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?

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.

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…

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…

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

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.

Okay. Could you provide a trailing 12-month EBITDA number for that portion of the business? Steven A. Cossé: Kevin, trailing 12 months.

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?

That's right yes.

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

Yes.

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.

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.

We'll move on to Leo Mariani with RBC.

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?

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.

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?

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.

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.

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.

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?

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.

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

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.

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

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.

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?

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.

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?

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.

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?

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

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

Yes.

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

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.

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

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

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

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

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.

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].

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

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.

Okay. Roger, do you a have 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 a really black oil play, Paul.

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

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

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

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?

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.

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

I think it's $1.3 billion of revenue.

And that's unchanged, right?

I'm sorry, Paul?

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

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.

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?

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.

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'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.

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?

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.

How's that in April so far? Steven A. Cossé: April, I don't think -- April to April, up about 4%.

April, up 4%? Steven A. Cossé: Yes, over last year's April.

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.

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?

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.

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?

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

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?

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.

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?

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.

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

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.

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.

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