Good afternoon, ladies and gentlemen, and welcome to the Murphy Oil Corporation Fourth Quarter 2012 Earnings Conference Call. Today's conference is being recorded. I would now like to turn the call over to Mr. Steven Cosse, President and Chief Executive Officer. Please go ahead, sir.

Thank you, operator, and good afternoon, everyone, and thank you for joining us on our call today. With me here are Roger Jenkins, our Executive Vice President and Chief Operating Officer; Kevin Fitzgerald, our Executive Vice President and Chief Financial Officer; John Eckart, Senior Vice President and Controller; 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 fourth quarter 2012 results. Steve and Roger will then follow with an operational update, after which questions will be taken. Please keep in mind that some of the comments made during this call will be considered forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. As such, no assurances can be given that these events will occur or that the projections will be attained. A variety of factors exist that may cause actual results to differ. For further discussion of risk factors, see Murphy's 2011 annual report on Form 10-K and the September 30, 2012, quarterly report on Form 10-Q on file with the SEC. Murphy takes no duty to publicly update or revise any forward-looking statements. I will now turn the call over to Kevin.

Thanks, Barry. Our net income for the fourth quarter of 2012 was $158.7 million or $0.82 per diluted share. This compares to a net loss in the fourth quarter of 2011 of $113.9 million or $0.59 per diluted share. For the entire year of 2012, we had a net income of $970.9 million, $4.99 per diluted share, compared to net income in 2011 for the full year of $872.7 million or $4.49 per diluted share. From continuing operations, net income in the fourth quarter of 2012 was $162.4 million, $0.84 per diluted share. This compares to a net loss in the fourth quarter of 2011 of $117.9 million or $0.61 per diluted share. The entire year's comparisons from continuing operations in 2012, we had a net income of $964.1 million or $4.95 per diluted share, compared to net income last year of $729.5 million or $3.75 per diluted share. The fourth quarter and full year results for 2012 included after-tax impairment charges of $239.6 million associated with both the Azurite field offshore of the Republic of Congo and our ethanol operations in Hereford, Texas. It also included U.S. income tax benefits of $108.3 million associated with operations in the Republic of the Congo and in Suriname. The fourth quarter and full year results for 2011 included a $368.6 million impairment charge, for which there was no income tax effect for the aforementioned Azurite field. Looking at income by segments, in the E&P segment, net income from continuing operations in the fourth quarter of 2012 was $145 million compared to a net charge of $144.6 million last year. The higher earnings in the 2012 quarter were mostly attributable to the larger impairment of the Azurite field in 2011 and the previously mentioned tax benefits recognized in 2012. The fourth quarter 2012…

Thanks, Kevin. 2012 is a profitable year for us, with $971 million of net income and cash flow of $3.5 billion. In the upstream business, we drilled 10 exploration wells and had 7 discoveries. We increased production by 8% year-on-year, which puts us near a 14% compounded annual growth rate over the last 5 years. We had an excellent year in reserve replacement with Eagle Ford Shale leading the way. We continued portfolio rationalization last year and signed agreements to sell our U.K. business, and those transactions we expect to close them here in the first quarter. In addition, we acquired bolt-on acreage at our Seal heavy oil property. And we added production reserves that fit well with our long-term enhanced oil recovery plans. In the downstream, we approved the spinoff of the U.S. retail business into a separate entity and solidified our relationship with Walmart through an agreement to grow the retail network with over 200 additional locations. We moved forward with some key initiatives for shareholders, including an -- increasing our regular dividend by 14%, declaring a special dividend to shareholders and implementing the share repurchase program. Dated Brent is the benchmark for the majority of our crude oil production and continued to outpace WTI for the quarter and the full year, with the spread averaging $21.80 and $17.70, respectively. After hitting lows near $2 per MMBTU earlier this year in a oversupplied market, natural gas prices in North America showed some strength in the fourth [ph] quarter, Henry Hub averaging $3.55 per MMBTU. While [indiscernible] continued strong demand for LNG provided support for our oil indexed Sarawak gas production. U.S. retail margins started the fourth quarter strong overall, as wholesale prices fell through October, but then eased off in December in a rising market, averaging $0.141 per gallon for the quarter. We continue to move forward with the spinoff of our U.S. retail business and in December, we filed a ruling request with the Internal Revenue Service seeking [ph] confirmation of tax-free status of the spin. We expect to receive an answer by midyear. This month, we announced the appointment of Andrew Clyde to the position of President and CEO of our U.S. retail marketing subsidiary. Andrew brings a strong background in gasoline and convenience retailing and will provide key leadership as we transition the business in the coming months. In the meantime, we're working on all aspects in establishing 2 separate companies to be prepared to move forward pending confirmation of the tax-free status of the spin. We are working to identify key members of the new management team, and preparing a strategic business plan. We anticipate completing the spin transaction in the second half of the year. U.K. downstream business, as we've announced before, will remain with Murphy Oil Corporation until the sales process for those assets is complete. Roger, you want to update on the E&P?

Thanks, Steve. Sure. On exploration, starting off in Malaysia. We drilled the Block H Alum well and made another gas discovery there, the seventh in a row in that play, encountering 280 feet of pay with a resource level near 150 BCF. So we'll drill another well later this year and continue to work with our partner, Petronas towards sanctioning the upstream portion of our floating LNG project, the Block, in late third quarter of this year. We've now established over 1.1 TCF gross per source for the project and have a third-party verification process ongoing. In Brunei, we are currently drilling the Kelidang Northeast-1 well in the CA-2 Block. The well is prospective for gas and is part of a larger cluster of gas-prone opportunities. A gas discovery here would fit well with Brunei's current LNG supply requirements. In Congo, we've relinquished our interest in operatorship in the MPN Block effective at the end of last year. In addition, we have given notice of our intention to relinquish our interest in MPS Block at the end of this quarter. In our Atlantic margin focus area, we've signed a PSC for Block W in Equatorial Guinea. We hope to start sizing [ph] work there late this year on this new acreage area. Further in the play, we signed a farm-in agreement for the Elombo Block on board of our current Ntem Block, in Cameroon. We now have a significant list of prospects in Cameroon focused on the Cretaceous span play. Elombo Block also contains shallow water prospects and the spud of the first well is scheduled to take place later this quarter. We plan on spudding 2 deepwater wells, one in each of our license later this year. We will operate at 50% working interest in the deepwater portion of…

Thanks, Roger. U.S. downstream business operated well in the fourth quarter, with solid margins in October giving way in December to rising wholesale gasoline prices. Overall, the U.S. downstream had fourth quarter net income of $22 million. Volumes continued to recover as our new measures implemented in the third quarter began to show results. We added 14 new stations in U.S. retail chain in the fourth quarter and ended the year with 1,165 outlets as planned. The U.K. downstream business recorded net income of $16.5 million for the fourth quarter. In 2013, our exploration program will include drilling close to a dozen prospects. We plan to drill 1 well in Block H, Malaysia; 1 well in Block CA-2, Brunei, which is currently underway, and pending results, likely a second location there; 2 wells offshore Cameroon; 2 Browse Basin wells in Australia, with the first well currently drilling; 2 to 3 wells in the Gulf of Mexico and a possible well in Semai II Block of Indonesia. The total capital budget for 2013 is $4.3 billion with $4.1 billion for our upstream business. In the upstream business, $500 million is earmarked for the exploration program and $3.6 billion will be spent on development projects, of which $1.5 billion is slated for the United States, mainly at the Eagle Ford Shale, and a further $1.5 billion is budgeted for Malaysia and $500 million slated for Canada. Downstream budget is approximately $200 million, primarily for new station builds and upgrades. We plan to add 65 to 75 retail outlets this year, and the future growth plans for the U.S. retail business will be rolled out in the coming months as we move towards the spinoff transaction. Production guidance for the full year is 200,000 barrels of oil equivalent per day, which represents a…

[Operator Instructions] We'll go first to Leo Mariani with RBC Capital.

Just a question here on Congo. Do you guys expect to get some production on that asset? In the first quarter, you kind of mentioned writing it off, a couple of your blocks. I'd previously thought that you guys were planning on getting some sales in the first quarter. Is that still accurate?

Yes, it is. Leo, this is Roger. We're going to continue to produce the asset at this time. We have a long-term lease obligation there and while we did impair the book value, et cetera, we are continuing to operate and probably, will do so going through this year.

All right. And I think you guys incurred a decent chunk of costs in the fourth quarter in the Congo. Do you expect to continue to see significant costs there? I think maybe you guys are trying to do some workovers to boost that production, any color you have around that would be helpful.

That workover is unsuccessful and I see very little spend in Congo going forward outside of normal OpEx at this time.

Okay. And I guess just looking at your LOE, your lease operating expenses, I mean it looks like to me they came down pretty significantly in the U.S. in the fourth quarter versus the prior quarter. Just any color you have around, what was driving that and how we should expect that to behave in 2013?

Well, we rolled that all into one U.S., Leo, this is Roger again. Our Thunder Hawk had a very nice well come on in the fourth quarter, and that's a leased FPSO facility. Also we continue to improve on the Eagle Ford Eagle Ford Shale as we build up production and production more in 4-well pads allowing us to accumulate more facilities there and lower our OpEx. So, yes, our OpEx is trending down led by those 2.

All right. That's helpful. And I guess in terms of your overall production guidance, I guess you guys are saying about 200 in the first quarter, it was about 211 in the fourth quarter. You talked about getting some sales volumes out of Congo. Can you just kind of help us out with what the other moving parts to kind of get from 211 and 200?

When you say 211, you mean 211 in the fourth quarter down to where we are now, is that what you're talking about?

Yes, 211 in the fourth quarter down to 200 or so in the first quarter, trying to bridge that gap.

Yes, I'll talk [indiscernible]. We have 4,300 coming down from West Patricia, as I mentioned, in my remarks the SK oil entitlement change. That's a reduction in pay per barrel, I suppose primarily. SK gas had a 7-day shut-in of almost 2,900 equivalent installed to compression that I mentioned. We sell in the U.K. a 2,800 and then we have the Tupper area continues to decline, around 1,600, and Syncrude has not been operating that well, about 800 down from the other quarter, and we have some builds going the other way with the K'ak'náab well on for the full quarter. Terra Nova, about the same, and then Eagle Ford adding to that other quarter, and that marches you back in that range where we are. We had -- I forgot to mention, Leo, of course, we had it in my remarks. But we had that fire at Seal that we just had to rush to add to the last variance before we went out.

We'll take our next question from Roger Read with Wells Fargo.

I guess a quick question, as I look at the kind of the performance here in the fourth quarter, strictly from an earnings standpoint and then I look at both the production guidance for the first quarter and the earnings guidance, is there another charge out there we're expecting to see in the first quarter? And if not, what else is it that's occurring on the cost side that's affecting the bottom line so much?

Roger, it's Barry here. Let me -- why don't I walk you sort of through and get you from 4Q to Q1. And it might help you see a little bit there. So let's -- if we -- when you normalize Q4, your in that $1.50 a share range for Q4 and we've come out with guidance here in the $0.55 to $0.90 range. So let's just walk through some of the moving parts. Corporate costs as we said before in the fourth quarter were $21 million, we're showing $52 million here in the first quarter, so that's $0.16 a share right there. Higher ForEx expenses, higher interest expenses and higher G&A expenses in that corporate number for Q1. Go to the downstream, when you normalize it and bring back in the Hereford impairment, you're moving from about a $78 million quarter to a $10 million loss, you've got a change there of $88 million. That's $0.46 a share, and that's all driven by Q1 lower margins in our U.S. retail, as well as lower margins projected in our U.K. downstream business. And then we get back to the upstream piece. When you normalize it and bring back in the Congo impairment and then those tax benefits we talked about, that was roughly a $1.22 a share quarter in Q4. And we're showing about $0.86 of our Q1 as being attributed to the upstream here. U.S. is pretty flat from Q4 to Q1. You've got growing Eagle Ford volumes offset by some G&G and OpEx expenses that are offsetting that. Canada, you're down quite a bit. You're down about $35 million, $36 million in Canada. You've got some higher costs at Syncrude and we've got some -- we've got lower volumes both Seal and Montney gas and lower prices for gas and heavy oil in Canada, as well as we have the well we're drilling at Muskwa in that Canadian number. So that's down about $36 million from Q4 to Q1. Then the other big one is Malaysia. We're showing oil sales in Q4 were significantly higher than oil sales projected here in Q1 on liftings, so we're down about 1.2 million barrels of oil sales from Q4 to Q1, offset obviously by the OpEx you're not going to show against those barrels until you lift them. So those are the big ones. Then I would say the Congo and our other foreign kind of offset each other. Congo will have less. In Q4, we have the Opale Marine and the Titane wells that we had to take. We won't have those repeat. But on the foreign side, we have a drilling program going with Australia, Brunei and Cameroon, as well as higher G&G costs, so those kind of offset. So all of that E&P stuff is about another $0.38 a share, so those are kind of the moving parts that sort of bridge the $1.50 back down to our $0.55 range.

Okay. So it sounds -- if I interpret that correctly, the cash impact in the fourth quarter was less so because you had mostly a charge whereas we're looking in the first quarter, most of this is either production that's not going to occur, the liftings or it's actually higher costs and so we are talking sort of a less free cash flow availability or less free cash flow generation in Q1 than we had in Q4?

That's fair.

Okay. The other question I had, can you walk us through what's going on, on the exploration side during 2013, just kind of what we should be looking for in other wells that you'll be drilling on that front?

Yes, Roger, great name there by the way. Steve, walked through some of this, so I'll go through another little bit of detail and Block H, on a nice run there, and we're going to drill a well there some time this year, these wells are very inexpensive to drill and we can come in and out of our development plans there and do them as we need to. So we'll probably have a Block H continuation well in the third quarter, we're drilling a well now in Brunei, the same type of a gas play, same type of size, resource, as we have in Block H, we'll more than likely have a follow-on well there around midyear. Now the Elombo block that I mentioned earlier is something we worked on for a long time. It has a shallow water well to be drilled here real soon and then a well of a cretaceous fan, a pretty big 200 million-barrel-plus prospect to be drilled at midyear, we'll drill a very large 700 million-barrel-type gross prospect right at yearend, we'll spud that well. We have the ongoing program in Australia, we drilled very large gas projects there, one called Basset West, one called Dufresne, and we just started the Basset West well and set surface casing, we'll be drilling there almost continually through midyear. We have possibly 2 wells to drill in Indonesia for our continuation of our commitments there, we're waiting on a jack-up rig from [ph] BP there. And we will get back to drilling in the Gulf of Mexico where we're bringing in our own deepwater rig, we will first complete our Dalmatian development wells and do some exploration work there at 2 of our prospects. So we have a good many to choose from, we'll be getting back to work in the Gulf in the second half of the year and that would pretty much wrap up a end of 11-, 12-well kind of program, which is where we want to be.

Okay. So the 2 Gulf of Mexico wells that you may drill, those have not been identified yet?

I have them here but I'm not identifying them yet. So yes, I have many options there and partners and things I'm working on at this time, but there will be an oil amplitude well to drill and a Northfield [ph] well to drill for sure in that 2 to 3 pocket.

We take our next question from Blake Fernandez with Howard Weil.

Roger, while we're on that exploration, I just want to make sure and clarify, when you said you relinquished the Congo MPN and MPS, is it fair to say that the presold exploration well is no longer on the books?

Well, we drilled our MPN well and we announced that well as dry sometime back as when we had our debt offering [ph]. We actually penetrated, went ahead and drilled ahead into the subsalt, didn't see good reservoir there, and it's been a long run of poor success in Congo for me, Blake, and it's time to move on. We're letting those blocks go.

Understood. Okay. And then, Roger, I guess, we'll have you, you talked about moving down 80 acres in the Eagle Ford, I know some of your peers are testing below that. Are you at a position where you're ready to start running pilots on below 80-acre or are you just going to wait and see what industry has to offer and then move from there?

Well, I think, we have -- I think I said we have 160-something wells producing today, 40 of them are downspaced to 80 already and we have about 13 months of history on our 80. It will be the longest one we've had. We've seen no interference and any problem with it. We'll probably, with the way my rigs are shaking out, the way my land is shaped, I may have some 40 acre downspacing, later in the year, probably may not have results on it this year, but I'm sure all my good friends around me will have plenty of data to talk about.

Right. Kevin, if you don't mind, could you give us an update of where you guys stand with regard to the buyback status?

Yes, we ended the accelerated share repurchase back in, I guess, it was mid December, $250 million. Now we had -- and there's a cap to that. We had a little over 3.8 million shares that were delivered to us. The counterparty that we entered into the ASR with is currently buying back that position in the market. We had set a timeframe of 2 to 5 months to complete that. But depending on what price is ultimately achieved, we could get an upward adjustment, it wouldn't be more another couple hundred thousand shares, but we could get an upward adjustment to the shares we receive. Now that 3.8 million-plus shares that we've gotten back have been taken out of the share count as of the end of the year and removed from -- the 250 million was removed from equity. Again, we'll just make the other adjustment when the program is completed.

Got it, okay. Final one I have for you, Steve, if you don't mind, I know you addressed Syncrude and Montney, I was just trying to help and clarify, is it fair to characterize this as a situation where you hired a consultant, you marketed the assets, and at this point, that process is over and now it's kind of like Montney and Syncrude are similar to everything else in the portfolio that at the right price, you're a willing seller but basically, we finalize that process, is that a fair characterization?

I think so. It's only we didn't solicit offers or anything. We went out and tested the market, I guess, from an inquiry standpoint but yes, that process is over. The conclusion we come to is, hey, these assets fit nicely in our portfolio for now. But again, as we said, having said that, if we need more cash, for the Eagle Ford shale or other project developments, we'll look at asset rationalizations. And Syncrude and Montney could be part of that rationalization process, but for the time being, we're not going to put it ahead of the formal process.

Okay. If I could just risk maybe asking, is it fair to say your interaction with Third Point has been finalized or are you still interacting with them?

Well, they're shareholders just like a lot of your clients are so, no, and I guess we're not finished interacting with them as long as they're shareholders.

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

Set of quick question. Roger, I think, or that maybe is for Kevin, I think, in your press release, you're saying that you have a higher working interest in Thunder Hawk and Front Runner, can you tell us what's the current working interest and then what's the production and earning contribution in the fourth quarter because of that higher interest?

We announced last year that we bought out our partner Statoil in the Gulf of Hall [ph] and that we're now 62.5% at both Front Runner and Thunder Hawk.

Yes, Front Runner, I think, Statoil originally stated [ph] 37%?

Yes, yes, that would be right. Now we're 62.5% at both. [indiscernible] in the fourth quarter, I don't have the earnings income of an individual field but look at the Gulf of Mexico, Thunder Hawk net fourth quarter, we made 64 95, oil and 5 million a day gas, BOE, 7.3, 7,300 a day.

And that's Thunder Hawk?

Thunder Hawk, yes, sir.

How about Front Runner?

Front Runner, we've been delayed in putting a new well on, it's been fairly stable for a long time, the well should be on today probably. In the fourth quarter, we made oil there, 44 79 net oil and 3.2 million a day gas per BOE around a little over 5,000 a day.

By the way, Roger, those numbers, is it net to you or just gross?

That's net to me, Paul.

So that means that seems that you essentially doubled your working interest, so that means, in the fourth quarter, your higher working interest have contributed roughly about 6,000 barrels per day for you?

Not really. Well, we -- if you go back from third quarter to fourth quarter, we bought it back in June. So there is some attributable to that, sure. But I don't believe that my success in making the quarter was due to buying out Statoil, I can tell you that, it's too much sweat to get it besides that, it wasn't by the pen.

Okay. Fair enough. On Eagle Ford, Roger, can you tell us what is the current unit operating cost, cash cost?

John, can you help me with that? Let me get Eckart here, exactly what is, Paul, if you don't mind.

12 months ended December, Paul, the Eagle Ford Shale OpEx was right around $23.

How much?

$23 for the full...

$23, do you have a fourth quarter number?

Sorry?

Do you have a fourth quarter number?

Fourth quarter number was -- I got it right here, $18.28.

And I assume that we should continue to see that trending down, right?

Yes, we hope to. We probably have -- probably be in the 14, before we make enormous improvement below that. But I'd also get that into 13, 14 range...

So long-term debt, you are targeting '13, '14. Do you think, Roger, that you can get there by the end of this year or sometime next year?

I think, a year from now, yes.

And well cost right now, is it still about $8 million or did that change?

No, we've been doing really well on that, Paul. If you look at Karnes where we've set some pace setter wells, like I said, around 13 days drilling case, which would be equal to any of the other players nearby, probably lowered our budget cost from 7.9 million to 7.2 million total in Karnes. Hilden [ph], where we're heavy driller. Hilden [ph] area, if you look in our slide decks, we're drilling those wells now in 11 days, and we're drilling them now and completing for 6.7 million in lieu of 7.7 million previously. And over at Catarina, which Eagle Ford Shale is shallower, around 8 days, and we're costing those wells with fracs at a little over 5 million, and we used to think that would be 6 million. So real good situation [indiscernible].

And Roger, have you announced that trucking order, or [indiscernible] order is actually using a more effective means to get the oil out?

Well, what I think has happened, if you look at the end of the year, we'll still be 75% trucking, we're about 86% trucking today. What's changed in the Eagle Ford shale is that the series of truck depots across the play used to be a lot of long-term mileage and backups and issues around the trucking. We very rarely have a tracking problem today and it's talking less than 20 miles instead of 80 miles. There's many places to unload the trucks, many depots, many options. We're doing very well with our crude. Murphy's land situation is not a condensate one. For black oil, 41, 42 degree API, we've been getting a $13 positive margin to WTI there for some time. And people want our crude in that area and we're doing very well with the marketing quality of crude because we have very little condensate in our business.

And should we assume that at this point, your production have not been curtailed because of transportation issue? So you've been able to produce whatever that you could?

During the holidays, some of these truck drivers don't come to work. You'll end up losing about 500 barrel a day, type of tank top issue. Corpus Christi area is becoming more just in time with barges, there are some crude being barged out of here. On occasion, you'd get a tank top issue. And once you're [ph] doing an FPSO and other things we have in our business but talking 500, 700 barrel a day curtailment for 2 or 3 days, we're making way more than that [indiscernible] better than it was 1.5 years ago.

Okay. Two final question. One, do you have F&D costs for 2012?

It's probably going to be around 30, Paul, we spend a lot of money and we booked a good many reserves but our 3-year average on that is probably about 27, but if you look at the F&D in our Eagle Ford, we're pretty proud of that, around 14. So that's -- so you can take our CapEx and divide into our barrels that we just announced, so that's around 30...

Sure. And final one there on Congo. If we look back in hindsight, is there anything that you may have learned now that we have changed the way how departure was originally being interpreted or analyzed or they're [ph] being developed? What we may have learned?

Well, everything in life, when you have a mistake, you learn from it, Paul, of course. I've been around, it's my 30th year, it's the only impairment I ever worked on, I don't think it's something happens very often. Let's say looking back in general, a couple of things, it was a small project. Anytime you go to develop 70 million barrels where you have no infrastructure, you have to be careful. I would characterize it as how you delineate more aggressively early on. And then also, we went to some one-off equipment that worked and we got it in the field on time and on budget from that one-off equipment that led to difficulties in performing the work over that we needed. As you know, in Kikeh, we're able to work on wells easier because the wells are set up differently and more uniform to industry. So those factors, I suppose, but this is something quite rare and I don't anticipate happening very often [indiscernible].

Sure. Have you, subsequently, instituted any changes in the way how your team, the process, have worked or that you think that this is somewhat of an obscure situation and so correspondingly, you don't have to change your process?

I would say we always are changing our process. We do a lot of business with Petronas, which has a very rigid 5-step gate approval process. We have to do so much business there that we put our business in that way. We have a formal review of resources now that's probably much more rigor than it was in those days. So of course, there's always improvements in sanctioning, the projects are very expensive. And I'm certain that the lessons have been learned and the process are in place to prevent it again.

We'll take our next question from Pavel Molchanov with Raymond James. Pavel Molchanov - Raymond James & Associates, Inc., Research Division: On the U.K. assets, obviously, it's a tough market to sell, anything refining related in Europe. At what point would you just say, you know what, let's just shut it down or convert it into a terminal?

Good question. I think we've got pretty close to that decision probably a year ago. But the U.K. operations started -- it didn't become a drag on earnings, it didn't become a drag on cash flow so we sort of deferred that. It's a good question, but I really can't answer it right now. I think, for now, we're engaging different parties and hope -- we are hopeful, remain hopeful, that we'll be able to conclude something in the near future. But we're not there yet. Pavel Molchanov - Raymond James & Associates, Inc., Research Division: Okay. And then once you presumably sell the U.K. and spinoff U.S. downstream, have you done the math on what would be the cash savings on your income tax based on the different treatment of independents versus integrated companies under the U.S. tax code?

Well, it will be 100% in the U.S. because I'll operate at a net operating loss, as long as they allow IDCs to be deductible as they currently are. I mean, my issue will be -- we've talked about it several times in these calls and a lot of one-on-ones, biggest issue I have will be tax, efficiently moving money around the world because of that potential net operating loss position in the U.S., that will be driven by the intangible drilling cost adoptions [ph]. Pavel Molchanov - Raymond James & Associates, Inc., Research Division: Okay. But I guess any sense of, in dollar terms, what the savings might be, for example, in last year, had you been treated as an independent, what would it have been?

Well, I don't have those particular numbers, I could tell you, for 2012, we're going to have a big net operating loss to the tune of $500 million that we're going to carry back to prior years where we had a lot of taxable income. Now a lot of the taxable income in, say, in 2011, was driven by the sale of the refineries. And then I've had taxable income driven by the downstream. But when the retail gets spun off, a large portion of both my U.S. cash flow and taxable income goes away and I won't have taxable income in the U.S. As long as they keep IDC deductions, I won't have taxable income in the U.S. for some time.

We'll take our next question from Guy Baber with Simmons & Company. Guy A. Baber - Simmons & Company International, Research Division: You guys added to your exposure at field during the quarter but, Roger, you also mentioned the poor netbacks that you're seeing in your prepared remarks. I was just hoping you could discuss your outlook for a heavy Canadian oil differentials, how they could impact the way you allocate capital there and are there any initiatives to really improve those realizations in light of what could be a pretty challenging price environment over the next couple of years?

Yes, our marketing folks and we believe that it will show some improvement in the second half with lighting refineries and chart refinery and certain in-bridge improvements, the in-bridge thing has become quite a surprise to industry. We'll only need our netbacks in the 50s here to have the rate of return that we need. Of course, it's much below that now. We are working on many initiatives on rail, I think rail will be attractive there. I know we're working at some items we'll have to do to change our -- the way we treat the crude in order to get it rail-ready and we're working on that a good bit. I'd say, off the top of my head right now, and I'm fairly close on this, it's a couple hundred million of drilling, probably 100 million on the conventional old fashioned horizontal drilling. We can move that to Eagle Ford quite easily and because our Eagle Ford is drilling so fast, we're ending up with 40-something wells parked there today, more than we've ever had. So we have that flexibility, we're organized with 1 onshore, North American team. That won't be difficult to do. But we have to be careful pulling back on EOR, the prize here is EOR. I do believe that the refineries in the United States still will want heavy, there'll be a market for heavy, there's enormous business for heavy, there is a long-term enormous pipeline expansion for heavy. So we're going to stay -- we have to be careful not to -- one of the problems in Seal in the past, they have to pull back the capital and move it somewhere else. Now of course, we have a very lucrative Eagle Ford to move in into but we have to be careful with that on the strat side, the steam side. But I think we can move some capital on the conventional and are looking to do so and planning to have that worked out in the next couple of months. Guy A. Baber - Simmons & Company International, Research Division: Okay, very helpful. And then my follow-up is you all are forecasting downstream losses during 1Q, so can you just speak to expected U.S. retail performance. I know early last year, you all talked about volume and margin under performance there relative to peers, but you since identified some initiatives to improve performance and have been encouraged, so just looking for any update there, just with respect to how those initiatives might be progressing?

Guy, it's Barry here. I mean, Q1, of course, is typically a shoulder season for that business and always difficult and has been in the past. We talked about these initiatives we had. I think we saw some nice results in terms of volume recovery, balanced with margins and showed a pretty good fourth quarter as result of those initiatives. I think this year, we're just anticipating that moving along but the normal seasonal trends holding true as well, as part of that business. So I think we anticipate obviously coming out of it in Q2 and through the summer and with the usual strong seasonal results.

We'll take our next question from Stephen Simko with Morningstar Equity Research.

My question is just to -- just on your exploration program and looking at the results over maybe the last couple of years, they haven't been -- they've been mixed, you guys have spoken to that in the past, but looking at your 2013 drilling plans, I don't personally identify any major changes in strategy, and I'm just wondering, are you guys looking at your -- at exploration at all in terms of spending levels or just even in any ways, how you approach it day to day operationally, in terms of possibly changing it in the future, or are you pretty content and feel that you're in a good spot [ph]?

Well, I think we've made a good many changes in the rigor of the decision-making we've put forth and work that we make commitment wells on, definitely made a change in that. We just happened to -- we have had pockets of success in Block H Malaysia, 7 in a row means that you can analyze seismic and find and drill wells successfully and we have that ability. We're involved in Western Australia offshore, that has a very high success rate. We're glad to get into that at ground-floor basis. we've been working a long time on the Atlantic margin with the Cretaceous span play, which is a new play for us, and we've established a very nice position in Cameroon, the 2 blocks that have been sought after and had competition by others. And we just added a block in EG along that same margin, the steep margin where the Cretaceous span plays exist. I think another difference for us at Murphy, we're getting back to work in the Gulf of Mexico. Due to Macondo, we didn't work for a while. A place we focused on less. If you look back at our history, over a 10-year period, we're a top quartile exploration company. Company of our size only takes one significant exploration hit to be needle moving. We believe we're an exploration-first company. We're using our very strong North American onshore business to be complementary to our exploration program. And I believe that sets us up unique and I do believe we've improved the rigor in the work and I'm happy with the way we're doing it. I'm glad to get back in the Gulf and I'm glad for the new acreage that we have. I do see it to be different and I do see it to be better in the future.

Very helpful. And then a real quick follow-up is, does what's happening on the ground in Australia right now change your opinion of how much capital you want to put there going forward or is that to you just possibly a short-term issue with that, really doesn't impact how you're going to be thinking about your...

We have been very successful in Malaysia, selling a small volume of gas to Petronas for a long time. We're actively involved with Petronas on floating LNG. But I believe Petronas to be the leader in gas, total value chain LNG in the world. So when they're interested in building 2 floating LNG, I think, floating LNG will become the way forward, away from the super large onshore multi TCF projects and 5 TCF project with the floating LNG may end up being better than larger TCF on land, I think the execution may end up being easier, I just have a feeling that floating LNG in that part of the world is going to be successful. It's the reason I'm in West Australia now, and that's the difference in the play that I see is the emergence of floating LNG and you are hearing of a good bit of flowing LNG work in Australia today due to the CapEx, the timing and the stakeholders and the increased times to gain those approvals on the big onshore plants. That's my view of it.

Ladies and gentlemen, in the interest of time, we have time for one more question. We'll take our final question from Ray Deacon with Brean Capital.

I had a question about reserve replacement and what -- have you broken down the sources of reserve adds?

Well, many, many fields, Ray, we start off yearend '11 and make the changes, subtract the production, if you look at the changes this year, is that what you're looking at, some color on some of the...

Yes, just largest sources of reserve adds. It sounds like Eagle Ford was...

Eagle Ford shale is around 87 million barrels, these are all BOE, Ray, but it is around 86% oil for us, Dalmatian, around 9 million barrels. And our Sarawak gas projects, which we continue to add reserves there, probably around 11 million BOE. And SK Oil that we'll be flowing later this year and after we have those sanctions, around 10 million barrels there. And then at West Pat, which is a project we've had for a long time, a really super performing project around 4 million barrels. Those are some of the biggers [ph] of -- the rest are in the 1 to 2 range and numbers to that effect, Ray.

Okay, got it. Great. And the wells that you're going to drill at Dalmatian midyear, that would add new reserves or is that...

When you initially book at the sanction, we don't book all of it, we're probably not even halfway there. So we have some -- when you drill these Gulf of Mexico wells and tie them back, we'll be completing the original discovery wells, that's what makes it so economic and so robust. So we have not drilled the exact water level, we have not fully delineated, these wells are flowing to another facility, do not have the infrastructure to build out as in a Congo example. So a long way to go in the book and they're probably not even halfway at Dalmatian.

Got it. And just one more quick follow-up. In Australia, would you -- how does the risk profile of the 2 remaining wells compared to kind of what you've done so far, is it the same kind of geology and traps you're going to be drilling there?

No, this will be totally different. We drilled a stratigraphic trap early on in this AC/P36 Block. These are large 4-way plover [ph] closures. We had this on our Block all along, it was deeper, the Conoco Poseidon discovery nearby opened this up from a reservoir-ability perspective because they're deeper than we are. And that opened up the play, there's been several discoveries in a row, the 4-way closure plover [ph] in this area is over 50% chance of success and the real risk is volcanics bleeding into the reservoir section in lieu of charge of Seal. So we see it to be a very prospective play, and once it was derisked by the Conoco discovery, it opened up a nice play set to drill in my view.

That does conclude our question-and-answer session for today.

Thanks, everyone, for participating in our call. Have a good day.

That does conclude today's conference. We thank you for your participation.