Good afternoon, ladies and gentlemen, and welcome to the Murphy Oil Corporation Fourth Quarter 2011 Earnings Conference Call. Today's call is being recorded. I would now like to turn the call over to David Wood, President and Chief Executive Officer. Please go ahead, sir.

Thanks, operator. Good afternoon, everyone, and thank you for joining us on our call today. With me are Kevin Fitzgerald, Executive Vice President and Chief Financial Officer; John Eckart, Senior Vice President and Controller; Mindy West, Vice President and Treasurer; Barry Jeffery, Director of Investor Relations; and Tammy Taylor, Assistant Manager, Investor Relations. I will now turn the call over to Barry.

Thank you, David. Welcome, everyone, and thank you for joining us. Today's call will follow our usual format. Kevin will begin by providing a review of fourth quarter 2011 results. David 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 2010 Annual Report on Form 10-K filed 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 for his comments.

Thanks, Barry. For the fourth quarter 2011, we showed a net loss of $113.9 million or $0.59 per diluted share. This compares to net income in the fourth quarter of 2010 of $174.1 million or $0.90 per diluted share. For the full year of 2011, we had net income of $872.7 million or $4.49 per diluted share, compared to net income in 2010 of $798.1 million or $4.13 per diluted share. From continuing operations, in the fourth quarter of 2011, we showed a net loss of $113.3 million or $0.59 per diluted share compared to 2010 fourth quarter, where we had net income of $149.5 million or $0.77 per diluted share. For the full year of 2011, income from continuing operations was $740.9 million or $3.81 per diluted share, compared to net income from continuing ops in 2010 of $779.6 million or $4.03 per diluted share. As a reminder, Murphy's 2 U.S. refineries and certain associated marketing assets were sold near the end of the third quarter of 2011. The financial results related to these assets are now presented as discontinued operations. The fourth quarter and full year results of 2011 included a $368.6 million impairment charge for which there was no income tax effect for the Azurite field offshore of the Republic of the Congo. Poor well performance led to a cut in proved reserves at this field at year-end 2011. Excluding the impairment, income for the fourth quarter of 2011 was $254.7 million, $1.31 per diluted share. There were no one-off type items of significance in the fourth quarter of 2010. Looking at income by segment. In the E&P segment, we had income in the fourth quarter of 2011 of -- loss of $139.9 million versus income in the fourth quarter of 2010 of $154.1 million. The lower…

Thanks, Kevin. Looking back, 2011 saw benchmark WTI prices range bound between $90 and $100 a barrel for much of the year, with excursions above this range in the second quarter largely due to the shut-in of Libyan production and below the range in the third quarter as the market reacted to European Union sovereign debt issues and the S&P downgrade of U.S. government dent. Dated Brent, the marker for much of our production, outpaced WTI, with the spread starting the year near $10 then widening significantly over $25 by the third quarter before retreating back to current levels near $10, a level likely to be sustained given a number of regional transportation factors. We have set our 2012 budgeted oil price at $85 WTI and $100 Brent, which should be a conservative position given current pricing levels and global crude fundamentals. Natural gas prices in North America languished through 2011, working downwards from $4.50 at the beginning of the year to current levels below $3 as warm winter weather temperatures exacerbated the supply-demand picture. While we do not expect natural gas prices to remain at this low level midterm, we do expect pricing to be under pressure throughout 2012. I see us redirecting spend away from pure dry gas investments as the year plays out. We are fortunate that our North American portfolio has opportunity and flexibility to be able to move money and rigs to oilier plays timely. We are almost 2 years removed from the unfortunate and tragic events of the Macondo incident in the Gulf of Mexico. And while the pace of the play has improved, new permits require higher levels of manpower and much more time to complete. That, coupled with fewer rigs, makes for a much slower and for us, a smaller business. This…

[Operator Instructions] We'll take our first question from Arjun Murti with Goldman Sachs.

David, it sounds like the Kikeh program has gone well in terms of the workovers. Is there anything left to do? Or is it now done as -- in terms of getting everything back online?

Arjun, Kikeh is a great field, but we still got a lot of work to do. I think in a prior call, I said that we still had some original wells to drill from the sanctioned field development plans. So we've got a pretty active program this year. I think we drilled 12 wells, including some water injection wells. And as we go forward, we'll be looking to maintain this level. So there's still quite a bit of work to do.

But as far as the workover program, it sounds like that is now completed and behind you.

Yes. As we sit here today, I feel in pretty good shape with that field. This time last year, we didn't really have the rigs in the field to do the work, and we had not started doing the work to fix the problem. And now, that's behind us now. So yes, I feel very much better today.

And then 2 very quick North America resource questions. You alluded to some dry holes or exploration write-offs in Southern Alberta. Presumably, that's the Exshaw, Southern Alberta basin Bakken position. Can you just talk about what the status of that is? And then the second question is, any thoughts on how results in your Tilden area are comparing and contrasting to what you're seeing in Karnes County and the Eagle Ford?

Yes. So Southern Alberta, we drilled 6 wells, and we wrote off 5 of them. The sixth well is actually a pretty strong well. The thing you need to appreciate is it's actually not in the Exshaw. It's in the Three Forks. And so that's part of the logic for us in writing down the Exshaw. It's not that I don't think the Exshaw has potential. A couple of those wells I think gave us some encouragement, but this is a very nice well. And so I think our focus is shift it a little bit here. And I said in our budget, we have a couple of wells. Clearly, given this well result, we're going to do more drilling there. And clearly, given the fact that gas prices have got quite low here, we can move some capital and some rigs away from Tupper and move in that direction. So to me, it's the first time that we've seen some encouragement in that geography, and we're going to be quite active in going after that. As far as Tilden goes, we're a little bit behind that in terms of our development than our Karnes area, but I think we're pretty pleased with what we've seen so far. And so I'm comfortable that that whole Eagle Ford program for us, which is quite important, is pretty much on track. The evacuation in the Karnes area is -- in terms of pipeline, is slightly ahead of what it is in Tilden, but I think Tilden will be right behind it. But well results, better than what we thought.

We'll now take a question from Leo Mariani with RBC Capital Markets.

You guys addressed, obviously, weak gas prices here, discussed pulling rigs potentially away from the Montney, redirect them to other areas. I mean, clearly, gas has been pretty weak, below $3 for about, I guess, several weeks now. Is there a plan to do that in the very short term? Could you just give us some kind of thoughts on timing of when you may reshuffle the rigs? And how do you expect that to impact your Montney production? Do you expect to keep your Tupper plants full? Or could we start to see that production decline later in the year?

Leo, it's a great question. It's one that we're working now. We've actually been pulling rigs off Tupper. So let me kind of say what the budget for this year and next year is and the impacts of what we think is going to happen. So for this year, we were forecasted to drill 37 wells at Tupper and spend just over $300 million. If we take that down to a minimum number of wells, which for us is 14, we have some obligation wells to drill, then our CapEx falls to -- falls by about $160 million. The net impact of that is about 3,000 barrels equivalent a day on the year, so not much impact for the amount of capital we pull out. If we do the same thing next year in 2013, where we were budgeted about $430 million of CapEx to drill 45 wells, if we drop that well number way back, we'll save about $350 million of CapEx, but we'll lose a further 9,000 barrels a day of production. So we could lose 3,000 this year and 9,000 next year just from declines and not putting new wells back on production, but we would save over $500 million of capital that we could redeploy. And so part of the exercise that's ongoing now, and we have an integrated group, is where should we put those rigs for best effect? The nice thing is we have some options. We can step up the program at Seal. We can do some more drilling in Southern Alberta. Those of you that have done the math realize that when I said what the rig count was and the fact that we have spudded a well on our new play -- realize that the play is in Canada. That gives us great flexibility in putting rigs up there as well. So we have ability to physically move equipment, and then we have places to redirect capital. Of course, we also have the Eagle Ford to play. So that's kind of the name of the game for us as we look at the next 2 years with dry gas.

Okay. And I guess, clearly, as you redirect capital, I'm assuming that the effects on the production, that's just losses in the gas, but clearly, there will be some potential increases here on the oil side. Could you elaborate that on a little bit? And also, could you talk about potential takeaway on the Southern Alberta basin? Clearly, it looks like you've got a nice well there, but are you guys going to be able to get that oil sold in the short term? What's the infrastructure like over there?

300 barrels a day doesn't cause me any problem. If I got it up to some multiple of that, I think we'd have to look at it. That's getting ahead of ourselves here. I think we need to get in and get more active and get some other good wells, but I don't see that as being an issue, specifically. You're right in terms of redirecting the spend off [indiscernible]. We can go ahead and bring on production in these other areas. What the exact offset would be for the dollars, I don't have yet. That's being worked. But if the baseline is a 3,000 barrel a day loss this year and 9,000 next year, I certainly would expect to close some of that back through redirecting that capital, and I'm also redirecting it to more valuable production. So I think on a bottom line basis, it'll be kind of a win for us.

Okay. And I guess in the Gulf of Mexico, you guys talked about clearly having some delays in 2011. I think you mentioned spotting a Thunder Hawk well in February. Were you guys also drilling a well at Front Runner at one point? Is that still on the schedule here in early 2012?

Yes. It's all tied to permits. Last year, we tried to get an approval for the Thunder Hawk well and finally got it at the end of the year, and we now have a rig lined up. So that's the most important drilling that'll impact production this year in the Gulf, would be the well at Thunder Hawk. And so we -- we're anxious to get on with that, and we have a rig lined up here in first quarter to get that started.

We'll now hear from Blake Fernandez with Howard Weil.

A question for you, David. You just covered the, I guess, redirection due to, potentially, some natural gas weakness and a slowdown in activity there. But I guess from a little bit of a longer-term perspective, last conference call, we've talked about the potential sanction of Tupper Phase 2, and obviously, that's predicated on a decent gas outlook. So it seems feasible to think that that project's probably deferred, and I'm just curious to see how you're thinking about that and how we could potentially fill that void or if that's even in the cards. I mean, maybe we just defer that and go with the lower volume.

Yes. If you look long term, so we've talked about a 2015 target from existing assets that we have, excluding things like South Alberta we just talked about. In 2015, Tupper in that number is supposed to be producing about 40,000 BOEs and the Phase 2 Tupper, an incremental -- little over 20,000. So 60,000 BOEs from that area is dry gas. Clearly, if we slow the investment, then it'll decline, but it won't be 0. The decision on the Phase 2 is kind of an end of this year, next year type decision for what we think gas prices are going to be in 2015. So if we just say we get pessimistic about 2015, we'll probably have something in the 20,000 to 30,000, maybe even 35,000 BOEs to replace. So that would take us down to 260,000, 265,000 is what we would attain and then the gap would be the shortfall in Tupper. But we would have also unlocked a large amount of capital, I think, to be able to redirect to these other plays. So I think we have a good chance to call that back in terms of production and certainly, in terms of value in other plays. So I'm still not worried about the 2015 target, because I think we have some flexibility. The important thing for me was getting on this quickly and getting on this decisively and then redirecting our spend, and the guys that run that program have been right on it. So I'm comfortable where we're going.

Okay. And with the discovery over at Rotan, is there a potential to maybe accelerate that production? In other words, I think the original target was first production in 2015. Could that potentially fill the void?

It could. I don't know that bringing that thing forward -- I mean it's -- I'd like to stick with that late 2015, 2016 date. But I think proving up more resources there, so now we have Rotan. Now we have Bulu, which is this well we've just drilled. We have Bunga Lili as prospect. We'll get to spud right now. We have some other resources, and we de-risked a lot in that area. I think the size of that facility is really what we're studying now. So rather than quicker, I think it could potentially be bigger, but that's part of the discussion that we'll have. But it's good news. I mean, it's a nice looking well log and so forth, so I'm happy about it.

Sure. Okay. The last one for me, David, and this a little bit more strategic in nature. But we heard from one of your peers yesterday that has had a, I guess, you could say a lack of exploration success over the years and basically trying to minimize their exposure to exploration. Given the, I guess, you could say lack of success from Murphy, is there any change in your philosophy on deploying capital into the exploration program going forward?

No. We spend about 20% of our capital on exploration, and I think that's a comfortable level for us to do. We've had years where we've been quite successful and years where we've been not successful at all. Last year, we only drilled 4 exploration wells. The problem, I think, last year was 4 isn't the right number. I think we need to give ourselves an opportunity here to let the numbers work for us and drill a dozen, and that's kind of what we're going to do this year as we set out. Of course, drilling and discovery with the first well which you drill in the year always sets a good tone, albeit not a big discovery. So I think exploration for us is something we have managed. We're comfortable with the dollars we exposed, and I see us doing that going forward. Whenever we have failures, you got to understand why you have failures and make adjustments, and our guys are smart to be able to do that. So I think we'll keep doing it. I think today as opposed to say 3 or 4 years ago, having this North American resource footprint with its predictability and flexibility is a very good thing for us, but I don't know that I'd want to do that 100% of the time.

We'll take a question from Paul Cheng with Barclays Capital.

A number of quick questions. Dave, seems like that you have been pulling the rigs down. So at this point, that you're still producing oil out on your North American gas even at 2 40? Because I'd assume that you're actually losing cash at 2 40 or that you have shut in any well.

Well, we haven't shut in anything, and we have some gas forward sold, Paul. So I think our average price is north of $4 right now, so that's kind of the situation. If you look at our operating costs up at Tupper, it's in the $0.60 to $0.80 range.

Right. But I mean, the forward sales, I mean, in theory, that even if you have no production, you can still monetize those. So you doesn't necessary need to have the physical MCF to go with that contract. So I mean if you're looking at what your cash cost -- I mean, my guess is that in the cash price at 2 40 -- I mean can you mention that anyone actually making cash from that? So I just curious that whether that make a decision that you may just shut in and liquidate the order, get the payment from the future contract.

Paul, I don't see us shutting in, because I don't know we're smart enough to know exactly where gas prices are going to go between now and, say, the middle of the year. Are we looking at it closely? Sure. That's what I've just been addressing, redirecting capital. But I think we're still making a little bit of money here, so -- and I think it's smart not to knee-jerk react to these things and take a longer-term view. The nice thing is it's a great asset below ground. It operates great above ground. And so a little bit of price support and it'll do fine, so -- but I'm not into the knee-jerk reaction here.

Right. And on the longer-term basis that -- can you just remind us, to get to the 2015, your target of 300, are we assuming about $3 billion, $3.5 billion a year in CapEx?

Yes, it'll be a little -- it'll go up and down. There's pretty big spend there in Eagle Ford, which runs between $1 billion and $1.2 billion a year. Paul, that's one of the biggest components. And I think the spend is $3.5 billion to $4 billion, but that includes exploration dollars in there. I'm speaking from memory here.

Okay. And on the retail separation, what do you currently leaning towards? Is it going to be just a spinoff to the shareholder, because it's more tax effective? Or that you may want to just IPO it? Or that's just trying to sell the operation? I mean, which way that -- what is the consideration is going to look like?

Paul, those are all great questions. Those are all the things that we're looking at right now. And as we go forward, we've got to look at that and we've got to look at the impact on the corporation as we are now. And so all of those things are on the table, and what I've said is that I think it's a valuable business. I don't know that it's valued within us. I'm pretty convinced it's not, and so we're going to look at what we should do going forward. And so all the things that you suggested are kind of on the table, and we're actively working on that.

And, Dave, do you have a rough time frame that you can share with us that -- when do you going to make a final decision on that?

We're going to talk with our board here this year in the first half of the year. So I would suspect that sometime by the middle of the year, we'd know what we're going to do and what the timeline is.

Okay. Perfect. And in the Kikeh production in 2012, what was your current assumption for 2012 Kikeh? And also that I think due to the performance at North add [ph], I think Kikeh, current plan is that you're going to spend about $1 billion more than the regional investment during an additional 16 well. How much of them will be spend in 2012?

Yes. We're actually drilling more wells in total at Kikeh for some different reasons. Some of the wells -- so I think 12 wells this year. Some water injection wells. Five of the wells are going to be accelerated wells, because the deeper horizons didn't water out as quickly as our original development. And so rather than waiting on those, we're going to do some additional investment. So some of the wells are acceleration wells from our original plan. I think when we originally sanctioned Kikeh -- and Paul, I'm talking from memory here, which is always dangerous -- we had about $1.8 billion capital for Kikeh, and I think that number now is going to be closer to $4 billion in total. Part of it is costs have gone up considerably since we sanctioned this at $21 oil, and part of it is that we've added new wells and the workovers that we had to do last year. But oil prices aren't $21 today either, so it's still a pretty valuable project for us.

Sure. So the actually increase is not $1 billion. It's actually $2.2 billion. Any idea that how much of them has been spent this year? And how that -- the additional spending, is it going to be spread evenly over the next 5 years? Or that the -- how's that just going to look like?

I can get you -- I can get Barry to give you the exact numbers here, but it's going to be kind of the next 2 to 3 years primarily, is kind of what I have in my mind from going over it, Paul.

Okay. I mean, Barry, if you don't mind, just give us a quick call or shoot us an e-mail in terms of the number.

Will do.

And final question. On the exploration fund, I hear what you just said. But when I'm looking at your current production base, roughly about in the 200s. You'll be going to spend about in the $400 million. I think that, that's what you guys historically spending. That's about a little bit over $5 per barrel. So you actually think that, that is the appropriate amount of the spending or that this needs to be a little bit lower, particularly given that you look like you have some very good position in the non-conventional shale plays. So should we be able to assume that, as a result, you need to rely lesser on the historical exploration program?

Paul, you're absolutely right. Now that we have a meaningful-sized resource program with its kind of minimal below-ground risk, that clearly is going to become more important for us. If I look at this year, just in exploration drill dollars, we're about $175 million. The larger number that you talked about, which is what we call exploration cost, includes other things like seismic and leases and all that other stuff. There's always a lag between making those sorts of spend and drilling wells. And so I'm comfortable at this 20% of total capital number in an exploration program, knowing that it's not all drilling in any one given year. One year, we may be picking up leases in Kurdistan, for instance, with signature bonuses and then drilling later. So I think you have to populate an exploration program with enough dollars and give it enough time to allow it to be successful. And I think the amount of capital that we're putting in is appropriate for us, and over the long term, I think we'll be successful.

We'll now move to a question from Mark Gilman with The Benchmark Company.

A couple things. David, that new block in Suriname that you've recently taken down, I think you took it down in December, can you talk a little bit about the play types that you're looking at, relative to both what you tested on the original block as well as the trends for margin play?

Yes. So this is outboard of the block that we drilled the 2 wells on, which were dry holes. The primary reason for them being dry holes was updip seal issue. We believe that this block for the outboard and further down the slope has better opportunity for updip seal. It's also closer to the kitchen, not that, that distance means that much. It's really this updip seal piece that I think is the most important. So we've been doing 2 things. We've been working the block that we had and drilled the 2 wells on to see if there's an understanding that we can gain there, and then also recognized that perhaps the play is a little better further outboard, and that's the reason for picking up the block. And at the same time we picked up this block, there was 3 other blocks picked up right around it. So I think several players now are getting comfortable with some of the key elements in the play, and we were just part of the group that kind of went out there and recognized this area with potential. So we've got to shoot 3D seismic, Mark, and so that's going to be kind of the next game and then ultimately, go into drilling.

So the play concept is analogous to, say -- or there are play concepts on the block analogous to today is [ph]?

Yes. I don't -- I haven't seen any data on that particular discovery. But understanding what the play is about, yes, I would say that this area has similar elements, but I don't have 3D. And once I get 3D, I think we'll have a much better idea of exactly what we're going to drill. But similar type of things, yes. The critical issue, updip seal, we believe is better addressed in this particular block.

Okay. Yes. David, can you, at least in general, preferably in quantifiable terms, talk about the source of the reserve adds and in particular, the size of the Azurite reserve hit?

Yes. Azurite was kind of not very much, Mark. I think we took down that field by 5 million barrels and took it down to 2 million barrels, so it wasn't large to start off with. Our production last year started the year near 8,000 and ended at 3,000 barrels, and we've kind of kept that level this year. So it's actually, on a net basis, a pretty small field for us. So that was the order of the magnitude of the change.

And the source of the adds, if you could just talk about some of the larger contributors. I mean, I assume Tupper was the biggest.

Yes. So if we look at the top 5, we have Tupper. We have Eagle Ford, Kikeh and Schiehallion. So those are the makeup. It's slightly weighted towards oil, close to 60% versus gas, 40%. The gas is clearly all in Tupper.

David, could you talk for a second about the relationship between the CA-1, the first well on CA-1, relationship, if any, between that well and your Lepu discovery of some years ago?

The well that we've just drilled didn't have any reservoir and -- which is analogous to the 2 wells that we drilled in CA-2. So I think the question really is, where is the reservoir package? Was it there and then wiped out by these mass transit deposits? Or was it just not deposited? And so those are the critical technical questions. Clearly, just to the east, both the Kakap, Gumusut and at Kikeh, the reservoirs are well developed and highly productive. And so I think there's an understanding yet to be gained as to where we need to go next.

And was there any relationship in turn from the conceptual standpoint to the Lepu play type?

All of the plays here are similar, that they are large, thrusted features of about the same age. They are younger when you go into the western block than in the eastern block, because that delta system was deposited separately. So depth of burial is about the same; age, slightly different; mechanism of deposition, about the same; mass transit deposits, about the same issue. So I would say there's a lot of similarity here as we look along the margin.

We have a question from Evan Calio with Morgan Stanley.

Sorry if I missed it if it was covered, but -- and congratulations on the encouraging well results in Alberta Bakken. But can you provide more color? I mean, is this a different portion of your acreage formation? And while it's early, what might it mean in terms of your potential exposure on an acreage basis or ability to add?

Yes. We're -- we have a pretty reasonable acreage position here. It's north of 150,000 net acres, Evan. This good well that we've just drilled is actually in the Three Forks, so it's not in the Bakken. And whether that's the key or not, I don't know. I don't think I'm smart enough to know yet. But when you see a good well, you kind of follow it, and it was kind of a funny way to get it. When we were drilling this well, we were drilling it for the Exshaw. And we drill it vertically and then the idea is to cut a core in the Exshaw and then turn the well with a heel tie horizontal. But we realized when we went into the Three Forks underneath, that was the place with the best shows. And not trying to outsmart ourselves, our guys said, "Well, why don't we float test the one that has the best shows rather than stick with prognosis?" And as it turned out, the well has been on production 42-plus days. We choked it back after a few days, and its pressure stayed almost flat -- actually, flat and has hung in just under 300 barrels a day. So we're pretty excited about what it means for that particular play, but that wasn't really the play that we picked up the acreage for. So we're in the process of kind of getting all the stuff together, understanding what it means and understanding where we need to be. But we have a pretty nice acreage footprint, and we have a piece of information, I think, that's important. How important, I think we've got to work out, but it's still early days yet.

That's great. On the -- are the FLNG discussions in a parallel process? And I'm kind of shifting to Block H. And when can we expect to kind of hear something on the structure and cost, et cetera? Because I know there's -- there are various less capital-intense alternatives in the FLNG market to finance that facility.

Petronas are kind of a world leader in LNG, and of course, we have, with our long-term relationship there, a very good working relationship. And we've been in active discussions with them for quite a long time here on doing this, and so we're quite advanced in those discussions. And so I would think that sometime this year, we would reach a conclusion there and that we would have a plan going forward. And so, Evan, I'd say once we have that, then we'll be able to say, "Hey, this is the time frame. This is where we're at, and this is what we're looking to do." But it's -- part of our effort is to make sure there's enough resources for whatever size facility is being envisaged, and that's what we're doing. So I'm very happy with what we've got here. I'm very pleased with how the negotiations and discussions are going, so I expect something to be announced here this year.

Okay. Any -- do you have an update on the Congo exploration farm-out process and any date when you expect to secure that rig? I think Cobalt's still over the first well in its 3 slots.

Yes. We've got a number of companies that we're in an active dialogue with. That's really all I'll say about bringing a partner in, but I've been very pleased with the degree of interest. We're clearly keen to get that well spud as soon as possible. The rig which is -- our rig that we took from the Gulf is contracted to come back to us in the first quarter. And so we're just going to work out timing of when we get that rig back and when to spud the well, but we're pretty keen to get this thing up and running here. So I think everything will align pretty nicely.

Okay. So a second-half well?

Yes. Results, second half. I think that's exactly right.

And then just lastly, as you give -- you paid down some debt in the quarters and just curious if your view had changed on potential redeployment of capital from the downstream asset divestitures into potential acquisitions or spending organically. What's your thoughts were or current thoughts were there?

If we could add some opportunities to the asset base, God, Evan, I'd love to do that, and we have an effort to do it. So if we can make an acquisition here that fits, I would. We are looking to redeploy some capital from the dry gases that I talked about earlier, so that's going to help us in some of these other areas. So -- but we're in the game to look, and we can add some things I would spend, and we've got a nice war chest here. Mindy's pockets are almost too full, and so we got to find a place to spend it, but we're in good shape.

Okay. Maybe -- just one more if I could. On Azurite, is there any production in 1Q? And was there underlift there that kind of liquidates...

Yes. In terms of production, we forecasted something just above 3,000 barrels a day for the year. So the field's still producing. That's our net number. Because it's at a relatively low rate, the liftings don't come very often, and we've just had a lifting. So Barry's scratching around here for the schedule, but I suspect we've got a couple more liftings between now and the end of the year, is what I think.

And we are a little bit underlifted here in the first quarter.

We'll take a question from Gene Gillespie [ph] with Gillespie Consulting Group [ph].

A couple of things here. One, you've referred to the separation in retail, and there were comments in your press release saying that you're evaluating -- in 2012, evaluating your presence in the Gulf of Mexico, and -- which begs the question, to me, is where is the U.S. income going to come from to pay Kevin's salary and more importantly, the dividend?

Well, I think, Gene, that's a great question, and it's one of the ones that we're looking at. And so the Gulf of Mexico has been a historically active business for us, but it's kind of changed here recently as to what we can get done and what value it is to us. And so naturally, when you have that situation, you look at it. So that's on the table to look at. The retail business is on the table to look at for reasons that I've discussed before. Kevin loves it here so much, he's offered to work for free. So I think I've got...

There you go, the big picture there.

I've got him solved. The dividend, we have plenty of money within the corporation, but there's clearly issues of offset of foreign exploration, and also, dividend money is available. And so that's all part of the look that we do, Gene. So you're absolutely right, and it's right on the table, front and center on my desk.

Good enough. One last thing. I think in prior conferences or discussions that you guys had indicated that you would reached -- excuse me, reach the 300 million barrel threshold on Block K sometime around 2014. Is that still a good time? Or is it delayed further out now?

Yes. The way the profile has changed, particularly on Kikeh, it is kind of the end of 2015, 2016, Gene, is when we reach that 300 million barrel threshold volume point.

We'll take a question from Paul Sankey with Deutsche Bank.

David, obviously, your strategy is all towards becoming a -- I guess a North American E&P with international operations and exploration. Can you just quantify the benefits of that? And obviously, I'm thinking about tax.

Yes. That's all part and parcel of this look that we're doing here with the retail and with the Gulf of Mexico and other parts of our business, and if we buy something, where do we buy it. So all those strategic things, Paul, are things that we're kind of looking at. I think there's a suite of opportunities available here in North America. And we started to touch a number of them, but there still is a pretty nice suite for us, exploration type of opportunities outside of North America, and we'd still like to have exposure to those. So I don't see us not doing that.

And I guess that was what I was referring to is the potential for IDCs and the status of how much cash tax you'd be paying.

Oh, I think you're starting to dig down here into the weeds, and we're just up at the strategic level here, Paul. I think your question is a great question. It's an appropriate question, and like the other one, sits on my desk. So we'll be looking at all of that.

Got you. And just to reiterate, you said that you -- I guess the U.K. refinery process is ongoing. Retail is on your desk, but the general expectation is that we could get this cleared up, if you like, by midyear.

Yes. The retail in the U.K., the refinery, that process is ongoing. It's been slow because of the external environment. Now here, with some of the capacity that's going off in Northwest Europe, margins and people's outlook has kind of changed. So quite naturally, people have been engaging with more interest now. So I still see that as a process ongoing. As I said in my comments, if we go ahead with this retail separation, then that refinery, as a terminal, not as a refinery, would be part and parcel of that. And so we've been spending quite a bit of time and effort looking at making that conversion, so all of that is kind of ongoing.

Great. And forgive me. I believe you've already said this but just to reiterate, I think you're at -- you're expecting 200,000 barrels a day of production in 2012. And can you just confirm how much -- how the moving parts within that have shifted what you're expecting from Kikeh, how much you expect less now from Congo versus when you previously gave that guidance? I guess you mentioned some of the potential for less activity in North American gas. If you could just kind of run through, a, if that's the number? And I can't help but ask what the exit rate for 2011 was, as well, of your volumes.

Paul, the way it looks here for this year kind of by quarter is the 195,000 is our guidance for the first quarter. So that means you got the average 202,000 for the remaining 3 quarters. That gets you to the 200,000. I feel pretty good about where we are today. If I look at January, so as of yesterday, we're a little bit better than the guidance for the quarter, but we have some swings. We've had days as low as 175,000 and days as high as 210,000, and a lot of it depends on rig moves and weather and all this kind of stuff. But I feel pretty good about where we are looking forward. I think Kikeh, which was one of the main issues we had to manage last year, is in a much different situation now than it was. And now, we have rigs on location, working. We have the sand/fines issue, I believe, behind us. And so I see Kikeh being in near 80,000 gross a year, and it'll have some ups and downs. The gas component, as I mentioned earlier, if we slow down our spend significantly this year, it won't really have much impact on production, 3,000 barrels a day if we cut about $160 million of spend in that program. So it won't have that much. That is in the 200,000, and so we'll have to look to get that from somewhere else. In terms of Azurite, Azurite only has 3,000 -- a little over 3,000 barrels a day in that number, and it's still producing. That's -- the issue with Azurite was the write-down of the barrels that wasn't in the production. And we've known what the production curve of Azurite was looking like, and so we've already got that factored into this 200,000 number. So Azurite is not a factor, Paul, in what I see.

That's very clear, David. I was wondering, what's the price of gas required for reinvestment at Tupper and other places in the U.S. in your portfolio?

Well, for us it's really just Tupper. It's the only dry gas place that we're actively working here, and something in a $2.60 range is probably what you'd want to see at the plant.

So what would that be on the screen, then, at the NYMEX or the Henry Hub, I should say?

Well, AECO price would be about $2.90.

Okay. And at that point, it would be economic to pursue growth.

Then you get into the discussion of, what the heck are you doing that for when you got all these other good places to spend money? And so my simple answer is I've got a lot of better places to spend money than chase $2.90 gas.

Okay. So it's also a function, obviously, of the oil-gas ratio.

Yes. And...

It's just a big -- it's obviously just a big question. I'm sorry to interrupt. It's just a big question for us in terms of where -- how we rationalize the U.S. gas market and the kind of price below which we begin to see significant step-downs. But it sounds like your number would be a lot higher than $2.90. I mean, you wouldn't consider reinvesting there. I don't know. What's the number? It must be much higher than $2.90.

Yes. The number I was giving you was just kind of the base number. And so when you have opportunity, for instance, in areas of the Eagle Ford that are -- have a little bit of gas component, your overall economics are determined more by your liquids piece than they are by gas. And I think that's the overall problem, if you will, in gas supply in North America is associated gas. The problem with Tupper is it's dry gas.

And that will conclude our question-and-answer session for today. I would now like to turn the call back over to Mr. David Wood for any additional or closing remarks.

Operator, thanks a lot. I appreciate everybody dialing in and look forward to the next quarterly call. Thanks, everyone.

Thank you. That does conclude today's teleconference. We do thank you all for your participation.