statements. I'll now turn the call over to Kevin for his comments.

Kevin G. Fitzgerald

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 6 months ending June 30, 2012, our net income was $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 6-month period. However, the 2011 quarter did include $31.6 million at $0.16 per diluted share of income from discontinued operations related to the two U.S. 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 segments, 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 is 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 areas in British Columbia.

In the downstream segment, we have 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 was primarily attributable to operations in the U.K. 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 charges 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 in 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 our acreage in the Eagle Ford Shale or the drilling of our MPN prospect offshore in Republic of the Congo and an active lease acquisition program.

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

Steven A. Cossé

Thanks, Kevin. Before getting to operational matters, I'd like to emphasize that the recent management change here at Murphy was 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'll see in a little bit, we've got 4 big wells to spud here in the next 2 months, which is 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 at the Montney. Now we will also continue our efforts to divest the downstream in United Kingdom. It's been a very tough market, but we'll continue with those efforts.

In the United States, we regard our retail businesses 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's shareholders. And 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 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 get to operational update. Benchmark WTI prices averaged a little over $93 in the second quarter. Dated Brent, the marker for much of our production continued to outpace WTI, averaging near $100 for the quarter -- $108 for the quarter. In our latest outlook for the rest of the year, we're forecast $85 WTI and $100 Brent, which is in line with our original budget for the benchmark crude. 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 midterm, we continued to cut spending on our North American dry gas and moved capital to our oilier North American play. U.S. retail margins bounced back in the second quarter as crude and wholesale prices fell. The 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.

Roger W. Jenkins

Thanks, Steve. First in exploration today. Our 2012 exploration program is continuing on track for the year, with all of our wells being successful so far. We completed drilling of our Linnava exploration well on our Central Dohuk block, the Kurdistan region of Iraq and preparing to test the observed oil shows across 6 potential intervals, which total 278 meters of net pay in Jurassic and Triassic age of reservoirs. Over the next 6 weeks, we'll be conducting detailed core analysis and production testing. In the second quarter, drilling was completed on the Julong East sidetrack and the Jagus East 1 well in the CA-1 Block of Brunei. Each of these wells were discoveries. Last -- later this quarter, we'll spud the Opal [ph] Marine #1 well in the MPN block offshore Congo and test the 250 million barrels 10g [ph]carbonate target.

In the Gulf of Mexico, we plan to spud a Miocene amplitude test and the Dalmatian South prospect in DeSoto Canyon 134 in August.

In offshore Sabah, Malaysia this year, we anticipate drilling 3 additional exploration wells. We'll drill a Miocene-targeted structure on Block P and we'll drill 2 additional low-risk gas prospects as a follow-up on our 2 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 in recent placement of FEED awards. Rounding out this year's program internationally, [indiscernible] with #1 well in Block WA-423-P in the Browse Basin offshore Australia, which is scheduled to spud in early quarter 4. We're back to work in the Gulf of Mexico. Our board recently sanctioned the Dalmatian development. This project was sanctioned as a 40 million barrel equivalent resource, which will be developed at a 70% working interest and scheduled to have first oil in quarter 1 of 2014.

To develop this project and for our other exploration plans, we signed a long-term drilling contract or DP drillship. We're in the completion mode on a new well at Thunder Hawk, which should produce in September a rate of 8,400 barrels equivalent per day. Further in the Gulf of Mexico, we're successful in adding 14 blocks in the recent Central Gulf of Mexico lease sale, where we focused on Miocene amplitude plays, the Norfolk play in DeSoto Canyon and the subsalt Miocene play. Today, we're closing on the purchase on additional 25% working interest at our 2 Front Runner -- 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've been awarded as operator at Vietnam shallow water Block 11-2 in the Nam Con Son Basin at a 60% working interest with our partner, PetroVietnam.

We signed an MOU to form a new PFC, offshore Equatorial Guinea, at a 40% working interest as operator. We framed out 50% of our 100% working interest to Inpex in the AC/P36 block in the Browse Basin of Australia and planning on exploration well in the first half of next year. We've been awarded our first block in the Carnarvon 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 at 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're operating 10 rigs, 2 dedicated frac spreads and a call for a third crew and 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 flow back. In the latest outlook for the rest of the year, we expect to drill 149 wells and complete 123. We're currently producing near 16,000 equivalent net production, which is up from 11,500 the last time we had a conference call where we're 80% oil production in the [indiscernible]. We see our 2012 full year average near 15,000 BOE per day. We continue to see drilling record-setting improvements in fracs replacement. 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 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 break-up 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 add to approximated 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've received approval on our commercial polymer project with Phase 1 injection to commence in August. We received regulatory approval for our cyclic steam project, with steam injections scheduled for the fourth quarter of this year. Initially, in July, we're submitting application for our vertical steam drive projects 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 continue to focus on North America oil positions. Among the 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 and the well 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. The 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 downtime at Kikeh, Sarawak gas and Schiehallion in the U.K., 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 2, 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 downtime at Kikeh to pull in risers for some offsite production into our FPSO. These downfalls will be offset by production ramping up at Eagle Ford Shale, Syncrude and Thunder Hawk. We're maintaining our yearly production target of 193,000 barrels equivalent a day for the year. We see fourth quarter production growth in the range of 22,000 barrels per day will come from Kikeh with the addition of 6 new wells and less planned Kikeh downtime, continued ramp-up of Eagle Ford Shale, a new well, Thunder Hawk #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 3 and with planned maintenance at those facilities. We also have additional wells coming on at Seal and the early production flow from to our Kakap through our Kikeh FPSO vessel. I will now turn the call back over to Steve.

Steven A. Cossé

Thanks, Roger. Our U.S. downstream business rebounded in the second quarter, as U.S. retail margins improved in a falling wholesale price environment, averaging $0.197 per gallon for the quarter. Overall, the U.S. downstream second quarter net income was $73 million. We added 6 new stations in U.S. retail chains in the quarter and today our total station count is 1,142 and our plans are in the near at 1,175 outlets.

In renewable energy, our 2 ethanol plants at Hankinson, North Dakota and Hereford, Texas continue to operate reliably, but in a tough, tough market environment. Crush spreads remain 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. The U.K. downstream business provided a positive contribution for the quarter in the first half and improved margin environment with U.K. retail business continuing its steady performance. Retail margins benefited from improved market conditions associated with the recent idling of several Northwest European refineries.

And in summary, 2012 is moving forward on pace. The exploration programs are well underway, as I alluded to earlier, with our Linnava #1 well in the Kurdistan region of Iraq having reached total depth and has begun testing. We've got full -- we have important wells to drill in Congo, Australia, Gulf of Mexico and Malaysia, all to spud in the next month -- in this month or 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 U.S. retail and U.K. refining segments in the second quarter. Both the sales process for the U.K. downstream assets and the valuation of the U.S. retail business is ongoing. With that, I'll open it up for questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from Leo Mariani with RBC.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

I wonder 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 I guess just looking for the amount in terms of what you paid for that.

Roger W. Jenkins

Yes, it would include that. It's wrapped up in there, Leo. This is Roger. Today is the closing for that sale. I'm 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're comfortable with and the comparable price to that was something that was attractive to us. We executed that deal. To answer your question, the purchase of that is included in the roll-up of that additional CapEx.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

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

Roger W. Jenkins

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

Kevin G. Fitzgerald

That's an annual average number.

Roger W. Jenkins

An annual average number.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay, got you. And just in terms of Kikeh, all the workover is done this year?

Roger W. Jenkins

No, we'll continue on with the programs there. I mean, we're -- Kikeh, just to back up for a second, August 17 will be the fifth year of production there and 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 be -- have a new completion and that we'll be working there 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, Kikeh production is very flat without adding a well. And I think it's in good stand for our forecast that we have. We've maintained the forecast 2 calls in a row now at Kikeh.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

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

Steven A. Cossé

We're searching for that now.

Mindy K. West

If you just want to go on the net income basis -- and this is Mindy talking, the ethanol business for the second quarter lost approximately $3 million, which is a little bit above what -- 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 has had.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

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

Mindy K. West

That's correct.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay. And I guess in terms of the retail spin out, sounds like you guys are still going through a decision there. Do you have any kind of key factors in your mind or kind of 1 or 2 things that would lead you to move one way or the other on that?

Steven A. Cossé

Now before we get to the -- actually, before we get to the spin, no spin decision, you'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 we really need to understand that and address what -- why that is.

Operator

Our next question comes from Evan Calio with Morgan Stanley.

Evan Calio - Morgan Stanley, Research Division

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

Steven A. Cossé

Well, let me say, first of, yes, we did have margins, but we -- on a relative basis, we sort of underperformed the competition. We really did and while others were gaining volume and margin, we weren't and we need to understand that.

Evan Calio - Morgan Stanley, Research Division

I got you. And maybe also on the same kind of strategic side, I know it was regard 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 days. I mean is that still the plan as well as you see going forward?

Steven A. Cossé

Yes, I'm thinking we're always in the hunt for attractive oil and gas asset, I'll say that. So yes, that remains unchanged.

Evan Calio - Morgan Stanley, Research Division

Okay. Maybe just shifting to Canada. I know that you were reducing the spend in Canada in Tupper, yet your 2Q will volumes were flat. I thought you said 1 rig running. I mean was there a big, big well backlog? Or what am I kind of missing there?

Roger W. Jenkins

Well, we didn't start our curtailment of gas in Tupper West and Tupper until July 1. So we won't see that until next quarter. That's actually one in the third quarter that's last production. Our rigs in Canada today are at Seal. We do have a rig in Tupper drilling today because we have to move 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, the heavy oil asset.

Evan Calio - Morgan Stanley, Research Division

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 O&G exports, I mean, do you see any opportunity there to either participate on emerging or new or export LNG project or monetize your position for -- to someone who does?

Roger W. Jenkins

Right now, I wouldn't say we have an immediate plan of that, of course, we're taking back at some of the price recently paid for LNG and 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, the realization, where we're going to be on gas price and inability probably to invest in that business, we're more likely to take another look at that. Quite honestly, we're 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're looking for right now, but we could probably dovetail into another one over some period of time.

Operator

Our next question comes from Guy Baber with Simmons & Company.

Guy A. Baber - Simmons & Company International, Research Division

I had an exploration question on 2 of your potentially high impact prospects you're considering drilling later this year previously, and that's Cameroon and that's your hard-working interest block in Brunei. So can you share whether you have lined up the rigs? Do you need to drill these 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?

Roger W. Jenkins

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

Guy A. Baber - Simmons & Company International, Research Division

Yes.

Roger W. Jenkins

First, in MPN, we've had a -- we've solidified really on our rig schedule. We have the Ocean Confidence rig in Western Africa. It's coming to us. To drill a required well, we must real this year at in MPN and we'll go back to another operator. We'll hit that rig around a year from now probably and which we are going to drill somewhere in Cameroon. We have different opportunities there. MPN is one of those. We will go through our budget process to decide where we put that. It's quite a large prospect and the definitely significant side, if you will. As far as the Brunei CA-2, where we're 30% working interest, we should go back there at the real -- near the end of the year and we're drilling some prospects there that are being pulled out of a list. We have many partners there to work with, but we're not operator of that block, but we should get back in 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.

Guy A. Baber - Simmons & Company International, Research Division

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. But with a new CEO, I'm just wondering if the financial priorities for 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 kind of how you rank those.

Steven A. Cossé

This is Steve Cossé. We see no change in priorities. As you know, yesterday, we increased our dividend by $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?

Kevin G. Fitzgerald

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 -- the game that day. I mean, 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 follow 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 number for several years.

Operator

Our next question comes from Paul Sankey with Deutsche Bank.

Paul Sankey - Deutsche Bank AG, Research Division

Listening carefully, it seems that you're essentially reiterating everything that was said at the Analyst Meeting in May, which I guess had a 5-year outlook for Murphy as presented by David Wood. We were surprised by the resignation, but it seems to me that, if I understand what you're saying, including your targets for volumes this year, every other elements of what you outlined at that Analyst Meeting essentially you standby 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?

Steven A. Cossé

Yes, I think you summed it up very well.

Paul Sankey - Deutsche Bank AG, Research Division

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

Steven A. Cossé

Paul, I served at the discretion of the board and Mrs. Cossé and either have yet expressed any great dissatisfaction.

Paul Sankey - Deutsche Bank AG, Research Division

That's a very correct answer, Steve. So is there a time frame now that we can think about for the retail spin because it's actually one thing that's kind of different. Can you give us...

Steven A. Cossé

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

Operator

Our next question comes from Arjun Murti with Goldman Sachs.

Arjun N. Murti - Goldman Sachs Group Inc., Research Division

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?

Steven A. Cossé

Yes.

Arjun N. Murti - Goldman Sachs Group Inc., Research Division

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?

Steven A. Cossé

You're talking management change?

Arjun N. Murti - Goldman Sachs Group Inc., Research Division

In the management change, yes, sir.

Steven A. Cossé

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 event of any significance to be announced. And I really think, Arjun, it's more -- it's 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, "Hey, now is the time to change. Now is the time to part amicably and end it now before it got worse." So that's probably the best way I can express it. But again, I want to repeat that the management changes no -- absolutely no change in strategic direction.

Arjun N. Murti - Goldman Sachs Group Inc., Research Division

Appreciate the candor. Just 2 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?

Roger W. Jenkins

Yes, Arjun. This is Roger. That Analyst Meeting was my presentation and Paul a few minutes ago asked if that was where we're headed. I still assume that it is. Of course, we have to roll up our budget and we're ever mindful, Arjun, about your email on capital efficiency, and we'll 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.

Arjun N. Murti - Goldman Sachs Group Inc., Research Division

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?

Roger W. Jenkins

Kikeh is a very complicated field. We have 21 producing wells, 8 reservoirs. We've made 150 million barrels. We probably injected 200 million to 300 million barrels of water. It's going to reached, we think, around 75,000 gross at near year end and maintained that for some into '13 and then we'll need to reiterate with our budget, where that goes. We have a good handle though on the forecast. We've maintained the same forecast now for several months. We've had some operational problems on our 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'll 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. This is always an element of decline and I think to that nature as we get all these wells drilled. But I don't see anything going on in the operations of great concern, and we look to add a good bit of production here in the fourth quarter.

Arjun N. Murti - Goldman Sachs Group Inc., Research Division

And it sounds like there's nothing to really meaningfully change your estimate of the reserves there. It's more some of the operating issues in the oil field, that's natural, the declines, obviously.

Roger W. Jenkins

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

Operator

We'll take our next question from Paul Cheng with Barclays.

Paul Y. Cheng - Barclays Capital, Research Division

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

Roger W. Jenkins

Paul, this is Roger. I've heard your voice for many years but never spoken to you, looking forward to it. Kikeh today, we have 4 wells that have expandable sand screens in them. They're making a cumulative probably around 19,000 barrels of gross of oil. When water is projected to hit those wells at various tons, we feel that those wells could fail. So we're in there now drilling twins to those wells to ultimately replace them, as new wells and better take points for the reservoir, the next 2, if you will, of those producers.

Paul Y. Cheng - Barclays Capital, Research Division

So that means that, Roger, is that you learned from the last mistake, so we are not going to see all the 7 that you have, say, "Oh, I mean the production is down because the sand screen failed." So now that you are going to [indiscernible] on that by drilling the additional well already.

Roger W. Jenkins

Yes, that's true. I guess, the wells could fail now as we're in the middle of drilling the well [indiscernible]. A couple of them are more prolific than others. So naturally, we will replace the more prolific once first, right? So we're in the middle of doing that. We think we could still have a catastrophic failure there in the well and when we do it, it's hurtful to Murphy. But we're in a process of getting ahead of that and have 4 of those wells left and then we have some additional wells to complete our fuel development plan workovers, et cetera to any big major field with the ongoing multiple reservoirs and water injection that you'd find anywhere else in the world.

Paul Y. Cheng - Barclays Capital, Research Division

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

Roger W. Jenkins

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're across 4 plays. So we're in Karnes. We're in a field we call Tilden, Northfield and Catarina, all in oil focus. All those are different levels of depth, at Eagle Ford, different cost structure. I would say our wells -- we're 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 by 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 in new areas where we're drilling and if we build facilities, we remove the rental equipment. We think we're trending down the OpEx. It will get into next year after that to improve. All in all, our -- I guess the other questions on EUR. I would we're -- EUR IP was your question?

Paul Y. Cheng - Barclays Capital, Research Division

The 30-day IP.

Roger W. Jenkins

30-day IP in Karnes is probably 500 to 700 average for us. Let me turn it right here in just a second. I think we have the 4 fields. It's a lot to keep up with there. We're around, I would say, 300 to 400 in the Tilden area and 200 range in the Catarina area for 30-day IP. It'd be pretty normal. We really have pretty good performance there and the subsurface in the IP rates are really not a concern for us there.

Paul Y. Cheng - Barclays Capital, Research Division

Okay. And that 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 -- I mean, if we're 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 not to overspend by $1 billion. So how should we look at in terms of the company strategy? Do you really want to continue that trying to hit the growth target by overspend that dramatically or that you think you need to scale back your CapEx back to live more within your mean?

Steven A. Cossé

I think our projections show that if we fund our CapEx program over years, I don't think we get to a debt-to-cap ratio very, very high. It's very, very manageable and with our development projects and production coming onstream, it's -- it reduces over time fairly nicely. Kevin?

Kevin G. Fitzgerald

Yes, Paul, even with the -- what we're projecting for this year, we would end even with the 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. I hope we'll have some success there and then we'll start to develop those. We've had development projects, which the Eagle Ford itself could be considered a big development project. We run debt up into the low 30s before. So if you've got a good project to do, that's why we keep the balance sheet the way it is, we've got to take advantage of those opportunities. That being said, a lot of that monies being spent at Eagle Ford and most stuff winding down as we get out to '14 and '15.

Paul Y. Cheng - Barclays Capital, Research Division

So Kevin, should we assume that the 5-year trend you present in your Analyst Meeting in terms of the CapEx, those, say, in the $3.5 billion to $4.5 billion for the next couple of years that still is -- what do you guys have in mind at this point?

Kevin G. Fitzgerald

Well, at this stage, I think that the number that we showed at the Annual Meeting are probably a good go-by. But like Roger was mentioning, we're in the middle of a budgeting process and a new 5-year planning rollout where we're looking -- Roger mentioned signing up quite a few new concessions and PFCs in different areas. We got to see how that fits in all along as you go out 3, 4, 5 years and so we're rolling out that plan. We'll have a much better feel as we get into October and November of how that's playing out. Probably, on the next call, have a little bit more color we can add there. The thing to remember is in the Eagle Ford, the beauty of the resource play, as you know, is that you can ramp them up and ramp them down a lot easier than you can with some big projects like the Kikeh or these oil projects that we have in Malaysia. So 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.

Paul Y. Cheng - Barclays Capital, Research Division

And then 2 final questions. One is for Steve. Steve, on the U.K. downstream sales, is there a timeline that you will decide say, "Okay, it's not really going to happen, so we're going to turn it into a terminal" or yes, I mean, that the price is not good and then we're going to keep it running as an ongoing entity. Is there any timeline that you can share?

Steven A. Cossé

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

Paul Y. Cheng - Barclays Capital, Research Division

I see. And final one, maybe either it's Barry or Roger that you can -- 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?

Roger W. Jenkins

Okay. Quickly, Paul here, we've got third quarter U.S. 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 is about...

Paul Y. Cheng - Barclays Capital, Research Division

Can you breakdown the Canadian oil into offshore, heavy and Syncrude?

Roger W. Jenkins

Yes, heavy is about 7,000 oil. East Coast Canada Hibernia about 5,000 because turnover's on turnaround and sinker is about 14.5. Then we go to Malaysia, you've got 48.5 on oil, Kikeh, being about 42.5 of that. And you got Malaysia gas at about 202 million cubic feet with Sarawak being 155 of that. Those are the big ones.

Paul Y. Cheng - Barclays Capital, Research Division

And Congo?

Roger W. Jenkins

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

Paul Y. Cheng - Barclays Capital, Research Division

2,000. What's the corporate expense that you guys assumed in year EPS guidance?

Roger W. Jenkins

Corporate charge was $23 million.

Operator

[Operator Instructions] Our next question comes from Blake Fernandez with Howard Weil.

Blake Fernandez - Howard Weil Incorporated, Research Division

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

Steven A. Cossé

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

Blake Fernandez - Howard Weil Incorporated, Research Division

Okay. So it sounds like you're really in the initial stages of kind of evaluating that, all right. And then secondly, on the Kurdistan well, it's -- 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, I guess, 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?

Roger W. Jenkins

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 kind of walk through a stage of gross net pay start and you start hearing about cumulative tests among many reservoirs, and you ultimately get into oil in plays. This is the fractured carbonate Middle East-type reservoir, so it's -- if you notice, the other folks that are slightly ahead of us in the play, it's a good while to get to reserves, so it's going to be good a while to get to the reserves as well. Plus we need to float-test this well and have no oil back to surface in the float test. We're in the middle of running the perforated guns on the first one. It will be about 6 weeks there and I anticipated that it would be a slow March there where we go, as I said, to pay cumulative testing in the [indiscernible] oil in plays. I know these things to determine if we have a discovery to the size. 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're 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 a talk over the pipeline inside at KRG. But clearly, over time, those 2 regimes have to agree on a monetization until they do, won't be able to do so. We don't have this in our plan in any other growth plan that was shown. It's an exploration well and will remain so. The monetization is clear, but I still take a little solace in that 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 2 governments.

Operator

Our next question comes from Pavel Molchanov with Raymond James.

Pavel Molchanov - Raymond James & Associates, Inc., Research Division

One high-level one, if I may. You mentioned your new entry into Vietnam. By my count, that's country #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?

Roger W. Jenkins

No, not really. This is Roger. I thought it was ten, so you helped me out up to 11 there for me. We're a strong player in Southeast Asia, big office in Kuala Lumpur, also in Jakarta. We're used to working in that regions. We've been working there for a very long time to get these concessions. What we're trying to do in Vietnam is mimic, if you will, our success in Malaysia, but we start with the shallow water block and hopefully obtain some deepwater acreage and try to go into shallow deepwater like we were before. I don't see the country count getting much higher because we're 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.

Pavel Molchanov - Raymond James & Associates, Inc., Research Division

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

Roger W. Jenkins

No, some of them still have commitments wells here and there. And we usually -- if we have commitments, so you have to do the commitment stage and then make a decision on leaving the block in Suriname. We're shooting seismic there this year. We're excited about that block. It's a lot of interest from farming nearby. So we're active there and active in the other countries that you had up for me and happy to have them all, but it's not going into a much longer list than you prescribed.

Operator

Our next question comes from Ray Deacon with Brean Murray.

Raymond J. Deacon - Pritchard Capital Partners, LLC, Research Division

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.

Roger W. Jenkins

This is Roger, Ray. I would say that Karnes, of course, is one of the sweet spot of Eagle Ford. We are seeing some -- in Tilden, the way we described it, Tilden is quite big. We have a North Tilden which has a shallower Eagle Ford, so you have well of lower IP. We haven't -- still economic, of course, but we haven't drilled a lot of wells in that area, but if you talk about the need 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. We also have -- I mean, you have shallower Eagle Ford naturally. You drill the wells $0.5 million faster, and we're happy about expanding out of Karnes and we've been doing well away from Karnes and that's one of the areas we're focused. If you look at our rig plans for the rest of the year where we carried 10 rigs, we'll have 3 at Karnes, 2 out in Catarina West and the 5 rigs in Tilden. And so most stuff in there in a small area. That's heavily competitive area, competitors all around us. So I see it to be a very nice growth area for us and also an area that we have a higher working interest in Karnes.

Raymond J. Deacon - Brean Murray, Carret & Co., LLC, Research Division

Got it. And I guess 2 more quick ones. Do you see any opportunity to test the pure salt 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?

Roger W. Jenkins

Let me take the Seal first. We've done a polymer injection pilot and it's been very, very good. Now we're going with phasing in of 10 wells at a time and 20 wells in different phases. It will take maybe 8 or 9 months to see impact there, but it's doing very good in the pilot. Moving down to [indiscernible] back in the Eagle Ford, we do see opportunity for [indiscernible] players nearby [indiscernible] to have it. We may see another play there and we think we would have an opportunity to participate in it. We have planned next year working in [indiscernible]. This year, we going to try to drill the wells if we have enough time [indiscernible] for the time being.

Operator

The next question comes from Mark Caruso with Millenium Partners.

Mark Caruso

Steve, this question, more of a strategic question and a follow-up on the retail. One of the hurdles in the past when we talked about has been the cash flows and the dividend, and we've got a great dividend update last night and I want to kind of get your thoughts on that going forward. Is it better to keep everything integrated given the cash flows of retail? Can it be strong at times to help fund the dividend or can both entities pay dividends separately? And just want to see how that influences your thoughts.

Steven A. Cossé

Well, let me say, first of all, I wouldn't prejudge the -- if we do decide to spin, I wouldn't prejudge that spin codes board on dividends, but I think the -- our capability to continue our capital expenditure program post-spin as well as the dividend are eminently sustainable.

Operator

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

Steven A. Cossé

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 get better as we get on with the process. And once again, thank you all for participating. Thank you.

Operator

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

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