Murphy Oil Corp (MUR) 2011 Q4 法說會逐字稿

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 Treasure; Barry Jeffrey, Director of Investor Relations; and Tammy Taylor, Assistant Manager of 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 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 two US 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 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 the Republic of the Congo. Poor well performance led to a cut in proved reserves at this field in 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, the E&P segments, we had income in the fourth quarter of 2011 of $139.9 million -- loss of $139.9 million, versus income in the fourth quarter of 2010 of $154.1 million. The lower earnings in the 2011 quarter were mostly attributable to the previously mentioned impairment at the Azurite field. Fourth quarter 2011 also included higher exploration expenses but the quarter benefited from higher realized prices for crude oil and Sarawak natural gas. Crude oil and gas liquids production averaged approximately 108,800 barrels a day in the 2011 quarter, compared to about 117,100 barrels per day last year. The decline is primarily a result of lower production from Kikeh in Malaysia and from Azurite. Natural gas volumes were 488 million cubic feet a day in the fourth quarter 2011, compared to 365 million cubic feet a day in 2010, the increase primarily due to higher production from the Tupper area in Western Canada and from Sarawak, Malaysia.

In the R&M segment from continuing operations we showed net income in the fourth quarter of 2011 of $61 million even, compared to net income from continuing operations of $19.8 million in the fourth quarter of 2010. The main drivers of the income increase for the 2011 quarter were stronger retail marketing margins in the US, and improved refining and marketing margins in the UK.

The Corporate segment we showed a net charge of $34.4 million in the fourth quarter of 2011, compared to a net charge of $24.4 million in the fourth quarter of 2010. In 2011, we experienced higher foreign exchange losses and higher net interest expense. Capital expenditures for 2011 totaled just under $3 billion. Approximately 94% or a little of $2.7 billion was spent in the E&P segment, approximately $863 million in exploration, of which about $300 million was in lease acquisitions, and the remainder for development projects with the Tupper, Kikeh, and Eagle Ford Shale projects accounting for over half of the expenditures. For 2012 our budgeted capital expenditures which were approved by our Board in early December totaled $3.5 billion with approximately 94% or $3.3 billion slated for the E&P segment. Of that, approximately $3 billion is for development projects, the remainder or about $300 million is to be spent on exploration activities. Our budget assumes WTI pricing of $85 per barrel and Henry Hub pricing of $4.25 per Mcf. Dave will elaborate a bit further on CapEx in his comments.

At year end 2011 Murphy's long-term debt amounted to approximately $250 million or 2.7% of total capital employed, while cash, cash equivalents, and short-term investments in marketable securities totaled a little over $1 billion. With that I'll turn it over to Dave.

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 the US government debt. 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 the 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 mid-term, we do expect pricing to be under pressure throughout 2012. I see us redirecting the 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 two years removed from the unfortunate and tragic events of the Macondo in the Gulf of Mexico and while the pace of the play has improved, new permits require higher levels of man power and much more time to complete. That coupled with fewer rigs makes for much slower and for us a smaller Business. This year we are lined up to spud in February a new development well at our Thunder Hawk field.

Given this backdrop, 2011 saw some significant achievements for us as we established framework and began executing on our plans to reposition Murphy Oil as an independent E&P company. We successfully closed on the sale of the two US refineries at the end of the third quarter and are now focused on the disposition of the UK refinery at Milford Haven. We are also evaluating the potential to separate our retail business and to unlock its value which we believe is unrealized within the current Corporate structure.

Activity in our North American resource program ramped up in 2011 as we grew this position to complement our global exploration portfolio. This resource program now extends over 800,000 net acres with our entry into a fifth play where we have just spudded our first well. We currently have 16 rigs drilling in North America, 7 in the Eagle Ford, and 9 in Canada. Our on-shore North American business is now organized as a single unit to bring expertise and complementary disciplines from our successful Montney development program to the accelerating businesses in the Eagle Ford Shale and Seal. In the Eagle Ford Shale we exiting the year near 9,000 barrels of oil per day net as we ramped up our rig count from three to six over the year. We now have seven rigs running and will add two more by early March and average eight for the year.

To date we have drilled 56 wells with 9 awaiting fracs. Well results continue to be very encouraging and are trending better than our type curve for wells in the play. Costs are being worked down with improved service contract terms as well as improved efficiencies in drilling and completion operations. I expect to see further improvements in cost as gas rigs and equipment stand down across industry this year. Production growth at Seal Heavy Oil project in Northern Alberta is moving forward at an accelerated pace as we focus on additional development drilling, down spacing opportunities, multi-leg laterals, and advancing our EOR projects. Current production levels at near 9,000 barrels a day and we look for a steady growth profile going forward with the currently planned exit rate near 13,000 barrels of oil per day. We have plans to run three to four rigs this year but I expect this will be revisited as we move rigs away from gas-only areas.

While our south Alberta play has witnessed mixed results early on, we have just seen our best well come on production. It IP'd at over 300 barrels a day and has naturally flowed for 42 consecutive days near that level on a small choke. It's high-quality oil and we are budgeted to drill and complete two more wells in this play this year, with an ongoing review to increase that number based on this recent good news. We have also entered a fifth North American resource play and are continuing to build a land position which currently stands at well over 100,000 net acres. We are drilling our first well in the play now and expect to be able to discuss it more in detail by the next quarterly update.

Activity levels and results from our exploration program were disappointing in 2011. For the year we drilled four wells, testing targets in Suriname, Indonesia, and Brunei. The process of lining up rigs and finalizing well schedules pushed some activity into this year. So I expect to see 2012 as a more normal 12 to 15 prospect program. At year end we were active on two wells in Brunei, both are finished now and expensed as dry holes having failed to find reservoirs. It's still early days there and I expect further drilling to take place this year. In Malaysia we have just reached TD on an exploration well in Block H and made a nice gas discovery that will be developed as part of the Rotan Floating LNG program. It's a good start to 2012 and will be followed up with another nearby and larger potential feature.

The big upsides prospects for this year will come later. [Making] prospects in Congo, Iraq, and Australia. 2011 fell below expected production targets. We have reorganized this function under a single executive to ensure consistency of reporting and implementation of an improved process. Part of the issue continues to be too few wells and individual fields having an overly significant impact. This situation will improve as we continue to ramp up production and contribution from our North American resource program.

Fourth-quarter production averaged 190,100 barrels of oil equivalent per day, with December averaging 196,900 barrel of oil equivalent per day, that included a high rate in the month of 213,000 a day. We did see improvement in the ability to predict production from our assets in the quarter with most of the miss in production for the fourth quarter being attributed to nonoperated fields or third-party downstream operated facilities. Looking at previous guidance for the fourth quarter, we undershot by 8,000 barrels equivalent a day of which almost half was due to obstructions in the nonoperated Kikeh gas export pipeline and unrelated to the oil production from the Kikeh facility. Kikeh was producing near the 70s at year end as we were waiting to bring on delayed completion. That well should be on shortly. The gravel pack work-over program at Kikeh to remediate the sand fines migration issues has been successful with no further issue and we see that field on track for this year.

Production for 2011 averaged 179,400 barrels of oil equivalent per day. This was just under our yearly guidance and mainly related to delays in returning wells to production at Kikeh and the gas export line issues I just mentioned. A further portion of the miss was related to lower production levels at Thunder Hawk in the Gulf of Mexico where we were delayed in obtaining development well permits. The core production performance at Azurite in the Congo also contributed to the miss.

Reserve replacement for the year was strong at over 200% as we were able to book significant reserves from our North American resource play in addition to Malaysia adds with the new projects we sanctioned in 2011. In business development, we continued to add new growth opportunities and replenish our inventory of prospects with the new entry in Cameroon, West Africa. We also added a new block at Suriname and are actively engaged in adding acreage in Vietnam. Our US downstream business turned in a steady performance for the fourth quarter with $51 million of net income, despite a difficult month of December. The US business had a very solid year, turning in net income of $223 million, and cash flow of $414 million, the second highest in our history, building upon the most profitable for six-month and nine-month periods ever.

Buildout of our chain continued with the addition of 29 stations bringing the total number of retail outlets to 1,128 at year end. Our US retail chain broadened its partnership with Walmart and participated in the $0.10 per gallon roll back program on gasoline prices from June through September. Longer term we are excited about the opportunity to expand both within and outside our current footprint with Walmart.

In renewable energy we completed the construction and upgrades to the Hereford, Texas ethanol plant and started up at the end of March on schedule and budget. Startup and commissioning went well and the plant has ramped up to its name plate capacity of 105 million gallons per year. Operations at our Hankinson ethanol plant continue to be reliable and production rates have been steady at the 120 million gallons per year range. This business contributed over $18 million in net income, $31 million of cash flow for the year. Chicago crush spreads averaged $0.39 a gallon for the fourth quarter, and $0.20 a gallon for the year. Although corn prices exceeded $7 a bushel, during the year the cattle feed bi-product kept pace to more than cover operating expenses and contribute to earnings. Focus here is safe, reliable operations as the market rebalances in the absence of the ethanol tax credit.

Our UK retail business continued its steady performance and contributions. Northwest Europe refining margins remained under pressure for much of the year with some recent improvement linked to capacity coming offline in the region. Milford Haven refinery divestment process is ongoing and in the absence of an acceptable offer we are evaluating the potential conversion of the facility to a terminal with its excellent location, water access, and storage capacity of over 9 million barrels.

For 2012, we will see an active exploration program aimed at testing at least a dozen prospects. During the year, important prospects in Kurdistan, Iraq, Congo, subsalt and Australia are scheduled. We also have two prospects to drill in the Gulf of Mexico pending rig availability and permitting, two more Block H wells in Malaysia are budgeted in support of that [Y fleet] FLNG development.

Our total capital budget for 2012 as Kevin mentioned is $3.5 billion, with over $300 million earmarked for the exploration program. $3 billion will be spent largely on development projects with $1 billion slated for the US, primarily in the Eagle Ford Shale. A further $700 million in Canada of which $200 million is for Seal heavy oil development and $300 million is budgeted for Montney. $1.2 billion is budgeted for Malaysia, with $600 million for Kikeh field development and $465 million for Sarawak oil and gas projects, and $120 million for Kakap and Siakap North development. I expect some movement here especially in North American dry gas as we respond to current low prices. The downstream business is budgeted $200 million to cover 15 new station builds and other upgrades.

Production guidance for the full year is 200,000 barrels of oil equivalent per day, which represents an 11% increase over 2011 volumes. Production increases will primarily come from growth in our North American resource plays such as Eagle Ford Shale and Seal as they ramp up activity with the Montney gas production staying at full capacity for the year along with stabilized rates at Kikeh.

In summary, we're off to a good start in 2012, building upon the improvements seen last year. Average production for the year of 200,000 barrels of oil per day is on track as I speak here at the end of January. Kikeh work-overs to remedy sand fines have been successful and the field is on track for the year near 80,000 barrels a day gross. We have made our first discovery of the year in Block H Malaysia adding to an important resource base there and derisking a number of other prospects. Our Southern Alberta efforts have seen the first good well and we look to step up the evaluation of that large-acreage position. We have just spud the first well in our new on-shore resource liquids play with more news to follow. Impactful prospects will be drilled throughout the year with the notable wells as I mentioned in Congo, Australia, and Kurdistan having big upsides. Reserve booking for 2011 was strong at over 200% of production replacement.

US retail continued its excellent performance and provided a solid contribution in 2011, and is well poised for future growth. The repositioning is on track, and we will evaluate the potential separation of our downstream retail this year. That concludes my prepared remarks and I'm now happy to take your questions.

(Operator Instructions). Arjun Murti, Goldman Sachs.

David, it sounds like the Kikeh program has gone well in terms of the work-overs. Is there anything left to do or is it now done in terms of getting everything back on line?

Arjun, Kikeh's a great field but we've 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 plan so we've got a pretty active program this year. I think we'll drill 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.

As far as the work-over program it sounds like that is now complete and behind you.

Yes, as we sit here today I feel in pretty good shape with that field. At 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 much better today.

And then two 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 in the Eagle Ford. Thank you.

So Southern Alberta we drilled six wells and we wrote off five of them. The sixth well is actually a pretty strong well. The thing you need to appreciate is it's actually not in the actual, 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 has shifted 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.

That's terrific. Thank you so much, David.

Leo Mariani, RBC Capital Markets.

You guys addressed obviously weak gas prices here, discussed pulling rigs potentially away from the Montney, redirecting them to other areas. Clearly, gas has been pretty weak, below $3 for I guess several weeks now. Is there a plan to do that in the very short term? Can you just give us some kind of thoughts on timing 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?

That's a great question, it's one that we're working now; actually been pulling rigs off of Tupper. Let me kind of say what the budget for this year, next year is and the impacts of what we think's 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, 2013, where we were budgeted about $430 million of CapEx, we build 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. 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 realized that when I said what the rig count was and the fact that we spudded a well on our new play realized that the play's 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. That's kind of the name of the game for us as we look at the next two years for dry gas.

Okay. And I guess clearly as you redirect capital, I'm assuming that the effects on the productions, that's just losses in the gap, clearly 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 take-away on the Southern Alberta basin, clearly 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 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. 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 claw 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 will be kind of a win for us.

Okay. And I guess in the Gulf of Mexico, you guys talked about probably having some delays in 2011. I think you mentioned spudding 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 will impact production this year in the Gulf will be the well at Thunder Hawk and so we're anxious to get on with that. We have a rig lined up here in the first quarter to get that started.

Okay. Thanks a lot.

Blake Fernandez, Howard Weil.

Question for you, David. You just covered I guess the 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 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's project 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. Maybe we defer that and go with a lower volume.

If you look long-term, we 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, incremental little over 20,000. So 60,000 BOEs from that area is dry gas. Clearly, if we slow the investment, it will decline but it won't be zero. 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 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 at 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 claw that back in terms of production. And certainly in terms of value and 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.

Okay. And with the discovery over at Rotan, is there 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're getting to spud right now. We have some other resources and we've derisked 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're having. But it's good news. It's a nice-looking well log and so forth so I'm happy about it.

Sure. Okay. The last one from me. David, this is a little more strategic in nature but we heard from one of your peers yesterday that has had 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. 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 were not successful at all. Last year we only drilled four exploration wells. The problem I think last year was four 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 a discovery with the first well that you drill in the year always sets a good tone, albeit not a big discovery.

I think exploration for us is something we manage. We're comfortable with the dollars we expose and I see us doing that going forward. Whenever we have failures you've 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, three or four 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 would want to do that 100% of the time.

Got it. Thank you very much.

Paul Cheng, Barclays Capital.

Number of quick questions. David, seems like you haven't pulled any rigs down. At this point that you're still producing oil on your North American gas even at $2.40. Because I assume you're actually losing cash at $2.40 or that have you shut-in any wells.

Well we haven't shut-in anything. We have some gas forward sold, Paul, so I think our average price is $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.

But the forward sales, I mean, varied. Even if you have no production, you can still monetize those, so you doesn't necessarily need to have the physical Mcf that to go with the contract. So I mean, if you're looking at what your cash costs, I mean, my guess is that in the cash price at $2.40, I mean, [Kevin] mentioned that anyone actually making cash from that. So I'm just curious whether that makes a decision that you may just shut-in and liquidate it or get the payment from the future contract.

Paul, I don't see us shutting-in, 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. 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. So a little bit of price support and it will do fine. I'm not into the near jerk reaction here.

On the longer-term basis can you just remind us, to get to the 2015 year target of $300 million, are we assuming about $3 billion, $3.5 billion a year in CapEx?

Yes, it will be a little -- it will go up and down. Pretty good 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, speaking from memory here.

And on the retail separation, what are you currently leaning to? 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 you're trying to sell the operation, 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 then 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, 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.

David, do you have a rough time frame that you can share with us that when you're 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 would know what we're going to do and what the time line is.

Okay. Perfect. And in the Kikeh production in 2012, what's your current assumption for 2012 Kikeh? And also I think due to the performance, I think Kikeh current plan is that you're going to spend $1 billion more than the original investment, drilling an additional 16 wells. How much of that will be spent in 2012?

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 investments. 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 added new wells and the work-overs 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 actual increase is not $1 billion, it's actually $2.2billion. Any idea that how much of them has been spent this year and how that additional spending, is it going to be spread evenly over the next five years or how's that 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 two to three years primarily is kind of what I have in my mind from going over it.

Barry, if you don't mind just give us a quick call or shoot an email in terms of the number.

Will do.

And final question. On the exploration front, I hear what you just said. But when I'm looking at your current production base, of [roughly $1 billion to $200 million] and you're going to spend $1 billion to $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 proper amount of the spending or that it needs to be a little lower, particularly given that you look like you have some very good position in the nonconventional shale plays. So should we be able to assume that as a result you need to rely less 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 costs includes other things like seismic and leases and all that other stuff. And 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.

All right. Thank you.

Mark Gilman, The Benchmark Company.

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 plates heights that you're looking at relative to both what you tested on the original block as well as the transformed margin play?

Yes. So this is outboard of the block that we drilled the two wells on which were dry holes. The primary reason for them being dry holes was updip Seal issue. We believe that this block further 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 the updip Seal piece that I think is the most important.

So we've been doing two things. We've been working the block that we had and drilled the two wells on to see if there's an understanding that we can gain there. And then also recognized that perhaps the play's 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 three 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.

The play concept is analogous to say -- or there are play concepts on the block analogous to [Dedayis]?

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 exactly what we're going to drill but similar type of thing, yes. The critical issue, updip Seal, we believe is better addressed in this particular block.

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

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, we started the year near 8,000 and ended at 3,000 barrels and we've kind of kept that level this year. 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 five, 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, the relationship if any between that well and your Lithu discovery of some years ago.

The well that we've just drilled didn't have any reservoir and which is analogous to the two 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 at Kakap-Gumusut 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 terms -- from the conceptual standpoint to the Lithu 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 barrel 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.

Okay, David, thanks very much.

Evan Calio, Morgan Stanley.

Sorry if I missed it, if it was covered, but 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 or 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 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.

Okay.

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. It's kind of a funny way to get it. When we were drilling this well we were drilling it for the Exshaw. 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 guy said well why don't we flow 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 at 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 this 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. Are the FLNG discussions in a parallel process, kind of shifting to Block H and when could we expect to kind of hear something on the structure and cost et cetera? Because I know there's various less capital intense alternatives in the FLNG market to finance that facility.

PETRONAS, a kind of a world leader in LNG and of course we have with our long-term relationship there 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.

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. I expect something to be announced here this year.

Okay. 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. It's three slots.

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 first quarter and so we've just got 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, you paid down some debt in the quarter. Curious if your view had changed on potential redeployment of capital from the downstream asset divestitures into potential acquisitions or spending organically, what your thoughts were or current thoughts were there. Thanks.

If we could add some opportunities to the asset base we've got, Evan, I'd love to do that and we have an effort to do it. So if we could make an acquisition here that fit, I would. We are looking to redeploy some capital from the dry gas as I talked about earlier so that's going to help with us some of these other areas. 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 box pockets are almost too full. We've got to find a place to spend it but we're in good shape.

One more, if I could. On Azurite, is there any production in 1Q and was there any 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, Evan, 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.

Okay.

We are a little bit underlifted here in the first quarter.

Okay. Great. Thanks, guys.

Gene Gillespie, Gillespie Consulting Group.

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

Well, I think Gene, it's a great question and it's one of the ones that we're looking at. And so the Gulf of Mexico has been an 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 businesses is on the table to look at it 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 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 monies 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, you guys had indicated that you had reached the 300 million barrel threshold on Block K sometime around 2014. Is that still a good time or is it delayed further out now?

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.

Good enough. Thank you.

Paul Sankey, Deutsche Bank.

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

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've 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 still like to have exposure to those. So I don't see us not doing that.

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

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 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 UK 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 mid-year?

Yes, the retail in the UK, the refinery, that process is ongoing. It's been slow because of the external environment. Now here with some of the capacity that's gone 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 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? Thank you.

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've got to average 202,000 for the remaining three quarters that get 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 near 80,000 gross a year and it will have some ups and downs. The gas component as I mentioned earlier, if we slow down our spend significantly this year, 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. The issue with Azurite was the write-down of the barrels. It 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's not a factor, Paul, in what I see.

That's very clear, David. Thank you. I was wondering what's the price of gas required for reinvestment at Tupper, and other places in the US 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 the $2.60 range is probably what you would want to see at the plant.

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

ACO 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've got all these other good places to spend money. 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.

Obviously that's the big question for us in terms of how we rationalize the US gas market, 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. You wouldn't consider reinvesting there. I don't know. What's the number? Must be much higher than $2.90.

Yes. The number l 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 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.

Yes. Okay. I'll leave it there, David. Thanks a lot.

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.