Murphy Oil Corp (MUR) 2010 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Murphy Oil Corporation fourth-quarter 2010 earnings announcement. Today's conference is being recorded.

I would now like to turn the conference over to Mr. David Wood, President and Chief Executive Officer. Please go ahead, sir.

Thank you, Operator. Good afternoon, everyone, and thank you for joining us on our call today. With me are Kevin Fitzgerald, Senior Vice President and Chief Financial Officer, John Eckart, Vice President and Controller, Mindy West, Vice President and Treasurer, Barry Jeffery, Director of Investor Relations, and Craig Bonsall, Supervisor 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 2010 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 2009 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. Net income for the fourth quarter of 2010 was $174.1 million and $0.90 per diluted share. This compares to net income in the fourth quarter of 2009 of $318.8 million or $1.65 per diluted share. For the full year of 2010, had net income of $798.1 million, $4.13 per diluted share, compared to net income in 2009 of $837.6 million, or $4.35 per diluted share. There were no one [off] type items of real significance in the fourth quarter of 2010.

However, the 2009 fourth quarter did have a couple of them which included $185.3 million after-tax benefit that included after-tax interest income of $27 million and the recovery of royalties paid on certain deepwater oil and gas fields in the Gulf of Mexico. The interest income from that was included in our corporate segment with the remaining $158.3 million included in our E&P segment. The 2009 quarter also included a $31.3 million after-tax charge, associated with the reduction of our working interest in the Terra Nova field offshore Eastern Canada due to the redetermination process. Excluding these two items, income for the fourth quarter of 2009 would have been $164.8 million, slightly below our fourth quarter 2010 results.

Looking at net income by segment, in the E&P segment income in the fourth quarter of 2010 was $154.1 million, compared to $339.1 million in the fourth quarter of 2009. Without those special items mentioned just a bit earlier, the income in the fourth quarter of 2009 would have been $212.1 million. The lower earnings in the 2010 quarter were mostly attributable to the previously mentioned recovery of deepwater Gulf of Mexico royalties in the prior year, but 2010 also included higher exploration expenses. Again, the 2009 quarter was adversely affected by the Terra Nova redetermination charge.

Crude oil and gas liquids production from continuing operations averaged approximately 117,100 barrels per day in the 2010 quarter, compared to 138,300 barrels per day in 2009. Decline primarily a result of lower production from Kikeh in Malaysia. Natural gas volumes of 365 million cubic feet a day in the 2010 quarter compared to 306 million cubic feet a day in 2009. This increased primarily due to higher production from Sarawak, Malaysia and from the Tupper area in Western Canada.

In the Downstream segment, we had net income in the fourth quarter of 2010 of $44.4 million, this compares to a net loss in the fourth quarter of quarter 2009 of $4.1 million. The main drivers here for the income increase were stronger refining and retail marketing margins in the US.

The Corporate segment in the fourth quarter of 2010, we had a net charge of $24.4 million compared to a net charge in 2009 of $15.5 million. In 2010, we experienced lower foreign exchange losses and lower net interest expense, but the 2009 quarter also included the $27 million of after-tax interest benefit royalty recovery related to those Gulf Of Mexico leases.

Capital expenditures for 2010 totaled just under $2.5 billion. Approximately 83%, or a little over $2 billion, was spent in the E&P segment, about $700 million on exploration, of which about $240 million was in lease acquisitions, the remainder for development projects was Tupper, Kikeh and Sarawak gas projects accounting for over half of the development expenditures.

For 2011 our budgeted capital expenditures, which were approved by our Board in early December, totaled $2.2 billion, approximately 88% of which or just under $2 billion slated for the E&P segment. Of that, about $1.5 billion is for development projects, the remainder, or about $500 million, to be spent on exploration activities. Our budget assumes WTI pricing of $75 per barrel and Henry Hub pricing of $4.50 per Mcf. At year end 2010, Murphy's long-term debt amounted to approximately $939 million, or 10.3% of total capital employed, while cash, cash equivalents and short-term investments and marketable securities totaled a little over $1.1 billion. And with that, I'll turn it over to Dave.

Thanks, Kevin. Looking back 2010 saw benchmark crude prices range around between $70 and $80 a barrel. Breakout occurred in the fourth quarter with prices broaching the $90 mark, recently on the back of improved global demand and cold weather spikes in the Northern hemisphere. Most signs suggests this to be the new fulcrum point for the remainder of the year. Natural gas prices in North America languished through 2010 working downwards from $5 as the year progressed to hover near $4 as they are today. We expect natural gas pricing to be under pressure throughout 2011, with little move away from current pricing until the supply and demand better balance.

Our industry and our Company were impacted by the unfortunate and tragic events of BP's Macondo incident in April of last year. The Gulf of Mexico business was brought to a standstill for everyone and continues to be impacted as a result of the moratorium and now effectively a permatorium. We responded quickly to the impact on our Gulf business and made the decision to move the deepwater rig Ocean Confidence over to Congo to carry out our exploration program there. It is as yet unclear how the future of the offshore Gulf of Mexico will unfold.

Given this backdrop, 2010 saw significant achievements for us. Our Exploration program delivered 3 new discoveries from 8 wells drilled and found mainly oil reserves in amounts well above our produced volumes for the year.It did this all at a finding cost below our targeted $2.75 a barrel. Results for 2010 were very similar to 2009, and support our confidence that this program will deliver meaningful new growth in out years.

Towards the end of 2010, we drilled impact prospects in Congo which unfortunately came up short. We are now underway on our 2011 program and hope by the end of this year to be at least replicating last year's performance, plus have had some of our needle mover prospects also contribute.

Complimenting our exploration program with a solid North American resource play for oil and natural gas was a goal we carried into 2010. New acreage was added to our Eagle Ford Shale position as well as our (inaudible). We also added a new oil play, the Exshaw/Bakken in Southern Alberta, where our first well should spud very soon. This resource program now extends over 700,000 net acres and will in of itself add incremental reserves and production, providing a natural risk and timing balance to our exploration fuel production and reserve growth profiles.

New development projects continue to be brought forward and we sanctioned the first part of our Eagle Ford program before year end. This first one in Karnes County saw excellent well results throughout the year and currently has two rigs working.

In Canada, the EOR pilot work kicked off at our Seal heavy-oil project in Northern Alberta late in the year. We are evaluating the effectiveness of both polymer flooding and steam stimulation to unlock the massive 5 plus billion barrel resource in place on our acreage. Results of the pilot work are expected later this year.

On the gas side, development work in Canada at Tupper and Tupper West continued on plan through the year. Gas plant capacity at Tupper was expanded to 105 million cubic feet a day and first gas at the 180 million cubic feet capacity Tupper West plant is expected in first quarter 2011. Our pace here has been adjusted to reflect the deteriorating gas price. Average production for 2011 should be around 87 million cubic feet a day with an exit rate of 123 million cubic feet a day from Tupper West. Should we see gas price support we are likely to accelerate that pace. We are encouraged that even at current low prices, this project's all-in costs are below $3.75 an Mcf.

Reserve replacement for the year was a solid 114% despite increasing year production by 14%. Important new growth opportunities were also added to our portfolio during the year, in Southeast Asia we picked up two attractive Blocks in Brunei Darussalam CA-2 with a 30% working interest and CA-1 with a 5% working interest. We also signed an agreement with the Kurdistan Regional Government of Iraq to acquire a 50% working interest and operate the central Dahuk [line]. We have opened an office there and are evaluating other opportunities.

2010 saw good year-on-year production growth and good production results that beat our guidance in each of the first 3 quarters. The fourth quarter, however, was disappointing from both operated and non-operated fields. At the end of the third quarter, September 30, we were producing almost 160,000 barrels equivalent a day and projected a ramp to over 210,000 barrels by year end and looking at a yearly average just above 190,000 barrels. Results were less stellar than this and we exited the year at 190,000, and averaged the year at 186,394.

Looking at the details we see fourth quarter average production down at Kikeh by 5,750 barrels and Congo down by 3,355 barrels a day, as making up half of this miss. Non-operated impacts at Sarawak Gas, Schiehallion and Terra Nova the bulk of the remainder. At Kikeh the planned workovers were impacted by weather delays and longer time to execute the sand screen replacements than planned as well as a key well returning at lower rates. Azurite was impacted by below expected well performance.

US marketing had a very solid year turning in net income of $155.4 million, our second best ever. Retail margins were strong in the second and third quarters as petroleum prices remained range bound but came under pressure in the fourth quarter as crude and wholesale prices trended higher. Build out of our chain continued with the addition of 51 stations, bringing the total number of retail outlets at year end to 1,099.

In our Biofuels business, we fully integrated the Hankinson ethanol plant into our operations and averaged 115 million gallons per year of ethanol production, a 5% increase over name plate capacity all in the first year of operation. The plant performed well and contributed $18 million of net income for the year. In September we concluded the acquisition of the partially completed Hereford, Texas ethanol capacity and plan to complete construction and initiate startup by the end of the first quarter of this year.Production from these two plants will cover almost 50% of our current retail system needs and provides balance and coordination within that business.

In July of last year our Board approved the decision to exit the US refining and UK downstream businesses. All 3 refineries successfully completed turnaround work in 2010 and enjoyed a better second half of the year, each touching best ever run rates. The focus continues to be on safe, reliable and compliant operation of these assets. Refining margins, while under pressure much of the year, have been bolstered recently with improved crack spreads in the US where we also concluded a workable global consent decree that was lodged in September and will be entered in early this year. The divestiture process is ongoing and remains on track to exit that business this year.

Looking ahead to 2011, we see an active exploration program testing at least a dozen prospects. We began the year finishing up our first well Caracara #1 in Suriname where we found excellent reservoirs but no pay. Operations have been weather impacted and we are looking forward to completing our second well at the Caracara prospect in this first quarter. We are also drilling our first well in (inaudible) on the Semai II Block in Indonesia. Operations are going well and it should be fully evaluated this quarter. During the year important prospects in Brunei, Kurdistan, Indonesia, Australia and Congo are scheduled to be drilled as part of this program.

As Kevin mentioned total capital budget is $2.2 billion, with just under $500 million earmarked for the exploration program and the further $1.5 billion to be spent largely on development projects, Tupper, Eagle Ford, Kikeh, Sarawak and Seal EOR.Plans also include spending of $150 million for US retail, which includes construction of 55 new retail outlets and completion of the Hereford ethanol plant.

Production guidance for the full year is within the range of 200,000 to 210,000 barrels of oil equivalent per day, which represents a 7% to 13% increase over 2010 volumes. Production increases will primarily come from Tupper West, Sarawak gas and oil from Eagle Ford Shale and Seal.We remain unsure of timing with regards to activity in the Gulf of Mexico and expect declines to continue absent any meaningful changes in that business environment.

We also expect to sanction a number of development projects this year in Malaysia with oil development times at Patricia, [South Axis] and [Surrender] along with Siakap North in Block K. A floating LNG development at Road 10 and Block H is also under consideration for this year. (Inaudible) redevelopment in Hibernia South extension are also on the slate for sanction this year. Business development will continue at pace, targeting the entry of 2 to 3 new countries.

In US retail, the build out of our retail stores will continue with 55 stations budgeted for the year. Proceeds from the planned sale of our Downstream assets will be redeployed into paying down debt and/or reinvesting in our Upstream business.

So in summary, we have an attractive exploration program ahead that includes a dozen wells this year, several of which target impact prospects and are predominantly oil. This extends into 2012, where similar levels of activity and quality are to be tested. Specific impact wells in Congo, Subsalt, Kurdistan, Brunei, Australia complement the work already underway in Suriname and Indonesia. The last 2 years exploration programs were successful in delivering more reserves than produced at an attractive finding cost. Our table is set going forward for active and potentially impacting program. Continuing to grow both reserves and production with attractive returns, largely oil weighted, remains a focus and is helped with new developments being sanctioned in Malaysia, the UK and Canada this year.

Continued development and execution of our North American resource play is also set to provide growth with projects at Tupper, Eagle Ford and Seal EOR. Evaluation of our actual Bakken position will also come in shortly as I mentioned. Growth in our US retail business will continue as will our planned exit of the refining and UK retail businesses, redeploying that capital for further growth opportunities. That concludes my prepared remarks, and I'm now happy to take your questions.

Thank you. (Operator Instructions)And our first question will come from Evan Calio of Morgan Stanley.

Hi, good afternoon, guys. Just a broader question to open up for David. I mean NOL production outages in 4 and 1Q were disappointing. I mean has anything changed from your Analyst Day presentation, (inaudible) your 2015 production target, 30-- 300 million BOEs per day of production, and maybe you could just refresh us on the assumption of volumetric adds and kind of where you see upside to downside to that longer term estimate.

Yes, Evan, thanks. It's not 300 million barrels, I think that would be a little bit--

A thousand, yes.

300,000.I'll go with 300,000. But yes, we feel real good about that. And the types of projects that are going to contribute to that are unchanged since we talked about it earlier last year. Let me talk about, if I could, the kind of where we are in our production and part of the reason for the miss here, which I will tell you in the room here and in our organization, we hate missing production targets. Last year we did pretty good for the first 3 quarters, but did woefully poorly in the fourth quarter. So it's clearly got attention within our shop.

And part of it goes back to the components that make up our production. We have grown year on year pretty nicely our production, but what we recognized a few years ago that we were very dependent on single wells. And I think what you saw last year was an important well and an important field for us go off production and the well was making 13,700 barrels a day. It's very difficult in a quick way to replace that kind of production within the portfolio that we have. And so that's one of the issues.

As we go forward, as we grow our production of course individual wells of that level will become less dominant. And also, our mix has changed. And part of the value of the resource play for us is this predictability and the ability to move around and meet targets. So I think our portfolio is going to help going forward. We're already starting to see some help now and I think it will be better going forward.

In Block K specifically in Kikeh, we are -- we always view that as Block K rather than just Kikeh. And we've talked about for a long time now keeping Block K production relatively flat on a net basis through 2015. I think once be get Kikeh back to where it's going to be, and I'll talk about that in a moment, I think we'll still be in the 65,000 to 70,000 barrels equivalent a day through the 2015 number, partly Kikeh, partly Kakap, partly Siakap North, partly (inaudible). And so that in itself is going to increase the number of wells contributing to control that profile and thereby help make it more predictable.

In the Kikeh case, the simple answer for the miss is we had a nice well and all of a sudden it started making some sand. We don't like making sand because it causes problems with our facilities. So we shut that well in. We thought we were going to work it over with a coil tubing unit. That unit had a surface failure so we quit that, and then we basically-- it took us 90 days to get a rig in to be able to affect that workover. So when you loose a well of that order of magnitude for a period of time, it clearly has an effect. Under more normal circumstances we might have asked the Gulf of Mexico, which is another place in our portfolio that has high rate wells, to step up and contribute. And unfortunately because of the comments that I made earlier, we're not able to go to there and help make up some production shortfall. So we lost a lot of flexibility in that case.

Kikeh going forward, it is a great field. We've produced over 110 million barrels. So we're about 25% produced of what our sanctioned volume is. We think that volume is a good number. Our reservoir models are good and they are consistent with what we're seeing. We have some additional wells to drill there. We have some workovers to undertake throughout the course of this year. I think we're guiding now towards bouncing around 100,000 barrels a day for that field. The timing of workovers and how we get things done is part of that component. But it still is going to be a great field with some great production coming from it. It's unfortunate that we lost one key well at a time and it took time to be able to replace it.

So hopefully, Evan, that kind of addresses some of your issues. I think our production target for this coming year was a good one, obviously. Our goal here in this Company is to meet targets, not to miss them. And we think the 200,000 to 210,000 number for the year, all things being factored in, is a very reachable one.

Right. Maybe a follow-up question focusing on the Eagle Ford. A few questions, if you could discuss the capital budget and the scope of the sanctioned project in Karnes County?And I believe you fraced maybe 4 wells in November in both Karnes and Dimmit. And if you could generally discuss at whether you have any different IP rates or EURs relative to what you presented earlier in 2010?

Yes, I think that's a good question. In Karnes we're very happy. Our Board sanctioned a development of part of our Karnes acreage. We drilled 10 wells to date and completed 4. A couple of wells have been on for quite a bit of time. One of them is (inaudible) 170,000, one's 83,000 barrels. We think both wells are above the type curve that we use and so they're likely to recover probably 700,000 barrels versus 500,000 which is kind of the tight curve we use there. We are in the process of getting some facilities and some pipeline hookups done. We have two rigs running and so we've got fracing to be done there. And I think it's a very good news story that's going to get better.

This year we're looking to drill 16 wells. We may bring in another rig and be able to get more wells than that drilled. We need to let this first quarter run for us and then see how we're going to move. We sanctioned that on a 160-acre spacing and we figure we'll get something like 40 million barrels out of that development. So we think it's a very good area, a very good development and the wells that we've got above the curve get it off to a great story.

We've also got drilling in Dimmit County. We have 3 wells drilled and 2 completed and these wells look like they're about, oh, based on the nearby results from others and ours, 350,000 EUR type wells. Our best IP rate was just under 200 barrels but we choked it back to be able to let the well unload and then extend its plateau rather than have a high rate.

And then we're in a third oil area in our acreage in Northern McMullen County. We've just drilled a well and log results are very encouraging and we're going to move forward and frac that here and hope to have results in the first quarter. Right now we have 3 rigs running, 1 dedicated frac crew that'll come full to us in the second quarter and enough frac crews to get this backlog moving. So also likely to add a couple more rigs in this program as the year rolls on. So a pretty good news story for us.

You're still in the 200,000 acres, Eagle Ford?

We're working to make it more. We're over 2 and we'd like to make it 4, but we'd like to make it more in the oil window. So the bigger deals are not available and the deals that are available we're going to have to be very judicious in what we do. So as I said before, I could see us getting to 250. I don't know that getting to 300 is where I'd want to spend money. But we're certainly in (inaudible).

Great. Thank you.

Thanks, Evan.

And our next question will come from Paul Cheng of Barclays Capital.

Hi, Paul.

Hi, guys, how are you doing?

Good, Paul.

A number of questions, hopefully quick. Dave, you talk about you feel pretty comfortable for 200,000 to 210,000 this year. If you look for the remainder of the year that-- if you have to sight one, just the biggest potential risk, what that may be?

Let me give you the components that get there, Paul, and we can kind of talk that -- let me just get the right piece of paper in front of me here. We're going to get production from Tupper and Tupper West, and so the issue there is the facilities have plenty capacity and I think we'll have plenty well capacity. The pace at which we grow that will be tied more to gas price than anything else.

Kikeh we have an active workover program is the next piece and as I mentioned, we feel as though bouncing around the 100,000 barrels for that field is about right. We have the rig in the field and that program is ongoing. The next contribution will be Eagle Ford. And we have rigs running. As I said, we're building facilities. And so all of those are actively being worked and I think we're in pretty good shape.

The fourth one is Sarawak Gas and is really tied the down time of facilities that we move our gas to. As of late, that has been doing very, very well. And so I feel pretty good about that. And then once you get below that, Paul, they're all relatively minor. We will lose about 5,500 barrels a day of production from the Gulf of Mexico unfortunately, which represents a little over 20% of what we're producing, and so any encouragement to be able to get back to work would be a plus there, rather than the negative that we currently have in our budget.

Dave, at what gas price or below you would start to have some (inaudible) need to further slow the down the pace in the Tupper West?

As I mentioned in my comments, Paul, we're pretty good at $3.75 all in. So as long as we can stay north of $4, I'm happy to keep that game going. As you know, in that game you have to be drilling all the time, producing all the time to keep getting better and driving costs down. And so stopping it really doesn't make much sense. We also have parties that want to use some of the capacity in our facilities that also helps further reduce our costs. The big issue is how much do you want to ramp up, and as long as we've got good other opportunities elsewhere, I would rather spend the money there than I would making relatively small return, but still a return up at Tupper.

Dave, in-- you're talking about on the schedule for the refining exit, where are we in the process? I think initially you guys were talking about (inaudible) in the first quarter, I presume that's somewhat aggressive at this point. And what is your revised time line that you may post or you may announce something?

Yes, well I'm not going to announce something today, but I will tell you that the time line that we laid out is we're still on track and we talked about concluding the process in the first quarter. We have had interest. I think it's probably not wise of me to comment about where we are, given the fact that we're so advanced. But I feel pretty good about the process.

So you still think that you can announce a deal in the first quarter?

Paul, I don't know if I can do that because we're still in the very end of the process here and so I only control part of that, not the other end.

Okay. In Eagle Ford, Dave, can you give us an idea that how much is the production contribution that you're expecting for the next 2 or 3 years from there?

What we'd like to see is production at the end of this year get to the 8,000 barrels a day level. And we're going to sanction another component of the Eagle Ford. We split Karnes County separate from Dimmit, separate from the area that's north of McMullen. And so as we continue to drill and get comfortable at what we have, then we'll bring each of those areas forward. But the general plan now is to have a second area sanctioned this year and a third area sanctioned next year.

Should we assume that you may get to about 25 in 2 to 3 years' time? Or is that too aggressive?

I'd love it.

Okay. And that any comment that what you're going to -- when you're going to start doing some drilling or that you will be able to share some information about [South Alberta]?

The rig is on its way now. We should be spudding here very, very soon. We are going to drill 4 wells initially as part of a 6, maybe as many as 10 wells this year to appraise our acreage position. The first well will be drilled and we will core the 3 objective targets. The second white specs, the [Reardon] and the [X-shore]. We will then turn the well horizontal in the X-shore, drill about a 900-meter horizontal and frac it. And so that's going to be the first part of what we do.

Oh so even for the first well that you're already going to do horizontal and frac it? You're not just going to do vertical?

No. I think it's important in that type of play to get data early and so this appraisal program for us is very important for us to help position ourselves. We're already on the Canadian side one of the top 4 acreage holders and we want to have some data that helps us understand where the sweet spots are in this play and where the better areas are. So that's the purpose of this program.

All right, final question for me. When I look at your US marketing margin that you indicated about $0.07, it seems like that in order for you to make $22 million in net income, either your effective tax rate is very low or that your costs has been down maybe somewhere about in the $15 million. Is there any one-off benefit that we should be aware for the operation in the fourth quarter or whether if your costs is actually down, should we assume that is sustainable into the future? Thank you.

Paul, there's really no, this is Kevin, there's really no one-off item there but in the fourth quarter our merchandise margins were really good and that helped.

That is you already reported though.I based on that merchandise margin what you guys report, and what is your merchandise sales, it still seems like that there's a gap in what you report as earning. I mean in the first quarter for example you report your gross margin-- your realized retail margin is over $0.08, so it is higher than the fourth quarter, but your net income is much lower.

Paul, I think we did discuss in our -- there is a one-off item with regard to a LIFO adjustment that was made in the fourth quarter and primarily impacted the marketing portion and we had a LIFO adjustment of some $14 million and about 80% of that was for retail, the remainder was over the manufacturing.

I see. Okay. Thank you.

Paul, this is John. And what we were-- we looked at the overall volumes in our system and decided from an operational standpoint we could bring those volumes down some. So it's an operational decision to bring our finished products down in our business that led to these lower costs.

Oh, no, that's fine. I just didn't realize that you have that inventory benefit so it's good that -- I mean that's what I'm trying to understand. So that is sort of a one-off, right, so in other words, then when we look at in the first quarter that you're not going to have that benefit?

That is correct. We're not assuming any benefit in the first quarter.

Okay. Very good. Thank you.

Thanks, Paul.

And our next question will come from Arjun Murti of Goldman Sachs.

Thank you. David, just a follow up on your Kikeh comments. I think you mentioned you still feel very good about the reservoir and you expect to get the reserves you had originally anticipated, but you did have a well that sanded up here. And just wondering how you can confidence that it isn't a reservoir issue? I understand there's been issues with the coil tubing rigs, the weather, getting a new rig back in.But until you really get that rig done, how can you say with confidence it's not a reservoir issue?

Yes, Arjun, let me kind of dig into some detail here. When we side track that well to place a new screen, which is what you do, you don't actually pull the old screen out. You actually bypass, if you will, the existing completion and drill, so you get an opportunity to run some logs and to evaluate that section. And what we recognized with that well was that there was a very thin sand stringer within the overall reservoir [pack ridge], towards the bottom but not at the bottom that was water wet. And what we think has happened is that it was that water coming from that isolated interval that was producing sand that contributed to the collapse of that sand screen.

And so as we brought the well back on where you do not want to go through the issue of having a cut-out or a collapsed screen because making sand from that one little stringer. It isn't a stoic issue and it isn't a productability issue. I believe we could open that well up and get pretty high rates. The issue would be producing sand, causing us a problem both down at the well interface and also at the surface equipment.

I'm sorry go ahead.

Yes, as we look at the rest of the field -- so that was just one well, as we look at the rest of the field we've got to remember how we're developing this. We have a number of wells drilled down dip that are water injection wells and we have a number of up dip wells. And so we have over the years now been able to match how the wells are producing both in terms of the water injected and also the oil produced out. So the mapping of how reservoirs perform in the field is actually pretty good. And so it's that confidence and the well histories that allow us to be comfortable as we are.

It's very normal here for water cut rates to rise. What the problem was, I wouldn't -- with this one particular well, it was the fact that we were cutting out the screen was the real issue. And we just don't want to have sand coming up into our surface equipment because as you know, that's a bigger issue. So below ground oil in place, good. It's just a question of managing how we make the production from those wells.

We do have some additional wells to drill at Kikeh. There's a fault Block that we've yet to drill and we drilled it originally as appraisal but not as development wells. And we have another fault Block where we're going to put a couple more wells. And so there are some other parts of the field that were part of our original development plan that we are going to bring on as well.

That-- really appreciate the full explanation there, David. Thank you. Just a related follow up. When will you be done with the operations on this one well?

This one well is done. We've done a second well where we re-completed it. It came back at the same rate as it was before the workover. And so we're just monitoring that well. It's currently making about 5,000 barrels a day, and that's a level that we feel comfortable that we won't produce sand that will cause us a problem. And we have a couple more wells to workover and then we have some other additional wells to drill this year that I mentioned.

That's really helpful. And then just one quick follow up in Eagle Ford. What portion of your Karnes County acreage, and I apologized if I missed this, was sanctioned as part of this first development?

Yes, about 15,000 acres was about what we sanctioned.

15. That's great. Thank you very much.

Thanks, Arjun.

And our next question will come from Mark Gilman of The Benchmark Company.

Hi, Mark.

Guys, good afternoon. Couple things. Sticking with the Karnes County sanction for just a sec, David, what do you think is the cost of the project you've sanctioned?

The total? I'm scratching around for a number here, Mark. Somebody will get that and I'll answer it to you.

Also when you said--

800.

Try that again.

Mindy says 800, so it's a good number. 800.

$800 million? Net to you?

Yes.

Okay. And the $40 million, I believe recoverable that you talked about associated with the sanction, that's a recovery factor of what?

Oh, it's not based on a recovery of in-place oil because I think you get a little off track when you start going down that path. What we're going down here is well histories and decline curves and making an assessment that our average well will recover 500,000 barrels. But the wells that we've drilled so far look like they're on a track to do substantially better than that.

Okay. David, if you remember back to the conference call at the end of the third quarter I think I asked you about the front end payment on the Kurdistan Block. Can I repeat the question in the hopes that perhaps that payment may have been made? Can you quantify it?

Mark, we were ready for that, it's $34 million. And happy to answer it now we've signed it.

Thank you. Let me clarify something, if I could, please. Did you say you thought you could sustain the Kikeh facility at the 65,000 to 70,000? I assume that's a net number to you. Also-- and should I assume it's equivalent with the inclusion of Kakap?

How we look at that -- there's going to be 2 facilities there. Kakap production is through its own facility and then we have Kikeh. Kikeh Kecil, Kerisi and Siakap North are all going to come through the Kikeh facility. So 2 different facilities. Because it's a PSC we recognize just 1 net number and that's the number that I gave, the 65,000 to 70,000.

So the 65,000 to 70,000 does include Kakap?

Yes.

Even though it's a separate facility, same PSC?

It's the same PSC and so it really don't recognize the fact that there's two different fields just like it doesn't recognize Siakap is a different field.

Got it. Can you give me some granularity on the reserve adds and the replacement?

Yes.Let me get you my little sheet here. If you look at the big reserve adds for this year, Tupper, Tupper West are up there. We have some additional reserve adds at Kikeh. We have Eagle Ford Shale, just starting to make some adds there. And goes down the list, there's a little bit of Syncrude in as well. What's going to happen as we go forward as you know, we're going to do more and more predictable reserve adds in those resource places like Eagle Ford and like (inaudible).And then we should have some field sanctions this year that I mentioned in my comments.

Okay. David, in the news release you issued I guess a couple weeks ago on the drilling program in the Congo, MPS, there was an indication and a statement regarding improved fiscal terms. I wonder if you could be a little bit more specific and the extent to which it does or does not apply to Azurite?

Mark, we're imminently ready to have all of that signed and so it was important for us to let people know that that was close to conclusion and I expect that to be done very quickly and so I'd rather reserve my comments into the makeup as to what the actual terms are, but it does include Azurite.

Does include Azurite?

It does.

Okay, final one for me. The fourth quarter release references the reversal of some previous Malaysian dry hole charges. Could you give me an idea what that's about and any specifics as to which wells?

Yes, this is John. What we do on an annual basis, and sometimes more often, is we come in and we evaluate how much cost have been accrued versus how much has been paid. This is nothing more than the fact that we overestimated on a whole series, Mark, of wells, there's multiple numbers in there on past wells going back into 2008 and 2009.So this is just a true-up of what those actual costs are and you go down line by line and look at all different components of cost. But it's just a number of wells and they -- all these relate to wells that we expensed in prior years, simply overestimated the cost on them.

Okay. John, so it does not relate at all to a change in thinking regarding the commercial potential?

None at all.

Okay. Thanks very much, guys.

Mark, thank you.

And our next question comes from Blake Fernandez of Howard Weil.

Hi, Blake.

Hi, guys, good afternoon. Couple of questions for you. David, can you remind me, the Suriname, is that a 3 well commitment? I'm trying to get a feel for if the second well is indeed dry, what the plans are from there?

Yes, let me kind of give you a little bit of -- kind of my thoughts on where we are with Suriname. We did drill the first well at Caracara.We found a good quality reservoir, actually better than we had predicted, but it did not contain any oil. The rig is currently waiting on whether to move to Aracari.We hope that that's going to take place imminently. The results of Caracara kind of underscore some of the things we thought going in and helped address one main risk, which is the preference of reservoir. So we believe we got reservoir on the system. The several hundred meters, actually it's about 600 meters of shale that are overlying that sand package had oil shows. And we believe that that is encouraging for the play, because we wanted confirmation that we were in the kitchen area and we believe that that suggests that we are.

What is also interesting is that the next prospect is drilling a seismic anomaly that is down depth from where these oil shows were seen in this well. Now, if the second risk element is [up] it's seal, the encouragement news here is that there is oil shows within a seal section for this next prospect. Now, that's what we've seen and that's what we understand. We've still got to drill the well. We've still got to make sure that it itself has a reservoir. But as in all exploration around the world, occasionally you're lucky enough to take a discovery with the first well and sometimes it takes more wells to understand what you're doing. We have done as a Company both.

In this case here it does not discourage us that Caracara is dry. Having said that, I love making discoveries with the first well but we are seeing some of the things the way we thought they should be, and when you're in the exploration business that is always good. We will drill 2 wells. We will let the rig go to other people and the rig will come back to us and we have a number of prospects, some of different play types than what we've tested and we'll be looking to do the drill [levels]. So that's kind of the plan that we're on there.

Great. That's -- thank you for the comprehensive answer there. Also, you mentioned the Congo pre-salt. Is there a specific time frame on when we may see that spud?

Yes, if we go back and look at the well results here, just at the end of last year around Turquoise, Cobalt and Turquoise Marine 3 were trying to prove up additional reserves in the Miocene lower tertiary section, and were unsuccessful. We deepened the Turquoise Marine 4 well to a horizon we had not seen before, which was a carbonate section called the [Sanjee]. We found very good quality reservoir but we also found pay, about 5.5 meters of oil pay. And so we think that has opened up a new play for us in that acreage and so we're going back and looking for that horizon as potential targets.

So the remaining targets, both for MPN and MPS remain this tertiary channel type play like Azurite and Turquoise, but now include the deeper Sanjee carbonate play which works outside of Congo quite nicely and also the Subsalt. The Subsalt is in MPN, we shot new 3D, we're excited about what we see. We've got to come up with some prospects. If we could arrange it, I would love for us to be able to drill a Sanjee target if we've got one and/or Subsalt towards the end of this year, first part of next year. So that's kind of the game plan as we've got it now.

Great. Thanks. And my final question actually kind of ties in with what Evan was asking you right out of the gate. Going back to the Analyst Day presentation, if I'm not mistaken the 2020 target for production essentially amounted to about a 7% average annual kind of increase. And I'm just curious if you have any sense for a breakdown of what you could achieve from unconventional on that target and what percentage of that really kind of requires some high impact exploration success?

Yes, when we look at the near targets, so we were talking about 300,000 barrels in 2015, the contribution of exploration in that 300 number was about 30,000 barrels. And everything else was from existing fields and about 50 from Eagle Ford and 60 from [Motne]. It is possible to ramp up both those plays, I believe, but I'm kind of comfortable with that sort of balance.

When you step out to the 2020 time frame, then the exploration or the new additional opportunities becomes a bigger part of that. And one option is to ramp up the resource play but given the quality of exploration program that we've got, both going forward, I think that we're likely to see some contribution there. So that's kind of the breakdown that I would give.

Thanks a lot. I appreciate it. That's all I had. Thanks.

Thanks, Blake.

And our next question will come from Ray Deacon from Pritchard Capital.

Yes, hi, David, I was wondering if you could just talk a little bit about the potential on the new Blocks in Malaysia that you see and sort of timing in terms of seismic and potential drilling there?

Which Blocks are you talking about, Ray?

Sorry. The Brunei, I'm used to calling it Malaysia, I guess, but--

I thought you might have known we picked up some new Blocks, which we haven't. But yes, Brunei timing, the first Blocks, CA-1, the final plans have not been set yet but there's going to be drilling I think this year, a couple, maybe 3 wells. The second Block, CA-2, there's an outside chance it could be drilled this year and I'm kind of speeding a little bit here because we haven't really had all the meetings yet with partners to kind of worked that out. But certainly late this year, certainly next year, I think we're likely to get to drilling there. That's great quality acreage. We know the trend very well. Clearly, with Kikeh and Kakap we feel like we opened the play here, and so we're very happy to have the acreage and we see great potential going forward. So I think it'd be a nice add for us.

Got it. And both oil and gas prospects there or -- ?

Yes, it's interesting when we look at Kikeh, there's very little gas in Kikeh. Our GOR is in the oh, 12, 13, 1400, 1500 range so not much gas. More gas and free gas in Kakap. I think that ratio is probably going to be present throughout the trend. If you look at CA-2, I think there's a thicker section to play than CA-1 and I kind of like that. But there's no well's been drilled. So that will clearly be one of the first things I think we'll collectively look at as a group, so I think a combination of oil and gas.

Got it. Got it. And just one more question on the X-shore well is are you-- as far as I can tell no one has actually released any results. Was that a new field are any of the Canadian companies-- have you heard any different, I guess? And how long do you think it will take to prove up the-- to establish kind of what the aerial extent it and what zones are best to complete in?

Yes, my sense of the play is it's still a little early and people are running around getting positions. That's one thing, and it's probably why you're not hearing people talk about it. We're being I think appropriately aggressive because we want to grow our position if there's encouragement. The other thing is, there's a different level of activity south of the border, north of the border. And I think some companies maybe are sitting on some information that is going to help decide what kind of deals they want to do. So my bet going forward, if you give it 6 months people will be talking just like they started to talk about these other plays. And so we're in that kind of twilight, people have learned a lot of lessons, I think that's where we're at.

Got it. Got it. And just one more quick one. On the Eagle Ford in Karnes County, the wells you've drilled there, have they -- I mean, have you -- I assume you feel you've derisked the Block, I guess. Are they kind of broadly drilled across the acreage Block so that you feel like most of that is going to be productive or -- ?

Yes, the acreage number that I used before, I think we've got enough of a spread of wells and wells near it.We feel as though we're part of some sort of sweet spot there. I don't think we have it exclusively, but we think it's a pretty good area. And the well results have been reasonably consistent, so we feel comfortable.

Great, thank you.

Thanks.

And our next question will come from (inaudible).

Hello, I just wanted to recap a few things. The first thing is your guidance for this current quarter is like $0.55 to $0.90.

Yes.

Yes, our guidance is $0.55 to $0.95, and really that is the $90 million spread on our exploration exposure.

Okay.

So about $60 million of that $90 million is really made up of Suriname and Indonesia, those 2 big wells.

Very good. Again, I would like to recap what's the cost of the Mexico-- the Gulf of Mexico well? How much do you loose on that?

Production-wise, if we don't do anything this year, then we'll lose about 5,000 barrels equivalent to production looking at the start of the year, end of the year. If we can get some approvals to do simple things, side tracks, recompletions from our own facilities, we might be able to arrest that. But it's going to be a decline I think this year.

5,000 barrels--

The Gulf of Mexico is going to have a pretty impactful decline this year and if nothing happens this year to arrest that, then next year is going to look even worse in my opinion.

So it's about 5,000 barrels a day?

For us, yes. So that's about 20 -- a little over 20% of what we produce in the Gulf.

And again, recapping, the cash at the end of the quarter was over $1 billion, and the debt was like $950 million?

That's correct.

Okay, very good. Appreciate it.

Our next question will come from Pavel Molchanov of Raymond James.

Hi, Pavel.

Hi, guys. First, just a quick downstream question. You mentioned last fall that you're planning to sell the 3 refineries as a package in aggregate. Is that still a plan or are you more inclined to split it up?

The plan was to either sell it in total or to split it up. And I'm open still to either.

Still open to either, okay. And then let me kind of follow up on Suriname. Given the -- given what you learned from the first well, are there some specific kind of take aways or learnings that are applicable to our Aracari or are there completely independent prospects?

In terms of independence, they're quite independent. The reservoir package that we were playing for Caracara is deeper in the geologic section and quite separate from Aracari.What we found there was thick sands, probably too much sand, but very nice to see. We saw on top of it a nice shale interval with oil shows. It's those oil shows and that shale interval that link the two prospects because in the second well we will be drilling the down dip and hopefully sandy equivalent of the shalier section that contained the oil shows. So that's the only real connection in the 2.

And if we look at the rest of the Block, there are other independent prospects on the Block. And so after this 2 well program, we'll have time to evaluate what we learned and then plan what we want to do next. But it's very typical in exploration to learn something that causes your thinking to change. What we learned from Caracara was that we would want to drill Aracari next anyway in light of the shale in the section above this well's main target and the fact that there oil shows, so that didn't change, actually enhanced it. (Inaudible).

Appreciate the color, guys. Thanks.

Thank you.

Our next will come from Mary Welge of OPIS.

Yes, hi, how you doing? Thank you. Following up on a refining and marketing question, I wanted to know -- I was interested in what the status is of your efforts to acquire more retail assets?I think you were bidding on some of the Exxon Mobil sites down in Florida.

Mary, no, we evaluate opportunities to growth-- grow our retail business. The 55 that I talked about that are in our budget are sites that we select and do that way. We don't have anything on the table here to make a refining acquisition or a retail acquisition as you suggest.

Okay. Thank you.

Thank you.

And we have a follow-up question from Mark Gilman at The Benchmark Company.

Yes, Mark.

David, is Aracari a 4-way?

No, it is not. If you look at it seismically, it looks like a tennis racket with a very short handle on it. The handle being the -- what we believe is the feeder channel that made this event. But it is not a 4-way. There are a couple of 4-ways on the Block but we chose not to test them yet.

Okay. Can I ask on CA-1 now that the whole ownership issue seems to be resolved, will your efforts on that Block to the extent that you have influence on the operator relate at all to the (inaudible) well?

Mark, I would say that for Brunei and for that particular Block, that a French company operates, questions about that ought to be directed towards them rather than me as a small working interest hold holder in that Block.

Can you talk about the results of that well which you held tight?

I'd prefer the operator to talk about it.

Okay, just one final clarification. We talked before about the Block, the Block K production number, 65,000 to 70,000. I wasn't clear whether that's BOE or barrels.

B.

Barrels.

Thanks, David. You bet, Mark.

Gentlemen, it does appear there are no further questions at this time.

Operator, thanks a lot. Everyone I appreciate you calling in and I look forward to the next call. Thank you.

And that does conclude today's teleconference. Thank you all for your participation.