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Executives

David Wood - President and CEO

Kevin Fitzgerald - SVP and CFO

John Eckart - VP and Controller

Mindy West - VP and Treasurer

Barry Jeffery - Director of IR

Craig Bonsall - Supervisor of IR

Analysts

Evan Calio - Morgan Stanley

Paul Cheng - Barclays Capital

Arjun Murti - Goldman Sachs

Mark Gilman - The Benchmark Company

Blake Fernandez - Howard Weil

Ray Deacon - Pritchard Capital

Pavel Molchanov - Raymond James

Mary Welge - OPIS

Murphy Oil Corporation (MUR) Q4 2010 Earnings Call January 27, 2011 1:00 PM ET

Operator

Good day, ladies and gentlemen, and welcome to the Murphy Oil Corporation fourth quarter 2010 earnings announcement. I would now like to turn the conference over to Mr. David Wood, President and Chief Executive Officer.

David Wood

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 of Investor Relations.

I will now turn the call over to Barry.

Barry Jeffery

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.

Kevin Fitzgerald

Thanks, Barry. Net income for the fourth quarter of 2010 was $174.1 million or $0.90 per diluted share. This compares to net income in the fourth quarter of '09 of $318.8 million or $1.65 per diluted share. For the full year of 2010, net income was $798.1 million or $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 from 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 '09 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, E&P segment income in the fourth quarter of 2010 was $154.1 million compared to $339.1 million in the fourth quarter of '09. Without those special items mentioned just a bit earlier, the income in the fourth quarter of '09 would have been $212.1 million. The lower earnings in 2010 quarter were mostly attributable to the previously mentioned recovery at deepwater Gulf of Mexico royalties in the prior year. The 2010 also included higher exploration expenses. Again, '09 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 the 138,300 barrels per day in '09, the decline primarily a result of lower production from Kikeh in Malaysia.

Natural gas volumes were 365 million cubic feet a day in the '10 quarter compared to 306 million cubic feet a day in '09. This increase was 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 compared to a net loss in the fourth of '09 of $4.1 million. The main drivers here for the income increase were stronger refining and retail marketing margins in the U.S.

In the corporate segment in the fourth quarter of 2010, we had a net charge of $24.4 million compared to a net charge in '09 of $15.5 million. In 2010, we experienced lower foreign exchange losses and lower net interest expense, but the '09 quarter also included the $27 million of after-tax interest benefit from the royalty recovery related to the 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 in exploration, of which about $240 million was in lease acquisitions, the remainder for development projects with 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, about $1.5 million for the 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 yearend 2010, Murphy's long-term debt amounted to approximately $939 million or 10.3% of total capital employed. 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.

David Wood

Thanks, Kevin. Looking back 2010, so benchmark crude prices range-bounded between $70 and $80 a barrel. Breakout occurred in the fourth quarter with prices approaching a $90 mark recently on the back of improved global demand and cold weather spikes in the northern hemisphere. Most signs suggest this to be the new fulcrum point for the remainder for 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 a little move away from current pricing until supply and demand better balance.

Our industry and our company were impacted by the unfortunate 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 permitorium.

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 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 three new discoveries from eight 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 pound. The 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 some of our needle-mover prospects also contribute.

Complementing our exploration program was a solid North American resource play for oil and natural gas. It was a goal we carried into 2010. New acreage was added to our Eagle Ford Shale position as well as our Montney position. 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 in production, providing a natural risk and timing balance to our exploration fuel production and reserve both programs.

New development projects continue to be brought forward, and we sanctioned the first part our Eagle Ford program before yearend. This first one in Karnes County saw excellent oil 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 billion-plus 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 180 million cubic feet capacity. Tupper West plant is expected in first quarter of 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 holding costs are below $3.75 an Mcf.

Reserve replacement for the year was a solid 114% despite increasing year-on-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 Dohuk well. We have opened an office there and are evaluating other opportunities.

2010 saw a good year-on-year production growth and good production results that beat our guidance in each of the first three 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 yearend 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, non-operated impacts of Sarawak gas, Schiehallion and Terra Nova the bulk of the remainder.

At Kikeh, the plant workover was impacted by weather delays and longer time to execute the sand screen retracements than planned, as well as a key well returning at lower rates. Azurite was impacted by the low expected well performance.

U.S. 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. Petroleum prices remained range-bound, but came under pressure in the fourth quarter as crude and wholesale prices trended high. Build-out of our chain continued with the additional 51 stations, bringing the total number of retail outlets at yearend to 1,099.

In our bio-fuels business, we fully integrated the Hankinson ethanol plant into our operations and averaged 155 million gallons per year of ethanol production, a 5% increase over nameplate capacity out 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 facility and plan to complete construction and initiate startup by the end of first quarter 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 U.S. refining and U.K. downstream businesses. All three 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 U.S. where we also concluded a workable global consent decree that was larger than 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 at Caracara-1 in Suriname where we found excellent reservoirs, but no (pec). Operations have been weather-impacted and we are looking forward to completing our second well at the Aracari prospect in this first quarter.

We are also drilling our first well in KUS 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, Kyrgyzstan, 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 a further $1.5 million to be spent largely on development projects at Tupper, Eagle Ford, Kikeh, Sarawak and Seal EOR. It also includes spending of $150 million for U.S. retail, which includes construction of 55 retail outlets and the 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 the clients 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, Serandah along with Siakap North in Block K, a floating LNG development at (inaudible) and Block H is also under consideration for this year. Schiehallion redevelopment and the Hibernia South Extension are also on the slate for sanction this year.

Business development will continue at pace, targeting the entry of two to three new countries. In U.S. retail, the build-out of our retail stores will continue with 55 stations budgeted for the year. Proceed from the plant 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 on hold. These extend into 2012 where similar levels of activity and quality are to be tested. Specific impact wells in Congo subsalt, Kurdistan, Brunei and Australia complement the work already underway in Suriname in Indonesia.

The last two years' exploration programs were successful in delivering more reserves and produced at an attractive time and cost. Our table is set going forward for an active and potentially impacting program.

Continuing to grow both reserves and production with attractive returns largely remains a focus and is helped with new developments being sanctioned in Malaysia, U.K. and Canada this year.

The 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 comment shortly, as I mentioned.

Growth in our U.S. retail business will continue as well our planed exit of the refining and U.K retail businesses, redeploying that capital for further growth opportunities.

That concludes my prepared remarks and I'm now happy to take your questions.

Question-and-Answer Session

Operator

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

Evan Calio - Morgan Stanley

Just a broader question for David. I know well production averages for 1Q were disappointing. Has anything changed from your Analyst Day presentation like for 2015 production target of 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 or downside to that longer-term estimate.

David Wood

It's not 300 million barrels. I think that will be 3,000. We feel real good about that. 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, to kind of where we are in our production. Last year we did pretty good for the first three 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. Now 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 levels.

And I think what you saw last year was an important well, and important field for us had to 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, mix is changed. And part of the value of the resource play for us is this predictability and the ability to move around and re-target.

So I think our portfolio was going to help going forward. We are already starting to seek some help now and I think it will be better going forward.

And Block K, specifically in Kikeh, we always view that as Block K rather than just Kikeh, and we've talked about for a long time now keeping our Block K production relatively flat on a net basis through 2015. I think once we 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 and partly Siakap North, partly Kerisi.

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 coiled tubing unit. That unit had a surface failure, so we quit that. And then basically, it took us 90 days to get a rig in to be able to effect that workover.

So when you lose a well of that order of magnitude for a period of time, it clearly has an effect. Under 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 are not able to go 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 produced over 110 million barrels. So we are about 25% producers 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 was to meet targets, not to miss them. And we think the 200 to 210 number for the year, all things being factored in, is a very weak number.

Evan Calio - Morgan Stanley

Right. A follow up question focusing on the Eagle Ford. If you could discuss the capital budget and the scope of the sanctioned project in the Karnes County and I believe you frac'ed 24 wells in November in both Karnes and Dimmit. And if you could generally discuss whether they are any different now, IP rates or EURs relative to what you presented earlier in 2010.

David Wood

I think that's a good question. In Karnes we are very happy. Our Board sanctioned the development of part of our Karnes acreage. We've built 10 wells to-date and completed four. A couple of wells have been on for quite a bit of time. One of them has achieved 170,000 barrels. One has achieved 83,000 barrels. We think both wells are above the tight curve that we use, and so they are likely to recover probably 700,000 barrels versus 500,000 which is kind of the tight curve when used 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 some frac'ing to be done there. And I think it's a very good news story that's going to get better. This year we are looking to build 16 wells. We may bring in another rig and be able to get more wells in that drill. We need to let this first quarter run for us and then see how we are 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, very good development and the wells that we've got above the curve get it off to a great start.

We have also got drilling in Dimmit County. We have three wells drilled and two completed. And these wells look like they are about based on the nearby results from others and ours, 35,000 EUR-type wells. Our best IP rate was just over 200 barrels, but we (choked) it back to be able to let the well unload and then extend its plateau around one that didn't have a high rate.

And then we are in the third oil area in our acreage in Northern McMullen County. We've just filled the well and log results are very encouraging, and we are going to move forward and frac that here and hope to have some results in the first quarter.

Right now, we have three rigs running, one dedicated frac crude that will come full to us in the second quarter, and enough frac crudes to get this backlog and move it. So also likely to add a couple more regions program as the year rolls on. So, pretty good news story folks.

Evan Calio - Morgan Stanley

Are you still in the 200,000 acres at Eagle Ford?

David Wood

We are over two, and we'd like to make it more (inaudible). So the bigger deals are not available, and the deals that are available we are 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 if getting 300 is just where I want to spend money, but we're certainly in the game.

Operator

Our next question will come from Paul Cheng of Barclays Capital.

Paul Cheng - Barclays Capital

Number of questions pretty quickly. Dave, you talked about that you feel pretty comfortable for 200 to 210 this year. If you look for the remaining of the year, if you have to say one, the biggest potential risk, what that may be?

David Wood

Let me give you the components that get there, Paul, and we can kind of talk about it. We are going to get production Tupper and from Tupper West. And so the issue there is, the facilities have plenty of capacity, and I think we will 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. It's 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 are building facilities. And so all of those are actively being worked, and I think we are in pretty good shape. The fourth one is Sarawak gas, and it's really tied to the downtime 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, well, they are 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 are producing. And so any encouragement to be able to get back to work would be a plus rather than the negative that we currently have in our budget.

Paul Cheng - Barclays Capital

At what gas price or below do we start to have some (inaudible) and lead to further slowdown the pace in the Tupper West?

David Wood

As I mentioned in my comments, Paul, we are pretty good at 375 all-in. So as long as we can stay north of $4, I am happy to keep that gain going. As you know, in that gain you have to be drilling all the time, producing all the time to keep getting better at driving costs there. 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 along as we have got good other opportunities elsewhere, I would rather spend the money there than I would making a relatively small return, but still a return up at Tupper.

Paul Cheng - Barclays Capital

Dave, you are talking about that you are on schedule for the refining exit. We are we, because I think initially you guys were talking about (profit) in the first quarter. It seemed as somewhat aggressive at this point. And what is your revised timeline that you may close? You may announce something?

David Wood

Well, I am not going to announce something today, but I will tell you that the timeline 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 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.

Paul Cheng - Barclays Capital

So you are stating that you can announce a deal in the first quarter.

David Wood

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

Paul Cheng - Barclays Capital

And Eagle Ford, Dave, can you give us idea, how much is the production contribution that you are expecting for the next two or three years from there?

David Wood

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 that we split Karnes County separate from Dimmit, separate from the area that's Northern McMullen. As so, as we continue to drill and get comfortable at what we have, then we will 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.

Paul Cheng - Barclays Capital

So we assume that you may get to about 25 in two to three years time, or that's too aggressive?

David Wood

I'd love it.

Paul Cheng - Barclays Capital

And any comment when you're going to start doing some drilling or that you will be able to share some information about Southern Alberta?

David Wood

The rig is on its way now; we should be spudding here very, very soon. We are going to drill four wells initially as part of a six, maybe as many as ten wells this year to apprise our acreage position. The first well will be drilled, and we will core the three objective targets. The second white spec is the Exshaw. We will then turn the well horizontal in the actual drill about 900-meter horizontal and frac it.

Paul Cheng - Barclays Capital

So for the first well, you're already going to do horizontal and frac it. You are not just going to do a vertical.

David Wood

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, it's tough for 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.

Paul Cheng - Barclays Capital

Final question from me, when I look at your US marketing margin that you had 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 cost 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 that if your cost is actually down, so we assume that is sustainable into the future? Thank you.

Kevin Fitzgerald

There's really no one-off item there, but in the fourth quarter our merchandise margins were really good.

Paul Cheng - Barclays Capital

But you already reported that. Based on that merchandise margins, what do you guys report and what is your merchandise sales. It still seems that there is a gap in what you report as earning. I mean in the first quarter for example, you report your realized retail margin is over x cents, so it's higher than the fourth quarter, but your net income is much lower.

Mindy West

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

John Eckart

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's led to these lower costs.

Paul Cheng - Barclays Capital

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

Mindy West

That's correct. We are not getting any benefit in the first quarter.

Operator

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

Arjun Murti - Goldman Sachs

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. I'm just wondering how you can have confidence that it isn't a reservoir. I understand there's been issues with the coil tubing rig, the weather, getting the new rig back in. But until you really get that rig done, how can you say with confidence it's not a reservoir shale?

David Wood

Arjun, let me kind of dig into some detail here. When we sidetracked 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 in 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 screener within the overall reservoir acreage towards the bottom, but not at the bottom, and 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, we do not want to go to the issue of having a cut-out or a collapsed screen, because making sand from that one little screener. So it isn't a stoic issue, and it isn't a produceability issue. I believe we could open that well up and get pretty high rates. The issue would be producing sand causing some problem both down at the well interface and also at the surface equipment.

As we look at the rest of the field, we got to remember how we developed it first. 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 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 placed good and 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're yet to drill, and when we drilled it originally its appraisal, but not developed wells. And we have another fault block where we're going to put a couple of more wells. 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.

Arjun Murti - Goldman Sachs

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?

David Wood

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 work over. And so we're just monitoring that well. It's currently making about 5000 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 of more wells to work over and then we have some other additional wells to drill this year that I mentioned.

Arjun Murti - Goldman Sachs

And then just one quick follow-up on Eagle Ford, what portion of your Karnes County acreage, and apologies if I missed it, was sanctioned as part of this first development?

David Wood

About 15,000 acres was about what we sanctioned.

Operator

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

Mark Gilman - The Benchmark Company

Couple of 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?

David Wood

I am scratching around for a number here, Mark. Somebody will get that and I'll answer it too. If he says $800 million, it's a good number.

Mark Gilman - The Benchmark Company

$800 million, net to you.

David Wood

Yes.

Mark Gilman - The Benchmark Company

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

David Wood

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 thousand barrels. But the wells that we've drilled so far look like they are on a track to do substantially better than that.

Mark Gilman - The Benchmark Company

David, if you remember back to the conference call at the end of the third quarter, I think I asked you about 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?

David Wood

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

Mark Gilman - The Benchmark Company

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

David Wood

How we look at that is there's going to be two facilities there, Kakap production is to its own facility. And then we have Kikeh, Kikeh Kecil, Kerisi and Siakap North. They're all going to come to the Kikeh facility. So two different facilities. Because it's a PSC, we recognized just one net number, and that's the number that I gave, the 65,000 70,000.

Mark Gilman - The Benchmark Company

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

David Wood

Yes.

Mark Gilman - The Benchmark Company

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

Unidentified Company Representative

It's the same PSC and so it really doesn't recognize the fact they are two different fields, just like it doesn't recognize sea cap is a different.

Mark Gilman - The Benchmark Company

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

David Wood

Let me get to my little sheet here. If you look at the big reserve adds for this year, Tupper West are up there. We have some additional reserve adds at Kikeh. We have Eagle Ford Shale and just starting to make some adds there. And it goes down the list. There is a little bit of Syncrude in as well.

What's going to happen as we go forward, as you know, we are going to do more and more predictable reserve adds in those resource places like Eagle Ford and like Montney. And then we should have some fields sanctioned this year that I mentioned in my comments.

Mark Gilman - The Benchmark Company

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

David Wood

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 make up, as to what actual terms are, but it does include Azurite.

Mark Gilman - The Benchmark Company

Does include Azurite?

David Wood

It does.

Mark Gilman - The Benchmark Company

Final one from 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 specific as to which wells?

John Eckart

Yes, this is John. What we do on a annual basis and some times more often, as 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 over estimated on a whole series, Mark, of wells, multiple numbers in there on past wells going back into 2008 and 2009.

So this is just a true up of what those actual cost are and you go down line-by-line looking at all different component of call, but it's just a number of wells. All these relate to wells that we expensed in prior years, simply overestimated the cost on them.

Mark Gilman - The Benchmark Company

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

John Eckart

Not at all.

Operator

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

Blake Fernandez - Howard Weil

Couple of question for you, David. Can you remind me the Suriname is that a three well commitment? I'm trying to get a feel for, if second well is indeed dry, what the plans are for there?

David Wood

Let me kind of give you a little bit of my thoughts on where we are with Suriname. We did drill the first well at Caracara. We found 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. And we hope that that's going to take place imminently.

The results of Caracara kind of underscore some other things we though going in and helped address one main risk, which was the present of reservoir. So we believe we got reservoir in the system. The several 100 meters, actually it's about 600 meters of shale that are overlying that same package had oil shelves.

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 dip from where these oil shelves were seen in this well.

Now, the second risk element is up dip seal, the encouragement news here is that there is oil shelves within that sealed section for this next prospect. Now, that's what we've seen and that's what we understand. We still got to drill the well, we still got to make sure that it itself has reservoir. But as oil exploration around the world, occasionally you are lucky enough to make a discovery with the first well.

And sometimes it takes small wells to understand what you're doing, but 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 two wells. We will let the rig go to other people, and the rig will comeback 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 drill those. So that's kind of the plan that we're on that.

Blake Fernandez - Howard Weil

Thank you for the comprehensive answer there. Also you mentioned the Congo pre-salt, is there a specific timeframe on when we may see that spud?

David Wood

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, we're trying to prove up additional reserves and you might have seen lower tertiary section and were unsuccessful.

We deepened the Turquoise Marine-4 well to a horizon we'd not seen before, which was a carbonate section called the (sengi). 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 as tertiary channel type play, like as Azurite Turquoise, but now include the deeper (sengi) 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 at (sengi) target if we've got one and/or subsalt towards the end of this year or first part of the next year. So that's kind of the game plan as we've got it now.

Blake Fernandez - Howard Weil

And my final question is actually going tie them with what Evan, was asking you right out of the gates. Going back to the analyst day presentation, if I'm not mistaken, the 20-20 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 break down of what you could achieve from unconventional on that target and what percentage of that really kind of require some high impact exploration success?

David Wood

Yes, when we look at near target, 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 Montney. 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 20-20 timeframe then the exploration of 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 break down I would give.

Operator

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

Ray Deacon - Pritchard Capital

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 size making potential drilling there?

David Wood

Which box are you talking about?

Ray Deacon - Pritchard Capital

Brunei, I'm used to calling it Malaysia, I guess.

David Wood

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, may be three 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 that kind of work that out. But certainly late this year, certainly next year, I think we're likely to get to drilling in the area. You know that's great quality acreage. We know the trend very well, clearly with Kikeh and Kakap we feel likely opened the play here. And so we're very happy to have the acreage and now we see great potential going forward.

So I think it'll be nice to have that for us.

Ray Deacon - Pritchard Capital

And both oil and gas prospects there?

David Wood

It's interesting when we look at Kikeh, there is very little gas in Kikeh. Our GOR is in the 1,200, 1,300, 1,400, 1,500 ranges, so not much gas. There is more gas and free gas in Kakap. I think that ratio was probably going to be present throughout the trend. If you look at CA-2, I think there is a bigger to play than CA-1 and I kind of like that, but there are no wells being drilled. So that will clearly be one of the first things I think we'll collectively look at. It's a combination of oil and gas.

Ray Deacon - Pritchard Capital

One more question on the Exshaw well is, as far as I can tell, no one has actually released any results, Rosetta and Newfield or any of the Canadian companies. Have you heard any different I guess and how long do you think it will take to establish kind of what the area it will extend to and what zones are best to complete on?

David Wood

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 are being I think appropriately aggressive, because we want to grow our position if there is encouragement.

The other thing is there is a different level of activity south of the border than north of the boarder. 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 six months, people will be talking just like they started to talk about these other plays. And so we are in that kind of twilight. People learned a lot of lessons.

Ray Deacon - Pritchard Capital

On the Eagle Ford in Karnes County, the wells you've drilled there, I assume you feel you've de-risked 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?

David Wood

The acreage number that I used before, I think we've got enough of a spread of wells. 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 are reasonably consistent. So we feel comfortable.

Operator

And our next question will come from (inaudible).

Unidentified Analyst

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

Kevin Fitzgerald

Yes, our guidance was $0.55 to $0.95. And really that is the $90 million spread on our exploration exposure. So about $60 million of that $90 million is really made up of Suriname and Indonesia, those two big wells.

Unidentified Analyst

How much do we lose on the Gulf of Mexico?

David Wood

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

The Gulf of Mexico is going to have a pretty impactful decline this year if nothing happens this year to arrest that. And then next year it's going to look even worst.

Unidentified Analyst

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

David Wood

Yes. So that's about a little over 20% of what we produce in the Gulf.

Unidentified Analyst

The cash at the end of the quarter was over $1 billion, and that was like now just $50 million.

David Wood

That's correct.

Operator

And our next question will come from Pavel Molchanov of Raymond James.

Pavel Molchanov - Raymond James

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

David Wood

The plan was to either sell it in total or to split it up and open still.

Pavel Molchanov of Raymond James

Let me kind follow-up on Suriname. Given what you've learned from the first well, are there some specific takeaways or learnings that are applicable to Aracari or are they completely independent processes?

David Wood

In terms of independence, they are quite independent. The reservoir package that we're 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 intervals with oil shows.

It's those oil shows and that shale interval that linked the two prospects, because in the second well, we will be drilling the down dip and hopefully sandy equivalent of the shalear section that contained the oil shows. So that's the only real connection in two. And if we look at the rest of the block, there are other independent prospects on the block.

So after this two well program, we will 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 closes your thinking to change. What we learned from Caracara was that we would want to drill Aracari next anyway in light of the shale and the section above these wells main target and the fact that there were oil shows. So that didn't change. It actually enhanced it.

Operator

And our next question will come from Mary Welge of OPIS.

Mary Welge - OPIS

Following up on refining and marketing question, 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 ExxonMobil sites down in Florida.

David Wood

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

Operator

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

Mark Gilman - The Benchmark Company

David, is Aracari a four-way?

David Wood

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

Mark Gilman - The Benchmark Company

Can may I ask on CA-1 now that the whole ownership issue seems to be resolved? Were your efforts on that block to the extent that you have influence on the operator related also to the (inaudible) well?

David Wood

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 holder in that block.

Mark Gilman - The Benchmark Company

Can you talk about the results of that well?

David Wood

I prefer the operator to talk about it.

Mark Gilman - The Benchmark Company

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

David Wood

Barrels.

Operator

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

David Wood

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

Operator

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

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