Seeking Alpha
We cover over 5K calls/quarter
Profile| Send Message|
( followers)  

Murphy Oil (NYSE:MUR)

Q1 2013 Earnings Call

May 02, 2013 1:00 pm ET

Executives

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

Barry Jeffery - Director of Investor Relations

Kevin G. Fitzgerald - Chief Financial Officer, Executive Vice President and Vice President of Murphy Oil Company Ltd

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

Analysts

Andrew Venker - Morgan Stanley, Research Division

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

Blake Fernandez - Howard Weil Incorporated, Research Division

Paul Y. Cheng - Barclays Capital, Research Division

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

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

Raymond J. Deacon - Brean Capital LLC, Research Division

Operator

Well, 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 Cossé, President and Chief Executive Officer. Please go ahead, Mr. Cossé.

Steven A. Cossé

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 U.S. Retail Business; Mindy West, Vice President and Treasurer; Barry Jeffery, Director of Investor Relations; and Tammy Taylor, Assistant Manager, Investor Relations.

Barry?

Barry Jeffery

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.

I'll now turn the call over to Kevin.

Kevin G. Fitzgerald

Thanks, Barry. 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 income of $8.6 million or $0.05 per diluted share in 2012. The 2013 disc ops results related primarily to a gain in the sale of 2 E&P properties in the U.K.

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 or $1.44 per diluted share. The decline in 2013 compared to 2012 was due primarily to higher expenses for exploration and administration, financing and income taxes.

So looking at income by segment. In the E&P segment, net income from continuing operations in the first quarter of this year was $231.9 million compared to net income in 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 a 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 the Tupper area in British Columbia and lower volumes from gas fields offshore Sarawak, Malaysia due to planned maintenance downtime.

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 U.S., downstream operations recorded income of $29.4 million in the 2013 quarter compared to a loss of $7.2 million in 2012, mostly as a result of higher fuel margins, advantaged product supply acquisition costs and RIN sales.

U.S. retail fuel margins average $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.

U.K. 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 is mostly attributable to higher administrative costs and the increased interest expense in the current quarter. At the end of the first quarter of 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.

Steven A. Cossé

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 nearly $3.50 for the quarter and even showed 1 year forward curve levels above the $4 mark. Although this is positive news, we continue with our strategy of minimizing CapEx, lowering our operating costs and delineating the liquids-rich areas in our Canadian market fields.

In U.S. 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 the upstream business, we've drilled and evaluated 3 wells, with 1 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 U.S. retail business, which we expect to complete in the second half of this year. Andrew Clyde, who, as I've said earlier, is President and CEO of the retail business, and his team are focused on efforts on all aspects of establishing a separate company to be prepared to move forward, pending confirmation of the transaction's tax-free status and the receipt of customary approvals. We expect to file the SEC Form 10-10 next week, which represents another significant step in the process. Our full effort is set on completing this spin in the second half of the year and the sooner the better. The sales process for our U.K. 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 movements [ph] .

Roger W. Jenkins

Thanks, Steve. First in exploration, Kevin McLaughlin [ph] 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, where he'll lead this important function in our business.

In Australia, we're near total depth on our Bassett West prospect. Wells have 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, a partnership group will be moving the rig and drilling the nearby Dufrense prospect with results expected in quarter 3. As mentioned previously, the Bassett West and Dufrense prospects are large Jurassic-aged Plover 4-way closures, with combined total resources of 7 to 14 TCF or 1.5 to 3 TCF net to Murphy.

In Brunei, the Kelideng Northeast 1 well in Block CA-2 drilled early in the quarter is a gas discovery where we encountered 115 feet of gas pay. This well de-risked other gas prospects in the block, and the partnership group plans to drill 2 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 2 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. We failed to find commercial hydrocarbons. We have firm rig slots now in place to spud our 2 deepwater prospects in Cameroon this year. The Elombo deepwater well will spud in early July. And the Ntem well is slated to spud near year-end, subject to final government approvals and rig timing. These 2 prospects have predrilled 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 average of 3 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 Titane, a Jurassic Norphlet prospect underlying our Dalmatian blocks. Titane has a range of 150 million to 300 million barrels gross reserves. The other 2 exploration wells are non-operated projects with spuds near year-end.

In business development new ventures, we continue to progress acreage addition in all of our focus areas. We participated in the recent Gulf of Mexico lease sale, where we were high bid on 7 blocks across 4 prospects. In Equatorial Guinea with -- the PSC has been ratified by the government in April, and we're planning a 3D seismic shoot in the fourth quarter. We continue to progress acreage adds in Vietnam. And we closed on our U.K. upstream assets at Schiehallion and Amethyst in quarter 1, and we hope to close on Mungo/Monan this quarter

We'll move to operations now. In Malaysia, Kikeh continues to operate the plan with production levels this quarter equaling those of the first quarter of 2012 in a 6-year-old-plus field. We do have scheduled shut-ins planned in this quarter and in August to install production facilities associated with Siakap North – Petai development, which will be tied into our Kikeh FPSO this year. We have completed the critical lifts 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 3.

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 4 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 4 projects are staggered through the second half of the year as planned, and we should have all of them online by year-end.

Operations are going well in our long-term oil-price-indexed Sarawak gas project. Quarter 1 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 normal rates this month. The realized gas price post PSC adjustments continues to be strong at $6.82 per MCF for quarter 1.

In the Gulf of Mexico, we are progressing our Dalmatian deepwater tie-back project with all contracts awarded and field installation work scheduled in the fourth quarter. As mentioned, our contracted rig will be doing well completions at Dalmatian as its first task. We are on schedule for first production in quarter 1 of 2014.

I'll move now to our North American onshore business. In the Eagle Ford Shale, the development is really going well for us. Due to drilling efficiency, we've cut back our drilling plans to 9 rigs at present. However, with continued pad drilling performance at such a rapid pace and improved efficiency and frac work, we expect to reduce our rig count to as low as 8 rigs by mid-year in order to maintain our planned capital spend in the play. In addition to our rig program, we are continually running 3 to 4 frac units at this time.

We're currently focusing on our 100% working interest lands in the Tilden area. This month, our net production at Tilden will exceed that of our Karnes field. We continue to focus on supply costs, with operating expenses in quarter 2 seem to be below those of quarter 1 with new facilities coming online and rental testing 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 1, and we're currently planning on producing over 38,000 net this year. This quarter 1 2013 production level is over 4,600 barrels a day higher than the fourth quarter of 2012.

The processor is strong in the Eagle Ford for quarter 1, averaging over 115 per barrel at an $8.70 discount to LLS. The progress in 2 40-acre downspacing projects in the Eagle Ford, with 1 6-row pilot at Karnes slated to flow in July. In addition, we're testing a 40-acre pilot in Tilden, with planned production in September. We're continuing to experiment with all forms of well design, including azimuth, 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 4 wells and have completed 2 horizontal wells in the play. The first well, our most northern well, has flowed over 50 days at levels approaching 200 barrels a day, with little gas seen in the production strain. Our second well has just started to flow. It's been flowing for 8 days, and it's presently exceeding 400 barrel equivalent at near 70% oil. Both of these wells have been flowed on 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 of 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. As 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 to equal those of our Karnes Field.

Up in Canada at Seal, we've restored all production online following the January fire. The 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 released all of our rigs through spring break-up, but we were able to complete our winter strat program, drilling a total of 23 wells. We're continuing on with our EUR projects as planned, with polymer injection, Phase 1 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 started steam injection of first cycle steam of 1 well pilot earlier in April. We should see results in the third quarter. We're waiting regulatory approval for the next 2 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. The pipeline netbacks were low as we saw at the start of the year. Our early year low netbacks have caused us to reallocate capital. We have seen small periods where higher netbacks are available in the market. We have recently sold approximately 40% of our heavy crude for May and June at a price near $50 per barrel. And we 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 of necessary facilities to capture this price. We currently have 1 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.

At 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 for the first 2 wells and reflected those in expenses and results discussed in -- for quarter 1 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 and in line for improvements in production guidance, as we've significantly increased our company's total producing well count with reliable, predictable Eagle Ford Shale wells.

Starting in quarter 2 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 2 2013 and the full year is 202,000 barrels equivalent per day, which includes near 2,000 barrels of NGL production.

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

Steven A. Cossé

Okay. The U.S. 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 U.S. retail margins, advantaged product supply and RIN sales. Year-on-year U.S. retail margins improved 55% from the first quarter of 2012, turning higher late in the first quarter in a falling wholesale market. This upward trend in fuel margins continued 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 7 new U.S. 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 has kicked off April 1 this year, looking forward to those results.

In summary then, the spin off of the U.S. 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 at Cameroon, Australia and the Gulf of Mexico. We continue to meet or exceed our production targets as Eagle Ford Shale outperforms expectations. And our 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.

Question-and-Answer Session

Operator

[Operator Instructions] We'll hear first from Evan Calio with Morgan Stanley.

Andrew Venker - Morgan Stanley, Research Division

This is actually Drew Venker. Just curious on the U.S. retail. Have you received your tax-free spin approval from the IRS at this point?

Steven A. Cossé

No, we haven't yet.

Andrew Venker - Morgan Stanley, Research Division

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

Steven A. Cossé

Kevin, trailing 12 months.

Kevin G. Fitzgerald

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

Andrew Venker - Morgan Stanley, Research Division

That's right yes.

Kevin G. Fitzgerald

Okay, as I said, the first quarter was 6 -- maybe over $67 million. We'll try to get back. Can get that for me?

Unknown Executive

Yes.

Andrew Venker - Morgan Stanley, Research Division

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

Steven A. Cossé

You said divestitures? Yes, I think the 2 ethanol plants. We don't view those as strategic to the retail business going forward, and we'll probably divest those in the short near term. We have a terminal or 2 as well that aren't strategic to retail, and we'll likely divest those as well.

Andrew Venker - Morgan Stanley, Research Division

Okay. And any reconsideration of potential Syncrude sale or your Tupper properties?

Steven A. Cossé

Well, as we said in late January, the last call, these 2 are really, really great assets. If we didn't have them, certainly, we'd be out trying to buy them. That said, if we would receive a compelling offer, and I think we'd know what a compelling offer was if we saw it, but barring that and some other strategic need for the proceeds, either in development of other projects, no, we really don't see it a process getting started.

Operator

We'll move on to Leo Mariani with RBC.

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

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

Roger W. Jenkins

Well, I mean -- thanks, Leo. This is Roger. Yes, we do a have 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've worked with Petronas to -- 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 from this well. These are 3 to 4 structures. They are very similar in look to the Block H we have in Malaysia, but they are different age rock. They're Pliocene type aged, both stratigraphic and structural features, very similar to Block H. I would say that this cluster opportunity here is 1.5 to 2 TCFs 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 play as 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.

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

That's helpful. And I guess it sounds like you're pretty close to TD on a well here in Australia. You had some delays there. Any kind of preliminary look at that? Any indications of hydrocarbons at this point?

Roger W. Jenkins

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

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

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

Roger W. Jenkins

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 strat 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 -- 1 million wells making 4 million a day kind of a number.

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

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

Roger W. Jenkins

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's that old, I think it's really good. Our barrels are the same from 1 year to the next. Thanks for clarifying that if I misstated it, Leo. Appreciate it.

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

All right. And I guess additionally, I think, are you done with your workover program at this point at Kikeh?

Roger W. Jenkins

No, we have -- we finished -- there was some well repairs early in the program, and now some additional wells are 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 would be going on into next year. And Kikeh has been rolling along from the high to -- high-60s and low-70s for a good while now, doing pretty well there.

Operator

Our next question will come from Blake Fernandez with Howard Weil.

Blake Fernandez - Howard Weil Incorporated, Research Division

Steve, I was hoping to maybe get an update from you on the U.K. The process is obviously dragging on for quite a while. I'm trying to recall if there was 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 -- and maybe even convert it to a terminal?

Steven A. Cossé

Yes. 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 are not adverse to separate them. But to date, as judged by the time it has taken us -- the time we have engaged in this process, it's just the tough, tough market, Blake. It has been. And converting it to a terminal, yes, we have looked at that. But as long as -- this refinery and the 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 to -- or at least the most economic way of marketing is as a refinery as a marketing system. But having said that, if we aren't able to divest this pretty soon, we may have to take different approaches. And like I said, terminal is probably the last thing we'll do because once you've done that, really, I don't think there's any going back to converting it to a refinery, if ever those things come back up back into the seller's market, so to speak.

Blake Fernandez - Howard Weil Incorporated, Research Division

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

Kevin G. Fitzgerald

Well, we did the $250 million accelerated share repurchase that 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 of weeks to run before it would end. At the current -- the prices that the stock has been trading at the last couple of months, we would expect maybe another couple of 100,000 shares to get. Once that program ends in the next couple of weeks, we'll take a look at doing the next piece. So, so far all we've done is the $250 million.

Blake Fernandez - Howard Weil Incorporated, Research Division

Okay. Roger, you introduced, I think, what you categorized as the 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?

Roger W. Jenkins

Well, no. I don't believe there's a change really in strategy at this point. He's just has just been here a short time. We, as you know, have Mike McFadyen and Gene run 2 parts of our upstream organization. And our exploration business is quite 2 big businesses, the Southeast Asia/Australia business and the Gulf of Mexico/West Africa business, each led by 2 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 2 gentlemen run the exploration in the other 2 areas. And really like working with him, like his focused areas that he has worked -- is very similar to what we have and brings a lot of experience to the table. And that's why it's not -- 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 issues -- the experience I needed to help me, and that's all it is, Blake.

Blake Fernandez - Howard Weil Incorporated, Research Division

Okay, got it. The last one for me, Roger, I know there has been issues with Syncrude and the 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 had a very strong 1Q. I see you haven't changed full year guidance. I'm just trying to piece them all together. Does increasing Eagle Ford increase the likelihood of meeting or maybe even exceeding production guidance for the year?

Roger W. Jenkins

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's 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 Azurite machine I just can't get away from had -- we did do a workover that led to the writeoff in the previous quarter. So those are the issues pulling us down to keep from a big increase due to the Eagle Ford. But I think the positive for us is, I've been saying for a long time and 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 and decline of offshore and where the facilities can go off and hurt yourself, I think our strategy is working to become very predictable on the guidance. If you see 5 quarters in a row, only 1 quarter missing at this point, 8%, not that I'm tracking it that close, so there you go.

Operator

[Operator Instructions] We'll now hear from Paul Cheng with Barclays.

Paul Y. Cheng - Barclays Capital, Research Division

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

Roger W. Jenkins

Yes.

Paul Y. Cheng - Barclays Capital, Research Division

And how about in terms of CapEx, you...

Roger W. Jenkins

Let me back -- at your conference, we had an ability to lower the gas further. I think it was 2 43 or something, Paul. And it's that same graph that we showed at your conference where you were chairing the room.

Paul Y. Cheng - Barclays Capital, Research Division

Okay. And just the CapEx, still talking about somewhere close to this year's level for next year also?

Kevin G. Fitzgerald

Yes. It could be pretty close. Naturally, it will be overall down a little bit once the retail spin happens.

Paul Y. Cheng - Barclays Capital, Research Division

Right. But excluding the retail, Kevin, will it be [indiscernible]?

Kevin G. Fitzgerald

On the CapEx, it'd be pretty -- for the E&P, it'll be pretty flat.

Paul Y. Cheng - Barclays Capital, Research Division

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

Kevin G. Fitzgerald

Well right now, we have 70% of the IDC that we can take. And once we have become full E&P, that would go up to 100%. But we still have to divest the U.K. downstream is my understanding before we qualify for that to go 100% IDC. Now these levels of IDC, with the amount of drilling we've been doing at the Eagle Ford, we had a net operating loss tax-free since 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 perhaps that should start to turn around as we get into 2014. And the Eagle Ford will start -- the back end of 2014, as Eagle Ford turns cash flow positive and the amount of the money [indiscernible].

Paul Y. Cheng - Barclays Capital, Research Division

Okay. Maybe let me ask it this way. In 2014, what is your estimated IDC going to be?

Kevin G. Fitzgerald

Paul, I couldn't tell you at this point in time. But we'll look at it and let you know. I don't have that number.

Paul Y. Cheng - Barclays Capital, Research Division

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

Roger W. Jenkins

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 a really black oil play, Paul.

Paul Y. Cheng - Barclays Capital, Research Division

So yes, 86%. You don't have -- do you have a split between black oil and condensate?

Roger W. Jenkins

Well, I'm 86% -- 86% of my production is oil, so the rest will be associated gas.

Paul Y. Cheng - Barclays Capital, Research Division

Okay, so I thought that you say [indiscernible] ...

Roger W. Jenkins

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.

Paul Y. Cheng - Barclays Capital, Research Division

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

Roger W. Jenkins

Well, 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's 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 the 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 called 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 in 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.

Paul Y. Cheng - Barclays Capital, Research Division

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

Roger W. Jenkins

I think it's $1.3 billion of revenue.

Paul Y. Cheng - Barclays Capital, Research Division

And that's unchanged, right?

Roger W. Jenkins

I'm sorry, Paul?

Paul Y. Cheng - Barclays Capital, Research Division

That's unchanged from your original budget even though you have been doing so well...

Roger W. Jenkins

It might be $100 million more than the original budget. But we were looking at a day when we stop completing. When you're frac-ing 4 wells a day, you can stop somewhat at the end of the year, if you want.

Paul Y. Cheng - Barclays Capital, Research Division

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?

Roger W. Jenkins

Well, I think $5 gas. And if you'll see, next week at our Analyst Meeting, we have some projections of production, and we have 5 gas -- $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 on 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.

Paul Y. Cheng - Barclays Capital, Research Division

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

Roger W. Jenkins

Petronas is in the middle of their FEED process. We visit with them continually. They have a full team on it. They're looking to build that and move forward. They 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. And we're on track and hope to progress it throughout this year it. To -- for both of us to sanction this year is the plan at this time, Paul.

Paul Y. Cheng - Barclays Capital, Research Division

Okay. Steve, if I can ask 2 final questions. One on the retail same-store sales, gasoline sales, for those stores that have been more than a year, year-over-year how's that look and so 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?

Steven A. Cossé

First of all, well, in terms of the RIN, I mean to that question first. First quarter we had $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. Now same-store sales, first quarter over the first quarter last year?

Paul Y. Cheng - Barclays Capital, Research Division

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

Steven A. Cossé

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

Paul Y. Cheng - Barclays Capital, Research Division

How's that in April so far?

Steven A. Cossé

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

Paul Y. Cheng - Barclays Capital, Research Division

April, up 4%?

Steven A. Cossé

Yes, over last year's April.

Operator

Our next question will come from with Guy Baber with Simmons & Company.

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

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 it's 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.

Roger W. Jenkins

I think it's something that next week we're going to be showing a lot of EBITDAX per BOE information and everything to do with our operating range there, Guy. I mean, clearly, we're in the $60 range going forward in the Eagle Ford, and we're going to be presenting in 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 play. We are very much concentrating on our OpEx at present and trying to get our OpEx much lower in the Eagle Ford. We've done all we can really do, what we can, but still working some small things. But all in all, we're in a very high margin game. Our Kikeh crude's 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 margin in the world, so we'd 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'd be easier to look at it at that time.

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

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?

Roger W. Jenkins

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 in a good shape on free cash flow, so we could make it 65,000 if we wanted to. So it's a matter of blending in and keeping that consistent, getting to a good program. We're 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 raising because I need to get cash flow CapEx in proper order going forward.

Operator

Pavel Molchanov with Raymond James has the next question.

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

To go back to one of the earlier questions about the U.K. divestiture, I guess sounds like you're going to leave an open-ended process. Or are you willing to set a deadline of some sort for arriving a decision on that?

Steven A. Cossé

Thus far, the last 3 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.

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

Okay. And then on 2 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?

Roger W. Jenkins

No, no plan to do so. We have -- we're still focused in Suriname, and 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 blocks. 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 years and a complementary onshore business. And that's just kind of where I'm headed right now.

Operator

[Operator Instructions] We'll move on to Ray Deacon with Brean Capital.

Raymond J. Deacon - Brean Capital LLC, Research Division

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?

Roger W. Jenkins

Well, 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's second well, it's a very good well. But that region is lacking gas infrastructure, but there's a very rich gas stream coming off this well. We are very interested in how we could fit that into Eagle Ford and would we want to keep all Eagle Ford capital one thing and keep that acreage rolling there. And 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 in timing to the Eagle Ford. But it's a nice well. It's a matter of putting together all the other folks' wells and see our acreage in the area what will be prospective. We need to drill about 3 more wells probably and see what we have there, if you will. But the issue is the wells and our wells making about 1 million a day of gas. And we need to get some gas infrastructure into that area.

Raymond J. Deacon - Brean Capital LLC, Research Division

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

Roger W. Jenkins

No, our sand over -- our sand we're looking to leave it alone, as we normally do. For costs today, Karnes well, we're looking at our Karnes wells in the first quarter $6.7 million drilling complete; Tilden, where we have 80,000 acres, $6.8 million; in Catarina, we've brought that down to $4.7 million. Probably best in class, which is what everybody else talks, then the Karnes will be $6.4 million;, Catarina, $4.6 million; and Tilden $6.3 million. Very, very well in that situation there.

Raymond J. Deacon - Brean Capital LLC, Research Division

Yes, it sounds great. And do you see much of an impact from rail at Seal. I mean, could that impact your...

Roger W. Jenkins

There was a $10 impact when we moved it, and we trucked it to a depot near Peace River. And we had to do some cash gating in some tanks to get our oil in a better shape to have a prude 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 got to get our EUR going. There's no question that the special refinery in the United States need heavy oil, and we want to be a part of that. And rail will be part of it, and we're getting ready to do more railing as we can going into the next couple of years.

Operator

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

Steven A. Cossé

Well, thanks, everyone, for participating in our call today. We look forward to seeing most, if not all, of you next week at our analyst meeting. So thank you very much for participating.

Operator

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

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!

Source: Murphy Oil Management Discusses Q1 2013 Results - Earnings Call Transcript
This Transcript
All Transcripts