Murphy Oil Corp (MUR) 2013 Q1 法說會逐字稿

Good afternoon, ladies and gentlemen, and welcome to the Murphy Oil Corporation first quarter 2013 earnings conference call. Today's conference is being recorded. Now, I will turn the conference over to Mr. Steven Cosse, President and Chief Executive Officer. Please go ahead, Mr. Cosse.

Thank you and good afternoon everyone, and thanks for joining us on our call today.

With me here is Roger Jenkins, our Executive Vice President and Chief Operating Officer; Kevin Fitzgerald, our Executive Vice President and Chief Financial Officer; John Eckart, our Senior Vice President and Controller; Andrew Clyde, our President and CEO of the US Retail Business; Mindy West, Vice President and Treasurer; Barry Jeffery, Director of Investor Relations; and Tammy Taylor, Assistant Manager of Investor Relations.

Barry?

Thanks, Steve, and welcome everyone.

Today's call will follow our usual format. Kevin will begin by providing a review of first quarter 2013 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 further discussion of risk factors, see Murphy's 2012 annual report on Form 10-K filed with the SEC. Murphy takes no duty to publicly update or revise any forward-looking statements.

And now I'll turn the call over to Kevin.

Thanks, Barry.

Our net income in the first quarter of 2013 was $360.6 million or $1.88 per diluted share. This compares to the net income in the first quarter of 2012 of $290.1 million or $1.49 per diluted share. This year's first quarter included income from discontinued operations of $152.6 million or $0.80 per diluted share, compared to an income of $8.6 million or $0.05 per diluted share in 2012. The 2013 disc ops results related primarily to a gain on the sale of two E&P properties in the UK. So income from continuing operations in the first quarter of 2013 is $208 million or $1.08 per diluted share, compared to net income in the first quarter of last year of $281.5 million, $1.44 per diluted share. The decline in 2013 compared to 2012 was due primarily to higher expenses for exploration, administration, financing, and income taxes.

So looking at income by segment, in the E&P segment, net income from continuing operations the first quarter of this year was $231.9 million, compared to net income the first quarter of last year of $313 million. Lower E&P earnings for 2013 were primarily attributable to lower average crude oil and Sarawak natural gas sales prices, higher exploration expenses, and higher income taxes. The increase in effective tax rate is largely the result of incurring exploration and other expenses in certain foreign jurisdictions for which no income tax benefits are currently available. Crude oil condensate and gas liquids production for the quarter averaged approximately 127,000 barrels a day in 2013, compared to approximately 107,500 barrels a day in 2012. The increase being mostly attributable to volume growth in the Eagle Ford Shale. Natural gas volumes were approximately 450 million cubic feet per day in the first quarter of this year, compared to 525 million cubic feet per day in the 2012 quarter. This decrease was primarily due to lower production in a tougher area in British Columbia, and lower volumes from gas fields offshore Sarawak Malaysia due to planned maintenance down time.

In the downstream segment, we had net income in the first quarter of 2013 of $25.3 million, compared to a net loss in the first quarter of last year of $4.2 million. In the US, downstream operations recorded income of $29.4 million in the 2013 quarter, compared to a loss of $7.2 million in 2012, mostly as the result of higher fuel margins, advantage product supply acquisition costs, and RIN sales. US retail fuel margins averaged $0.039 per gallon higher in the current quarter. However, retail fuel sales volumes on a per store basis were down about 1.5% year over year. Merchandise margins for the 2013 quarter were also down slightly. UK downstream operations recorded a loss of $4.1 million in the current quarter, compared to income of $3 million last year. The decrease was largely due to weaker refining margins and downtime for planned maintenance at the Milford Haven refinery.

In the corporate segment we had net charges in the first quarter of this year of $49.2 million, compared to net charges in the first quarter of last year of $27.3 million. This unfavorable variance was mostly attributable to higher administrative costs and increased interest expense in the current quarter. At the end of the first quarter 2013, our long-term debt amounted to approximately $2.5 billion or 21.5% of total capital employed. Cash, cash equivalents, and short-term investments totaled a little over $1.3 billion as of March 31.

And with that, I'll turn it over to Steve.

Thanks, Kevin.

The first quarter of 2013 provided a solid start to the year with, as Kevin noted, $361 million of net income, of which $208 million is from continuing operations. Benchmark WTI prices averaged over $94 for the first quarter with Dated Brent and LLS each pricing over $112 and $114 per barrel respectively. I think it's important to note here that Dated Brent and LLS both serve as markers for nearly 70% of our crude oil sales. While North American dry natural gas is not a major portion of our upstream portfolio, we're pleased to see pricing showing signs of strength in March, as year on year storage levels decreased, with Henry Hub averaging near $3.50 for the quarter and even showing one year forward curve levels above the $4 mark. While this is positive news, we continue with our strategy of minimizing CapEx, lowering operating costs, and delineating the liquids rich areas in our Canadian market fields.

In US retail operations, fuel margins averaged $0.11 per gallon in the first quarter, with January and February struggling against rising wholesale prices, but rounding out nicely in March as we exit what is typically a weak shoulder season. In upstream business, we drilled and evaluated three wells with one success in the first quarter. We exceeded our production guidance for the first quarter, getting us off to a good operational start for the year. Now in the downstream, we continue to move forward with the spinoff of our US retail business, which we expect to complete the second half of this year.

Andrew Clyde, who I said earlier is President and CEO of Retail Business, and his team have focused efforts on all aspects of establishing a separate company to be prepared to move forward pending confirmation of the transactions tax free status and the receipt of customary approvals. We expect to file the SEC Form 10 next week, which represents another significant step in the process. The full effort is centered on completing the spin in the second half of the year, and the sooner the better. The sales process for our UK downstream business, however, continues and we are engaged with interested parties to divest those assets.

I'll turn it over to Roger now for an update on our exploration and production business.

Thanks, Steve.

First in exploration, Kevin McLachlan has joined us as an Executive Vice President of Global exploration. He comes to us from a major oil company in Canada with over 28 years of experience in worldwide exploration and new ventures. We welcome Kevin to our organization and where he'll lead this important function in our business.

In Australia, we're near total depth on our Bassett West prospect. The well has been delayed by rig repair and weather issues. We now anticipate the well to be drilled and logged by the end of May. Post the drilling and evaluation of this well, our partnership group being moved in the rig and drill in the nearby Dufresne prospect with results expected in quarter three. As mentioned previously the Basset West and Dufresne prospects are large Jurassic age Plover four-way closures, with combined total resources of 7 to 14 Tcf or 1.5 to 3 Tcf net to Murphy.

In Brunei, the Kelidang Northeast-1 well in Block CA-2 drilled earlier in the quarter as a gas discovery, but we encountered 115 feet of gas pay. This will derisk other gas prospects in the Block. And the partnership group plans to drill two additional wells in nearby similar structures later this year subject to rig availability. A successful project here would tie in nicely to LNG feedstock demand in Brunei going forward. We're excited to have a possible oil linked LNG project to join our two projects in the region, namely the Sarawak gas project producing today and the future Block H floating LNG project in Malaysia.

In Cameroon, we drilled our initial commitment well in the Elombo Block in shallow water early in the quarter, but failed to find commercial hydrocarbons. We have firm rig slots now in place to spud our two deepwater prospects in Cameroon this year. The Elombo deepwater will spud in early July. The Ntem well is slated to spud near year end. Subject to final government approvals and rig timing, these two prospects have pre-drilled gross estimates in the range of 300 million barrels and 600 million barrels respectively.

In the Gulf of Mexico, our exploration program will be active right at year end with upwards of three wells spudding, all dependent on rig availability. We will take delivery of our long-term contracted rig from Transocean in the second half of the year, where the timing has been delayed by operational difficulties by another party. The rig will start on completion work at Dalmatian development before drilling our first exploration well at Titan, and Jurassic Norphlet prospect underlying our Dalmatian blocks. Titan has a range of 150 million to 300 million barrels gross reserves. The other two exploration wells are non-operated projects with spuds near year end.

In business development and new ventures we continue to progress acreage additions in all of our focus areas. We participated in the recent Gulf of Mexico lease sale, where we were high bid on seven blocks across four prospects. Equatorial Guinea with the PSE ratified by the government in April, and we're planning a 3D seismic shooting in the fourth quarter. We continue to progress acreage adds in Vietnam, and we closed on our UK upstream asset at Schiehallion and Amethyst in quarter one. And we hope to close on Mungo/Monan this quarter.

We move to operations now. In Malaysia, Kikeh continues to operate to plan with production levels this quarter equaling lows of the first quarter of 2012 in a six year oil plus field. We do have scheduled shut-ins planned in this quarter and in August to install production facilities associated with the Siakap North - Petai Development which will be tied into our Kikeh FPSO this year. We've completed the critical lists on Kikeh this quarter on time, and we're returning the wells to production today. We have initiated development drilling on the Siakap North - Petai Project with first oil planned in quarter three.

Kakap-Gumusut early production system is producing at planned levels. The first oil for the full field development using the recently built floating production system is slated for late in the fourth quarter. Development work is progressing on our four Sarawak shallow water oil projects to plan, with top sides load out completed on Serendah, South Acis, and Patricia, with Permas planned for load out in June. Production starts for these four projects are staggered through the second half of the year. As planned, we should have all of them online by year end.

Operations are going well in our long-term oil price index Sarawak gas project. Quarter one production levels were a bit below last year, primarily due to planned maintenance at the gas receiving facility where we have added new compressor equipment that will allow us to produce 300 million scuffs per day with 100% redundancy. Post this planned maintenance program, we have been producing at normal rates this month. The realized gas price post PSE adjustments continues to be strong at $6.82 per Mcf for quarter one.

In the Gulf of Mexico, we are progressing our Dalmatian deepwater tie back project with all contracts awarded and field installation work scheduled in fourth quarter. As mentioned, our contracted rig will be doing well completions at Dalmatian as its first task. We're on schedule for first production in quarter one of 2014.

I'll move now to our North American onshore business. In Eagle Ford Shale, the development is really going well for us. Due to drilling efficiency, we've cut back our drilling plans to nine rigs at present. However, with continued pad drilling performance at such a rapid pace and improved efficiency in frac work, we expect to reduce our rig count to as little as eight rigs by mid-year in order to maintain our planned capital spend in the play. In addition to our rig program, we're continually running three to four frac units at this time.

We're currently focusing on our 100% working interest land in the Tilden area. This month, our net production in Tilden will exceed that of our Karnes field. We continue to focus on supply costs with operating expenses in quarter two continuing to be below those of quarter one, with new facilities coming online and rental test units being removed in the Tilden area. We've now drilled 268 wells in the play and have 222 wells on production. Production averaged just under 29,000 BOE per day net in quarter one, and we're currently planning on producing over 38,000 net this year. This quarter one 2013 production level is over 4,600 barrels a day higher than the fourth quarter of 2012. Processed was strong in the Eagle Ford for quarter one, averaging over $115 per barrel at an $8.70 discount to LLS.

The progress in two 40 acre downspacing projects in the Eagle Ford with one six field pilot at Karnes slated to flow in July. In addition, we are testing a 40 acre pilot in Tilden with planned production in September. We continue to experiment with all forms of well design, including amsmath length and orientation as well as frac techniques. As with any resource play, there will be continued technological upside here in the long-term.

In our 48,000 acre Pearsall Shale area that lies beneath Tilden -- Eagle Ford Shale, we've drilled, cored and logged four wells and have completed two horizontal wells in the play. The first well, our most northern well is both over 50 days at levels approaching 200 barrels a day with little gas seen in the production stream. Our second well has just started to flow. It's been flowing for eight days and it's presently exceeding 400 barrel equivalent at near 70% oil. Both these wells have been flowed at our normal technique of using very small choke sizes for long periods of production.

This flowback method has clearly shown to exhibit top quartile production levels and improved EURs in all our Eagle Ford Shale completions. We're encouraged by these initial results in the Pearsall, and plan to follow-up with more wells over the next year. But with any new plays, we're in early days as to completion design optimization and well orientation. We see current drilling and completion costs in the Pearsall are equal to those of our Karnes field.

Up in Canada at Seal, we restored all production online following the January fire. Net production is back at over 10,000 barrel equivalent per day. In response to low netbacks early in the quarter, we deferred some of our capital spend on primary drilling at Seal and redeployed those funds in the Eagle Ford. We have a released of all of our rigs through spring breakup, but we were able to complete our winter strap program doing a total of 23 wells.

We continue on with our EOR projects as planned. The polymer injection in Phase I of our commercial polymer project, which began pumping late August and continues on track. We have additional phases of polymer injection which will show production responses later this year and next. We start steam injection, our first cyclic steam one well pilot earlier in April. We should see results in the third quarter. We're awaiting regulatory approval for the next two wells in the pilot program.

We recently sold approximately 5,000 barrels of heavy crude by rail starting in the first quarter to establish that capability, and the pipeline netbacks were low as we saw at the start of the year. While early year low netbacks have caused us to reallocate capital, we have seen small periods where higher netbacks are available in the market. We've recently sold approximately 40% of our heavy crude for May and June at a price near $50 per barrel. We'll look to lock in similar prices for the remainder of the year.

In the Montney, our only North American onshore dry gas business, we continue to operate well and focus on cost cutting measures, reserve increases, and third-party gas processing opportunities through our facilities to improve margins in the field. We're encouraged by the subsurface studies taking place in our liquids rich area of Tupper Main. We're assessing this upside in necessary facilities to capture this prize. We currently have one rig drilling in Montney due to our original reduction in North America dry gas. We've also made a forward sale of approximately 80 million a day at an average price of $3.75 for the remainder of the year, which is near our earnings breakeven point.

In Muskwa Shale, we drilled and completed our second horizontal well in the play, but the well did flow oil with rates in the 100 barrel a day range. We've stopped the project for the time being. As a result, we have written off the drilling and completion costs of the first two wells and reflected those in expenses in results discussed for quarter one here today. In production, we're pleased with where we stand as to oil and gas production. First quarter averaged 201,876 barrel equivalent per day, exceeding our guidance of 200,000, primarily attributed to strong production growth at Eagle Ford and less impact from the Seal fire than originally anticipated.

The growth in our complementary onshore business is taking hold in the line for improvements and production guidance, as we significantly increased our Company's total producing well count with reliable predictable Eagle Ford Shale wells. Starting in quarter two of this year, we will report NGL production separately in our upstream business. We're doing this to reflect the growing significance of this production stream going forward with our Eagle Ford Shale growth. We have realized full value for our wet gas streams in the past. Now, we will say our production guidance for quarter two 2013 and the full year is 202,000 barrel equivalent per day, which includes near 2,000 barrels of NGL production.

I'll turn the call now back over to Steve.

The US downstream business reported total net income of $29 million with cash flow of $51 million. The first quarter was better than expected, primarily due to strong US retail margins, advantage product supply, and RIN sales. Year on year, US retail margins improved 55% in the first quarter of 2012, turning higher late in the first quarter in the falling wholesale market. This upward trend in fuel margins continues into the second quarter. And merchandise sales of $515 million were slightly lower than the first quarter of last year, but margins of nearly 13% remained flat. We added seven new US retail stations this quarter, bringing our total count to 1,172 with plans to end the year near 1,235. And our latest fuel discount program with Walmart was kicked off April 1 this year. Looking forward to those results.

In summary then, the spinoff of the US retail business continues to move forward on plan to complete the process in the second half of this year. In exploration, we're off to a good start with the discovery and have an active program for the rest of the year with impactful prospects to drill offshore Cameroon, Australia, and the Gulf of Mexico. We continue to meet or exceed our production targets as Eagle Ford Shale outperforms expectations and oil developments in Malaysia are on track to come online later this year as planned.

Now, that concludes our prepared remarks. So we'll open it up for questions now.

(Operator Instructions)

Evan Calio, Morgan Stanley

This is actually Drew Venker. Just curious, on the US retail, have you received your tax free spin approval from the IRS at this point?

No, we haven't as yet.

Okay. Could you provide a trailing 12 month EBITDA number for that portion of the business?

Trailing 12 months? The first quarter was about $67 million, but I don't have a trailing -- do we have the trailing 12 months? It was EBITDA, right, you were asking for?

That's right, yes.

As I said, the first quarter was a little over $67 million. We'll try to get -- Barry, can you get that for me?

Yes.

And I guess one while you guys are looking for that. Do you have any updated thoughts on potential divestitures beyond this retail spin, maybe in light of gas prices increasing recently?

You said divestitures? I think that the two ethanol plants, we don't view those as strategic to the retail business going forward and we'll probably divest those in short -- near-term. We have a terminal or two as well that aren't strategic to the retail, and we'll likely divest those as well.

Okay, and any reconsideration of potential Syncrude sale or your Tupper properties?

As we said in late January, the last call, those are two really, really great assets. If we didn't have them, certainly we'd be out trying to buy them. That said, if we were to receive a compelling offer, and I think I would know what a compelling offer was if we saw it. But barring that and some of the strategic need for the proceeds either in development of other projects, no, we really don't see it, a process being started.

Leo Mariani, RBC.

Was hoping you could elaborate a little bit more on this gas discovery you made in Brunei. I know you guys have made a series of gas discoveries over there. You guys have talked about potentially getting into LNG project. And I guess do you think you have scale at this point to do that? And what do you think would be the timing to get production on something like that?

Thanks, Leo. This is Roger. Yes, we do have a strategy of exploring for this type of LNG with the right partner groups in this region and in Australia. We've built up a good bit of gas discoveries in Malaysia where we're working with PETRONAS to -- and they are in a feed process of building a floating LNG vessel there. This will be very similar in sizing to that. I don't want to get specific on what we have, I'd say north of 500 Bcf on this well. These are three to four structures. They're very similar and look to the Block H we have in Malaysia, but they are different age rock. They're a Pliocene type age, both stratographic and structural features, very similar to Block H. I would say that this cluster opportunity here is 1.5 to 2 Tcf sort of a thing if we can get all this to work with future drilling.

It's a little bit different than Malaysia in this place. There is a shortage of gas in outer years in Brunei. They do have an LNG plant that will need gas. There's some gas infrastructure there. If we were to put all this together I think you could see some flow there in 2020, but a long way to go to delineate the other discoveries, get all this organized with gas sales, et cetera. But it is an appropriate partner group that are in long-term LNG that we want to be in. It's a place that does have a need for gas in their plant long haul, the way we understand it, and we're glad to have it.

Alright, that's helpful. It sounds like you're pretty close to TD on a well here in Australia. You had some delays there. Any preliminary looks at that? Any indications of hydrocarbons at this point?

No, it's just -- we're right on top of the reservoir. The rigs have been really struggling with some maintenance issues there. Just rather drill the well and announce it when we get finished, Leo, at this time.

Okay. And in terms of Tupper, you guys talked about doing some science work, explore a possible liquids rich area. Just wanted to get a sense of where you're at there and what you might think the liquids content could be in part of your acreage?

Sure, we have it in a corner of Tupper Main. Some of the folks around us have advertised this as well. There's a certain strata of the Montney that has this liquids rich feature. Next week at our Analyst Day, we'll be going over some maps and talking more specifically about it. This is not an earth shattering thing. I think it's a 20 million barrel kind of thing, but it can help add $1 to gas price there. And really help the economics of something like that, really turn to an earnings provider fairly quickly. We're all going to have to do some work to our plant to catch more of those liquids. It's not designed for high liquids. We're talking about 12 barrels a million, wells making 4 million a day kind of a number.

Alright, that's helpful. In terms of Kikeh, I just wanted to clarify what I heard on the call here. Did you guys say that you think you start to see some natural declines on there kicking in, in the second quarter of 13? Did I hear that right?

No, if you did, I said it totally wrong. That wasn't the intent. The projects flowed the same rate this quarter as a year ago. And when a field is that old, I think it's really good.

Okay, thank you for clarifying.

Our barrels are the same from one year to the next. Thanks for clarify that if I misstated it Leo. Appreciate it.

Additionally, are you done with your workover program at this point at Kikeh?

No, we finished -- there was some well repairs early in the program and now some additional wells required to develop the field, some of which were originally planned. We have that ongoing, both water injection and producers. That's in our budget. It's been in our plan. It will be going on into next year and Kikeh has been rolling along from the high 60s and low 70s for a good while now. Doing pretty well there.

Blake Fernandez, Howard Weil.

Congratulations on the strong results. Steve, I was hoping to maybe get an update from you on the UK. The process is obviously dragging on for quite awhile. I'm trying to recall if there is any integration between the refinery and the retail itself. Are those being marketed as a package? Basically, any kind of update you can give on that. Or and maybe even convert it to a terminal?

Let me first say, it is integrated. That could technically be sold separately. It would be a little bit difficult to structure, but we've marketed them together, but we're not adverse to separating them. But to date, I've judged by the time its taken us to the time we've engaged in this process is just a tough, tough market, Blake. It has been.

And converting it to a terminal, yes, we've looked at that. But as long as this refinery and marketing system itself, as long as they're not a drag on earnings or not a drag on cash flow, I think the best way or at least the most economic way of marketing them is as a refinery as a marketing system. But having said that, if we aren't able to divest these pretty soon, we may have to take different approaches. And like I said, the terminal is probably the last thing we would do because once you've done that, you've really -- I don't think there's any going back to converting it to a refinery if ever those thins come back up.

Got it.

To be back into the sellers market so to speak.

Okay, thanks. Kevin, would you mind giving us an update on the status of the buyback program, how much you have remaining on the authorization?

We did $250 million accelerated share repurchase we announced back in December I guess, and we got the initial tranche of 3.8 million shares that will retire at the end of last year. That piece is still ongoing. It still has another couple weeks to run before it would end. At the current prices that the stock has been trading at the last couple of months, we would expect maybe another 200,000 shares to get. Once that program ends in the next couple weeks, we'll take a look at doing the next piece. So, so far all we've done is the $250 million.

Okay, thanks. Roger, you introduced, I think what you categorized as a new Head of Exploration. I was hoping maybe you could elaborate a little bit. Is there a change in strategy? Or how should we think about this?

I don't believe there's a change really in strategy at this point. Its just been a short time. We, as you know, have Mike McFadyen and Gene that run two parts of our upstream organization. And our exploration business is quite two big businesses of Southeast Asia, Australia business and the Gulf of Mexico, West Africa business, each led by two folks. And I had an opportunity to bring in someone new.

Had some meetings with them, and decided I would have an overall leader at Mike and Gene's level, and let those two gentlemen run the exploration in other two area. And really like working with him, like his focus areas that he has worked is very similar to what we have. And he brings a lot of experience to the table. And that's why it's not a -- no one left, it's an add-on. It gives me another set of eyes at a very senior level, an experienced guy with the -- of the issues -- the experience I needed to help me. And that's all it is, Blake.

Okay, got it, thank you. The last one for me. Roger, I know there's been some issues with Syncrude and lower guidance, and then of course it sounds like you're pretty much raising the Eagle Ford. So I guess I'm just hoping for maybe a little context from a broader standpoint as it relates to the entire Company? Obviously, you have a very strong 1Q. I see you haven't changed full year guidance. Just trying to piecemeal together, does increasing Eagle Ford increase the likelihood of meeting or maybe even exceeding production guidance for the year?

If I did that, Blake, I'd raise the guidance. Blake, first on Syncrude, we have always risked that back to some of our other partners there. And I would say that the cutback of a major player there yesterday is very similar to what we have in our forecast, and we were probably there already. So I don't think that that's a culprit. Eagle Ford is doing very, very well for us at present. We've had some issues at Seal where we had a fire. It was some very low netback crude at the time.

And then we've had some delays with some rig issues in the Gulf of Mexico. And of course, this has the right machine that just can't get away from. We did do a workover that lead to the write-off in the previous quarter. So those are the issues pulling us down to keep from a big increase due to Eagle Ford. But I think the positive for us, as I've been saying for a long time, I'm going to keep saying it more, is we had the lowest -- we have the highest production per well of anybody in our group. And we had hardly any onshore wells. And our strategy of adding onshore wells allows us to have the issues with the high drop in decline of offshore and where the facilities can go off and hurt you.

So I think our strategy is working to become very predictable on the guidance. If you see, five quarters in a row, only one quarter missing, and it was 0.8%. Not that I'm tracking it that close. So there you go.

(Operator Instructions)

Paul Cheng, Barclays.

A number of quick questions. The 2014 outlook is still about the same at this point for production?

Yes.

And how about in terms of CapEx --?

Wait, let me back -- at your conference, we had an ability to lower the gas further, and I think it was 243 or something, Paul. And then it's the same graph that we showed at your conference where you were chairing the room.

Okay. And is the CapEx is still talking about somewhere close to this year level for next year or so?

Yes, I think it's going to be pretty close. Naturally, it will be overall down a little bit once the retail spin happens.

Right, but excluding the retail, Kevin, would it be -- (multiple speakers)

On the CapEx it will be -- for the E&P, it will be pretty flat.

And Kevin, do you have a rough estimate after the spin-off of the retail, what is the percent of the IDC that you will be able to generate -- that you will have enough income to show the IDC -- for the IDC to show in 2014? And let's assume, say, $90 WTI.

Right now, we have 70% of the IDC that we can take. And once we become full E&P, that would go up to 100%, but we still divest the UK downstream is my understanding before we qualify for that to go 100% IDC. Now at these levels of IDC -- with the amount of drilling we've been doing at the Eagle Ford, we had a net operating loss, tax reasons last year that we'll carry back and get a refund. And at current levels we'll have a net operating loss this year. And that should start to turnaround as we get in 2014 and Eagle Ford will start -- the back end of 2014 as Eagle Ford turns cash flow positive and the amount of money--

Maybe let me ask this way, in 2014 what is your estimated IDC going to be?

I couldn't tell you at this point in time.

Okay.

We'll look at it and let you know. I don't have that number.

Okay. Roger, do you have a percentage split in terms of your current Eagle Ford production between black oil condensate and gas?

Yes, we're about an 86% oil player now. We have very little gas. This Pearsall Shale will probably be a gassier thing for us, but our Eagle Ford is really black oil play, Paul.

So 86%, do you have a split between black oil and condensate?

86% of my production is oil, so the rest would be associated gas.

Okay, I thought you said -- (multiple speakers)

We have only about I think 7 million or 8 million a day of dry gas. We're making about 22 million a day of total gas. So the rest of that would be associated gas of oil.

And Roger, can you give us an update, where are we in the Canadian Bakken?

That's a place where we didn't do very well with our wells. We drilled the best well in the play, and the well is still making 200 barrels a day as good as any Eagle Ford well. But from seismic and additional well results, we didn't see the thickness of that strata, and we've just pulled back that drilling. We do see some word nearby of some folks that are doing better in some other strata.

They call things differently, the Three Forks and Big Valley and things on that side of the border, but it's just the same thing that we would have here. We are marketing our bit of acreage there externally and monitoring the well results of the folks around us at present. And with my capital that I have this year and the Eagle Ford going so well, it's just hard to spend additional capital up there at this time because of the value that I have. And that's kind of -- I'm pulling back a bit in those additional shale plays in Canada at this time.

And Roger, can you remind us how much you're spending in the Eagle Ford this year?

I think it's $1.3 billion.

And that's unchanged, right?

I'm sorry, Paul?

That's unchanged from your original budget even though you'd been -- (multiple speakers)

It might be $100 million more than the original budget, but we were looking the other day and you always stop completing -- when you're fracking four wells a day, you can stop some at the end of the year if you want.

Sure. And I know that you're talking about Tupper, that you guys at this point have no interest to restart the process to develop it. Under what circumstance or what condition do you need to see in order for you to go back and be more aggressive in the development there?

I think $5 gas, and if you'll see next week at our Analyst Meeting, we have some projections of production and we have a $5 gas premium that many of our competitors do. And I see that as a way to go, but we have to get ourselves back into a free cash flow game and it would depend on the gas price and how much of a rig program that could churn out because we've got to get back to free cash flow in our business. It's a goal we want to get to. And with the Eagle Ford going so well, it's going to need to be good shape to compete in North America there.

And Roger, do you have an update in terms of the floating LNG project for Block H?

PETRONAS is in the middle of their feed process. We visit with them continually. They have a full team on it. They are looking to build that and move forward. They've paid a very expensive feed. The results of that will be coming out in July. So of course they're not going to negotiate a gas sale agreement with Murphy until they get their feed work. And they're doing that now, we're on track, and hope to progress it throughout this year for both of us sanctioned this year is the plan at this time, Paul.

Steven, if I can ask two final questions. One, on the retail same-store sales, gasoline sales, for those store have been more than a year. Year over year, how does that look in the first quarter and so far in April? And then finally, in the first quarter, how much is the income you generated from the sales of RIN?

As to the RIN, let me answer that question first. The first quarter in $13 million in revenue and that's pretax. So I guess somewhere, in terms of net income, somewhere between $7.5 million and $8 million. Same store sales first quarter over first quarter last year?

That's correct. Only on those stores that had been there for more than a year.

Yes, same store sales -- I'm sorry -- down about 1% this year over -- since last year.

How about in April so far?

April, I don't think -- April to April, up about 4%.

April up 4%?

Yes, over last year's April.

Wow, okay, very good. Thank you.

Guy Baber, Simmons and Company.

I wanted to ask about your expectations for overall upstream margin evolution, because obviously you're bringing on a lot of new production in 2014 and 2015 and almost all of its oil and most appears to be high margin. And at the same time, your North American gas production should continue to decline. So I'm just wondering if you have any upstream margin targets that you've identified that you'll be monitoring and holding your people to? I'm wondering if you could share those targets in light of what should be a pretty positive mix shift coming over the next couple of years.

I think that's something I'd rather do next week. We're going to be showing a lot of EBITDAX for BOE information and everything to do with our operating range there, Guy. Clearly, we're in a $60 range going forward in the Eagle Ford, and we're going to be presenting at our Analyst Day how that's looking out through to 2017. And we've been oily for a long time. A lot of people strive to be oily like us. I don't specifically have a margin in each place. We are very much concentrating on our OpEx at present, and trying to get our OpEx much lower at Eagle Ford.

We've done all we can really do up in Canada, still working small things. But all in all, we're in a very high margin game. Our Kikeh crude is one of the most expensive crudes in the world and really good shape there on that. But our shallow water Malaysia, we're going through a period where those are not some of the highest margins in the world. So we'll be putting that in with our other mixtures that we have. But all in all, I think you would find we'd be a high margin player to our competitors and I'm going to have a lot of data next week in slide, and I think it would be easier to look at it at that time.

Okay, great. And then my follow-up was, in the Eagle Ford with the new guidance of 38,000, previously you've talked about that being a 50,000 barrel a day type play for you all by 2015 or so. Do you have an updated view on the longer-term potential now? Or is that something that would be covered at the Analyst Day also?

We're going to be talking about all of our production of all of our fields through 2017 including of course the Eagle Ford. I really want to get back into good shape on free cash flow. So we could make it 65,000 if we wanted to. But it's a matter of blending in and keeping that consistent and getting to a good program and working on our metrics, more than it is just getting the barrels out of it. So we've got to get this OpEx in great shape and we are and it is improving. But it's not a time where I think I'm spreading more than raving because I need to get cash flow CapEx in proper order going forward.

Pavel Molchanov, Raymond James.

To go back to one of the earlier questions about the UK divestiture, sounds like you're going to leave it an open-ended process or are you willing to set a deadline of some sort for arriving at a decision on that?

Thus far, last three years, it's been sort of open-ended. I guess at some point we'll have to draw the line, but I don't see it just yet.

Okay. And then on two of your areas where I know you've relinquished some acreage last year, Kurdistan and Suriname, any CapEx dollars spent in either of those areas this year?

No, no plans to do so. We're still focused in Suriname. We have another block there which we're shooting seismic on probably starting today. That was a block we owned for a long time and drilled previous dry holes on. So we're still at Suriname, a new Atlantic margin player. In Kurdistan, it's a place that I just don't see us going back to at this time. We do have a block. We do have a nice prospect left in our block. We're talking to folks about farming into the block. It just really doesn't fit the strategy I have at present of an offshore explorer where we made our hay through the years in a complementary onshore business. And that's just kind of where I'm headed right now.

(Operator Instructions)

Ray Deacon, Brean Capital.

Roger, I was wondering if I could ask Roger whether -- the Pearsall doesn't sound as though it's something where you would ramp capital or view it as kind of accretive to returns in the Eagle Ford, but you're kind of encouraged by what you're seeing so far. Is that kind of fair?

There's a lot of information in wells, and one good thing about the Eagle Ford is everybody talks about everything they have. So we have a very nice well there. This second well is a very good well, but that region is lacking gas infrastructure. There's a very rich gas stream coming off this well. We are very interested how we could fit that into Eagle Ford and would we want to, let's keep all Eagle Ford capital one thing and keep that acreage rolling there. We're just in the middle of that. And we're excited about this well result that we have for sure.

But with the lack of infrastructure and the timing of leases, it's a little bit subordinate timing to Eagle Ford. But it's a nice well. It's a matter of putting together all the other folks wells and seeing our acreage in the area of what will be perspective. We need to drill about three more wells probably and see what we have there, if you will. But this year, the well is -- our well is making about 1 million a day of gas, and we need to get some gas infrastructure into that area.

Got it. And could you talk about your well costs in the Eagle Ford, where they are? And one of your competitors talked about going 100% white sand in the Eagle Ford, and are you already doing that or do you have plans to do that?

No, our sand we're looking to leave alone as we normally do. For cost today, Karnes well, we're looking at our Karnes wells in the first quarter of $6.7 million, drilling complete. Tilden, where we have 80,000 acres, $6.8 million. In Catarina, we brought that down to $4.7 million. Talking best-in-class, which is what everybody else talks then the Karnes would be $6.4 million, Catarina $4.6 million, and Tilden $6.3 million.

Got it.

We're doing very, very well in that situation there.

It sounds great. And do you see much of an impact from rail at Seal? Could that --

There was a $10 impact when we moved it, and we trucked it to a depot near Peace River. And we have to do some cascading and some tanks to get our oil in a better shape to have a crude option, and we're working on that because we want to be part of a big rail, the big need. I think for us long-term, Seal is a big resource, and we've get to get our EOR going. But there's no question that the special refineries in the United States that need heavy oil, and we want to be part of that and rail will be part of it. And we're getting ready to do more railing, as we can, going into next couple of years.

We have no further questions. Mr. Cosse, I'll turn the conference back to you for closing or additional remarks.

Thanks, everyone, for participating on our call today. We look forward to seeing most, if not all of you next week at our Analyst Meeting. Thank you very much for participating.

And again, ladies and gentlemen, that does conclude our conference for today. We thank you all for your participation.