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McMoRan Exploration Co. (NYSE:MMR)

Q1 2010 Earnings Call

April 19, 2010 10:00 am ET

Executives

Kathleen Quirk – Senior Vice President, Treasurer.

Richard Adkerson – Co-Chairman

James Moffett – Co-Chairman

Analysts

Joseph Allman – J.P. Morgan

Nicholas Pope – Dahlman Rose

Neal Dingmann – Wunderlich Securities

Noel Parks – Ladenburg Thalmann

Eric Anderson – Hartford Financial

Richard Tullis – Capital One Southcoast

[Dale Alexander – Darfil Associates]

Joan Lapin – Gramercy Capital Management

Operator

Welcome to the McMoRan Exploration first quarter conference call. (Operator Instructions) I would now like to turn the conference over to Miss Kathleen Quirk – Senior Vice President and Treasurer.

Kathleen Quirk

Good morning and welcome to the McMoRan Exploration’s first quarter 2010 conference call. Our results were released earlier this morning and a copy of the press release is available on our website at mcmoran.com.

Our conference call today is being broadcast live on the internet and anyone may listen to the call by accessing our website home page and clicking on the webcast link for the call. We also have several slides to supplement our comments this morning and they are also available using the webcast link on mcmoran.com.

In addition to analysts and investors, the financial press has also been invited to listen to today’s call, and a replay of the webcast will be available on our website later today.

Before we begin today’s comments, we’d like to remind everyone that today’s press release and certain of our comments on the call include forward-looking statements. Please refer to the cautionary language included in our press release and presentation materials and to the risk factors described in our SEC filings.

On the call today with me are McMoRan’s Co-Chairman Jim Bob Moffett and Richard Adkerson. I’ll start by briefly summarizing our first quarter financial results and then turn the call over to Richard who will review our recent performance and outlook using the slide materials on our website. After our formal remarks, we’ll open the call for questions.

Today, McMoRan reported net loss applicable to common stock of $66.2 million, $0.74 per share for the first quarter of 2010, which compared with a net loss applicable to common stock of $63.2 million or $0.90 per share for the first quarter of 2009.

Our results in the first quarter of 2010 included a number of items; $57 million in impairment charges recorded to DD&A to reduce the carrying value of certain fields, the most significant of which was our investment in Blueberry Hill where the impairment totaled $40 million. This reflected the completion of an impairment assessment following the decline in prices of natural gas during the first quarter.

We also recorded $4.6 million to exploration expense associated with the cost of Blueberry Hill offset appraisal well incurred through March 31, 2010 below 19,000 feet and $8.9 million in charges associated with our privately negotiated transactions to induce conversion of a portion of our 8% convertible perpetual preferred stock. Our dividend savings associated with the preferred stock inducements total $3.8 million.

Our production in the first quarter averaged 190 million cubic feet of equivalents per day at McMoRan. That compared with 198 million a day in the first quarter of 2009. Our production in the first quarter of 2010 was in line with our revised estimates provided in March 2010, but slightly below publicly reported estimates of 200 million a day in January because of unplanned downtime in certain fields and performance related issues.

Our oil and gas revenues during the first quarter totaled $128.8 million. That compares to $95 million during the first quarter of 2009. Realized prices in the first quarter of 2010 of $5.53 per mfc were higher than the year ago period’s average of $4.88. Realized prices for oil in [time and sap] averaged $76.34. They were significantly higher than last year’s first quarter of just over $40.00.

Our earnings before interest, taxes, depreciation, depletion and exploration expense totaled $84.7 million of 2010 and our operating cash flows totaled $80.3 million, which included $31 million from working capital sources.

Our capital expenditures during the first quarter totaled $40.8 million and we ended the quarter with cash of $268 million and no borrowings under our bank credit facility. Our debt at the end of March totaled $375 million and that includes $75 million in convertible senior notes.

Shares outstanding at the end of the period approximately 93 million and assuming conversion of our remaining mandatory convertible preferred stock, our 8% convertible preferred stock and the 5.75% convertible senior notes, we have approximately 114 million shares outstanding.

Now I’d like to turn the call over to Richard who will be referring to the slide presentation materials.

Richard Adkerson

Good morning, everyone and turning to the slides we recently published our annual report to shareholders. We have a copy of the cover of that annual report on Page 3, and in it, we talk about our strategy of creating value for our shareholders through focus on the shallow waters of the Gulf of Mexico and on the Gulf Coast for deep seated horizons of prospects in areas of where there have been very limited drilling done previously.

Our exploration targets are high potential targets in the area we’ve been working since 2000 drilling from 15,000 to 25,000 feet and now with our recent drilling at Blackbeard and Davy Jones to test the really exciting and new horizons in the ultra deep area.

Our company, led by Jim Bob and his exploration team is uniquely qualified to continue our leadership in the industry of pursuing these new horizons and this whole new frontier on the Gulf of Mexico.

The first quarter was an exciting quarter for our company as we reported the discovery at Davy Jones, and this is really significant and will be driving our exploration activities going forward. Davy Jones is located south Marsh Island block 230. It was drilled to a total depth of 29,000 feet. We logged 200 feet of net play and multiple Eocene, Paleocene sands in the well we have now. During the month of March, set up production liner.

The well is temporarily abandoned as we are working diligently to as quickly as possible get the equipment to complete this well in place so that we can perform a production test and determine what sort of flow rates we’ll be able to achieve with this discovery.

In our deep gas activities, we reported on both Hurricane Deep Sidetrack in the Blueberry Hill offset appraisal well. At the Hurricane Deep Sidetrack, South Marsh Island block 217, we were targeting drilling this well to just above 22,000 feet. The operator encountered an underground flow in the well at approximately 18,450 feet in February. We’re now developing plans to re-drill this well and which our interest was covered by insurance to test this exploration target.

At Blueberry Hill, this is the prospect on Louisiana State lease 340. We had commenced drilling there in early November 2009. We drilled this well to a vertical depth of 23,585 feet in March. We encountered significant intervals of sands, but they were wet and we were not able to confirm the continuity of the pay sands that we had seen in earlier drilling on this prospect.

We are now using the information that we gained and using our information and our 3D seismic interpretations and our geological interpretations to Sidetrack the well to target the sands, the productive sands that we had seen earlier in drilling in the prospect.

In our ultra-deep play, we’ve got two wells we’re now drilling; the Davy Jones offset appraisal well, as well as a new prospect in the Blackbeard area called Blackbeard east. We were able to successfully expand our ultra-deep acreage at the recent lease sale where we were high bidder on 17 of 19 tracks in the March lease sale so we are continuing to make progress.

On Page 5, we show the spread of our production and about one-quarter of our production comes from Flatrock field and the remainder is spread over a number of other fields.

Page 6 outlines the current outlook that we have for our exploration activities. This continues to evolve as we gain experience from our drilling and look at the opportunities that are coming to us through the industry as a result of our leadership position here, but I mention the Sidetrack efforts that are now beginning at the Blueberry Hill prospect.

We plan to re-drill the Hurricane Deep prospect and we have two new prospects that are currently in our plans to be drilled, the Boudan at Eugene Island 26 and then the project of Vermillion Parish.

Ultra deep, I mentioned Davy Jones offset the Blackbeard east. We also have another prospect we call Lafitte at Eugene Island 223 and then in the future we have plans to go back into Blackbeard west, which has yet to be tested. We’re considering developing plans for deepening and drilling offset wells at a new prospect called John Paul Jones as part of our ultra deep play.

The details related to Blueberry Hill which I mentioned earlier on Page 7, you can see that we drilled this well as I mentioned to roughly 23,600 feet by March, and we are now undertaking side track operations to a location southwest of the face sands that we had seen earlier in the drilling.

Our first quarter results include a charge for exploration expense for $4.6 million which is the cost we incurred to drill the well below 19,000 feet.

Hurricane Deep prospect, we have the map that we show related to our drilling in this area. This is a prospect that’s located as I mentioned the South Marsh Island 217 which is south of our Flatrock discoveries. We did encounter – the operator encountered this underground flow, so we were not able to reach our primary objective. This well hole has been abandoned and we expect to commence drilling to come back and test this prospect.

As I mentioned, we did have insurance coverage. We are targeting the significant gyro-sand section that we had encountered in another well in this prospect at the Hurricane Deep in 2007. Very significant un-risk potential here of 350 bcf equivalents.

On Page 9, we show how the ultra deep play that we are pursuing ties into our traditional deep gas play into production on shore as well as to the very significant success that’s been seen in the deep water. This is the same sand depositions that have been known to be productive both on shore and in the deep water, and now we’re having the opportunity to access those from the shallow water in the Gulf of Mexico where drilling has not been done to date, and this gives us the benefit of accessing these very large structures with high potential in areas where you don’t have the cost and time span issues associated with deep water development.

With success, this will allow us to commercially produce these in a much more efficient way than when you access these reservoirs in the deep water.

Davy Jones of course is the major success that we’ve had during the first quarter. This is a prospect that’s located in only 20 feet of water drilling to below the fault of salt well. We are paying for 25.7% of the cost four our 32.7% working interest, which would give us just under 20% net revenue interest.

We benefit from the fact that we entered through a previously well bore which allowed us to drill this well to 29,000 feet at - just under 26% interest, thanks Kathleen – which allowed us to drill this well, reach 29,000 feet in February as I mentioned. We had 200 feet of net play in multiple pay zones. We set the production liner and temporarily abandoned this waiting for the completion equipment.

Page 11 outlines the next steps that we’ll take with Davy Jones. We’ve spudded an offset appraisal well. In early April, it’s drilled below 4,000 located 2.5 miles southwest of the discovery well. We’ll test similar sections and deeper potential. We have not yet tested the cretaceous section that lies underneath the Neocene Paleocene section, which we have found to be productive, but the same theory of the deposition of this sand section, which was prolific, commercially successful on shore, the same geological analysis indicates that this is a very attractive additional exploration target for us.

We have initiated studies using outside experts from designing completion of the Discovery well. We need to flow test this well to determine what kind of flow rates we can achieve when we put this well on production and we’re working diligently to do this as quickly as possible. This is expected to occur within 12 to 18 months.

Blackbeard east was our initial ultra deep well. This as you recall was a well that had been drilled initially, came to us through Newfield where Newfield dissipated in a consortium of companies that had drilled this well, but abandoned it before it reached its objective target.

It’s located in80 feet of water at South block 144. The new well that we’ll drill is Blackbeard east, which is nine miles east of the Blackbeard west well where the initial drilling had been done.

We’re paying 32% with a net revenue interest of 30.7%. The well was spud on March 8, targeting just below 30,000 feet. We’re currently drilling in 11,000 feet, and this is targeting potentially Miocene objectives that’s below the salt well.

In comparison to the Blackbeard west well, targets should be present at shallower depth including the ability to test an additional Miocene section that wasn’t seen in the Blackbeard west well so we are moving forward with that.

Lease sale success that we had is outlined on Chart 13. We submitted apparent high bids. We’re waiting for approval of our bids on 17 of the 19 blocks that we participated in. We exposed our successful bids totaled $9.4 million. There was significantly higher interest on the shelf, including interest by major oil companies where bids were up substantially from the last lease sale that occurred a year ago.

Turning to our outlook for 2010, we have revised our production estimate now. We’re looking to produce at an average rate of 170 cubic feet equivalents a day. Our capital expenditures are currently estimated at $240 million. This is always a moving target as we go through the year as we deal with information that becomes available and opportunities as we assess them. That would be comprised of about $170 million in exploration and $70 million in development.

We are progressing with the reclamation obligations that we assumed with the Newfield deal. We are currently expecting to spend about $100 million in G&A expenditures this year and we also have $12.4 million that we’re required to contribute to an escrow account. We do expect to receive some reimbursement of some of our costs through insurance programs for our Hurricane related claims.

Page 15 shows our cash flow sensitivities. At current forward prices, we would generate according to our model results, $257 million of EBIDEX. You can see how that would vary with changes in oil and gas prices.

As a company, we are committed to maintaining a balance sheet and liquidity position to enable us to pursue these exciting exploration opportunities. We’ll spend capital prudently to take advantage of the opportunities and be cognizant of our objective of maintaining a strong balance sheet.

We’ll commit capital to those high potential opportunities and manage our capital program as we’ve done in the past; finding partners who contribute value to our operations and who can help finance our opportunities so that we can get exposure to more prospects.

With that, Jim Bob would you like to make any comments before we turn the call over to questions or just go straight into questions?

James Moffett

Let me just make a couple of comments because it may answer a bunch of questions. First of all, you have some slides, which we call geologic maps of the prospects. Richard’s been over the Blueberry Hill and the Hurricane Deep. We’ve had some great luck with Mother Nature. Davy Jones and Blueberry Hill, she has frustrated us because we got a dip through that well you’ll see through some sands.

On Page 21 of the geologic slides, the only interpretation that makes any sense is we feel like we’ve gotten into a fault zone where you see these faults are almost parallel to each other, and the reason for the information suggesting that’s what we’re tied up in as we saw some really well developed reservoirs average about 20% to 24% porosity as these flat rock type reservoirs do.

And they were wet with the exception of the very last center we saw which was really too think to consider completing this well, but the bid sand we had dipped – had two things that caused us to us in a zone of that may be possibly disturbed, and that is that we appear to have a high pressure in this second offset well than we did in the Blueberry Hill.

That suggested we’re fault separated and that may answer why we didn’t have the continuity even though we have almost 350 feet gross sand, 200 feet of net that was wet. So what we’re going to do is keep the well away from this disturbed zone and get back onto what we consider to be the west flank sand development.

You can see we’ve got a big shale mass touch the disturbed zone. It almost reminds you of a slat dome. There’s a deep zone that has a shale mass as these trapping mechanism as opposed to a salt mass, and we’ve got good ice back and good thickness which ties to our J.B. Mountain discoveries to the west.

So just stay tuned and we’ll get this dude figured out. If the big reserves that we originally through are there, we’ll get them pinned down and get these sands, these big thick sands in shape so we can fill them up like we did at Flatrock.

Mentioning Flatrock, Flatrock took us four wells. On the fifth well we finally got the discovery well. I was reminded of it as we were trying to evaluate this Blueberry Hill. We drilled the four wells to the south as you see called Hurricane and Hurricane Deep before we realized that strategically was more important than structure in this trap.

We went down dip, found 228 well which was the beginning of the Flatrock production. Just quickly while we’re looking at that, the Hurricane Deep that we’re going to be redrilling at Weber’s Run as prognosis by geology, tied to the original well when it became mechanically impossible for the operator to deepen and there were also some other zones by WD, indicated in the Opec and Ravel, above it that may be productive.

We never got a run on those where the underground flow occurred. So we’ll redrill that well probably a straight hole now we know what the data looks like and see if we can’t get that down in the next few months to confirm this second half of the Flatrock field.

Just a couple of points; on Slide 23, just to remind you, both emphasis on deep gas play, the one above the Lautrec and one below the Lautrec, the ultra deep – if you look at the Flatrock field and see Blueberry Hill just to the east, that’s why we’re trying to get this Sidetrack hold to confirm how we get back into these continuity as we see Flatrock and J.B. Mountain.

Of course it’s very important the entire exploration program on the State track 240 OCS 310 which includes the Flatrock discovery and J.B. Mountain discovery as you see, and there’s a broad area there that’s 30 miles wide and 60 miles long and you can see that we’ve got these big reservoirs that have this high pressure and high porosity which gave us the ability to get the high production rates.

Knowing the play is one of those places we’ll be drilling above the salt well. On the Page 27, I wanted to just point out a very interesting geographical reality. You see the Davy Jones well and you see the Blackbeard well, original Blackbeard west. Those are the only two penetration points on the shelf.

To the south, Jack, which is 220 miles south of Davy Jones is the only well that’s been tested in the Wilcox, we we’re hoping we can get this Wilcox test which will be important for the whole offshore play, especially our shelf play because of what I just said. There’s only been one well flow tested in the Gulf of Mexico in the Wilcox.

And then of course you can see Tibor, Castita, Thunderhorse, all those wells over 100 miles to the south of us, so when we talk about wildcat on a shelf where you had 50,000 wells drilled, and only have two points of penetration in the deep Miocene below the salt well, in the Wilcox I think it defines for you what the discovery of this section means.

Now on South Marsh Island, Davy Jones and Midwest on 28 you notice the structures are very similar. And the important thing is, we haven’t seen the Tuscaloosa or Crustaceous, which produces in the up dip Tuscaloosa trend. We feel that based on the fact that we saw the Wilcox top at 26,000 feet, that should be available along this whole northern trend where we have this well called Wilcox, Tuscaloosa trend.

The last slide and my geologic slides, very important point Page 29. If you see Blackbeard west, there’s ridges on the right cross section. When you look at Blackbeard east, the reason why we have additional Miocene section is that purple zone which is the ultra deep dimension covered up by the salt well.

It’s much higher in the section. We should it see up around 20,000 feet which means that we’ll see 5,000 feet of Miocene which was literally carved out if you will, eroded out. So we should see the same sands we saw in the Miocene down at the – below the 5,000 feet that we carved out in that five to ten feet above that, you’re going to have a definition of sands which will really be available to us across the whole east/west part of the shale which we draw the Miocene Wilcox trend.

And the feed which will be spudded later this year has exactly the same potential as a lot more Miocene section that we’ve seen, so we should get some really good information. Hopefully a couple of discoveries in this upper Miocene section we’ve seen in the deeper section below the Davy Jones.

Now I’ll turn the call over for questions.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from Joseph Allman – J.P. Morgan.

Joseph Allman – J.P. Morgan

On Davy Jones, is the plan at this point to definitely do a flow test and if so, what takes so long? Why are you indicating 12 to 18 months and I think you were trying to have discussions with MMS to see if they would allow 20,000-psi equipment. Could you talk about that as well?

James Moffett

As soon as the leases are all confirmed we’re going to go to MMS and we believe that we can use 20,000-pound equipment. The team that’s been assembled which includes those that have been involved in the high pressure, high completions around the world are sending all the data as to support that.

The only reason why the 12 to 18 months is mentioned, don’t want to over promise on the thing. Everybody including us is focusing on this. If we can’t get the 25,000 approval, and don’t feel comfortable with it, then the tie back string, the Christmas tree, all of that is available to us this year and the one hold up is the safety valve which we think we’re going to get that problem solved too.

So nothing’s changed as far as what we’re hoping to do. All we’re trying to do is say that the outside range would be 12 to 18 months. Obviously we’d like to get the thing done asap and we’ll do that.

Joseph Allman – J.P. Morgan

Still at Davy Jones, at this point have you had any problems with the heat down there in the well? Has the heat caused any problems with the equipment, melted any equipment or anything?

James Moffett

I know that with the concern that the temperature is higher than it has been in other wells in the Gulf of Mexico is a concern, but there have been wells to the west of us that have been drilled in the Gulf of Mexico to these depths that have had the same heat or higher and the Fandango field, which is onshore Wilcox, I think I mentioned to you before in south Texas, has even higher temperatures than we do.

So when you get into speculation, 420 to 430 degrees isn’t going to melt any kind of metal. It’s not going to melt anything that’s before our completion. The only problems that the heat had, which causes the conversation to continue is in our logging. When we’re trying to log with these, whether they were drilled pipe conveyed or run on a wire line, the heat and pressure has an effect on those logs and at certain points as we ran deeper, we found that the quantitative analysis took some time to complete burn up of the Lesko system occurred, but there again, we’re talking about electrical systems and wire cable.

But as far as the big items, the casing and the packer, I mean one of the big things we got done which when you put it on paper doesn’t hit you in the eye, but we ran the liner all the way to bottom and got a liner in the hole so that we would have a chance to float these things. Running these production lines is to see if pressure is going to have any impact, you’d see it on that kind of a situation, but we ran that five inch all the way to bottom so we can test these sands in ¾-inch hole.

So the drilling conditions, the most complicated thing we did and we learned an awful lot drilling this well, was to learn how to log these wells and what logs will work at this temperature and pressure and of course other companies are now fast at work trying to improve, mostly to measure the porosity.

The curves, gamma ray curves have repeated themselves. The sonic density neutron, those things that measure porosity, those things had a tendency to burn up quicker than the other logging mechanisms. So the heat melting any kind of metal to be used in the completion is unfortunately just rumor and concern, but it’s got no technical relations.

Joseph Allman – J.P. Morgan

At Blueberry Hill, previously you talked about the size of that at 500 bcf, so at this point have you downgraded that in your model to something below 500 bcf or what are you thinking about there in terms of the potential size?

James Moffett

Well obviously as I said, Mother Nature frustrated us when we saw the doggone – the one sand if you saw it on the log is 350 feet thick. Got that 200 feet net. If we had filled that dude up, we’d have been about half way to where we wanted to be as far as reserves.

It doesn’t make any sense. We’re 500 feet high to our down dip well. The seismic as you remember is just a great big north/south axis. 95% of the time, you’d up dip to three zones in that play. You’d fill up the boat when you get this high.

But for some reason, we appear to be not have continuity between the down dip sands and the only thing that can be doing that is the disturbed zone ie. fault zone. It’s got to separate and if we get off the flank and the big sand pile is still out there then we’ll still have our potential earmarks for a major discovery.

Remember the first three zones that we saw, particularly the one individual well that we drilled, was 150 gross with about 150 net and the porosity is in the doggone thing, I mentioned even the wet sands in this well are over 20%. That’s why you get these doggone high flow rates. So just stay tuned. Being 500 feet high and having these kinds of sand in the well should have been all the way to this target of 500 bcf.

If we kick off to the west, and we still don’t have the thing completely figured out, it may be that we’ll have to go further south. But if you were to look at the map with Flatrock and J.B. Mountain and Blueberry Hill, you’ve got to just realize that half the trap, Flatrock is [inaudible] and half is structural so let’s just stay tuned.

We’ve got the big sands. We know they’re here. We’ve just to fill the darn things up so we can start to talk about the 100’s of bcf that we thought were here after seeing the initial well.

Operator

You're next question comes from Nicholas Pope – Dahlman Rose.

Nicholas Pope – Dahlman Rose

With the Blackbeard still a feet well, I see like on the presentation it looks like you expect to stop in the Miocene. Are you going to have the well designed to where you’re going to be able to make it all the way to Wilcox if things are going well or do you plan to stop in the Miocene?

James Moffett

The well will be designed as was the Blackbeard west well where if we’re running the way we think we are and the model checks out, we have the Miocene section, we have no limited to being able to go in and see if we can top the Wilcox and find out what the prices look like.

The main reason we’re focusing on the Miocene in cross section is, I think you’ve heard there was 5,000 feet of Miocene section. It was scarfed out of the Blackbeard west which means that nobody has seen on the shelf anything but this 3,000 feet of Miocene that we tested, and now with this opportunity to define the rest of the Miocene section, the 5,000 of sediment, I don’t know how much of it is going to be sand or shale, because there’s no well to correlate with.

But if we have a very good sand section in the 5,000 feet section, we could expect 2, 3, 4, 500 to 600 feet porosity in a 500 feet interval and that’s why we’ve been focusing on really sort of getting that information as our first target, and then we’ll see where we go from there.

Nicholas Pope – Dahlman Rose

And I guess with once you get that data from Blackbeard east, does that, I mean does that make it where – is that going to derisk the drilling in Lafitte just in terms of having a corollary for the Miocene you’re looking at?

James Moffett

We believe as you can in the up dip section in the Miocene about the Lisgard, as long as you stay east/west which is why we’re defining two trends, the Miocene in the Wilcox to the south and the Wilcox Tuscaloosa on the shale, as you know when you go east/west you can go hundreds of miles east and west to say in the same bio stragraphic unit.

So when we define the rest of this section, that will as you say give us a very good idea of what we can expect in Lafitte and it also will give us a good idea of what we can expect as we go off the flank of Blackbeard west because one of the things we’re trying to find out with this Blackbeard prospect by drilling Blackbeard east is, are these two separate structures? Are they all connected?

One of the big things that we’ve seen from the deep water and with these very high altitude from the [inaudible] we can expect that we have significant columns in the reservoirs below the salt well just as we do in the deep water, and so we really need to see are these big structures connected by hydro carbon cone or are they separate?

So there’s a lot we’re going to be learning on the Blackbeard east in terms of additional Miocene section. It could enhance the value of Blackbeard west and Lafitte and all of the prospects, the ones that we have on this trend.

Nicholas Pope – Dahlman Rose

The Flatrock, I guess you briefly commented on the issues I guess, mechanical and production performance issues. Could you elaborate a little bit about what’s going on with Flatrock and what we may be able to see in terms of bringing some of the production back in that decline or are we going to be declining from the rate we’re at right now?

James Moffett

We’ll get the production back up. What happens is, we’re producing these wells at such a rate and we of course started with completions taking deeper sands first and the two big wells that made 100 million a day for over a year, have started making water. As they make water, you see the rate come down.

We have completions higher. For instance in the 220A well that we come up to and we can go up to sands in the wells that are making water and get a higher completion there. But when you have these wells in production and in the Operc particularly by the way to the south of the 220A and well into the 230, we’ve got a really good re-completion that we come up to in the Operc One, but the Operc ran has declined and it’s producing I don’t know, five million a day.

But when you have these wells in the initial completions and the re-completions when they flow at high rates and then go down to the lower rates of four to five million, as long as they’re commercial, you can’t go off and leave unless you can prove that you can produce it in an offset well because the MMS rightly so, doesn’t want you to leave any reserves in the ground.

So we’ve got numerous re-completions and other than the facts that we just discussed about how you have to prudently get as much reserve as you can out of the ground, we have at least three completions that will go back up to 80 to 100 million a day and the 229 well for instance, we forget how much gas these doggone wells produce.

It’s making water now. It was making 100 million. It’s down now to something like 27 to 30 million a day, but it made 50 b’s. before it started making water out of just one zone. And it’s the lowest well in the big 250 foot RobL10-4 reservoir.

So we have two wells up dip of that and obviously the well to make 50 b’s before it started making water has a very strong water drive so we should get 100 or so as high as you can on these other wells, and you’ll see the ratio go back up to the initial rates.

Operator

You're next question comes from Neal Dingmann – Wunderlich Securities.

Neal Dingmann – Wunderlich Securities

Could you give me the rig schedule as you see as the rig over Blackbeard west, will that then continue on to John Paul Jones or have you really sort of figured that out given the two wells you’re drilling now kind of what’s next. Will you keep two rigs running?

James Moffett

Well, let’s put it this way. With the three rigs we hope to keep them running. The information we get from the Blackbeard east will have a major impact on Blackbeard west where you mentioned that on.

The information we get on two things at Davy Jones that are going to be going on. One is the drilling of this offset well which we just set 75 to 4,000 feet and a flow testing of the Davy Jones number one well.

Considering if we get the kind of flow rates that we’re expecting, so that we see that these sands are going to flow at the kind of commercial rates we want them to, that could speed up the development of Davy Jones.

That plus the information from the offset well, remember we think we’re going to be somewhere between 500 and 700 feet high in this offset well. So you’ve got section that wasn’t seen and the first well that we will also be able to look at so that could focus us on trying to get more wells in the development stage at Davy Jones and get the high cash flow off of Davy Jones.

All of these things have got big potential and we need to get them tested. And so that plus the Miocene section that we just described, if we prove that 5,000 feet of Miocene has some big sands in it, that will have a major impact on it. So as you said, the information from these wells will determine where we take the rigs, then that’s sort of how the flow will go.

Neal Dingmann – Wunderlich Securities

You’re obviously pretty active at the lease block sale. I was wondering when you start hearing the final confirmation on that, how soon you’d get after those and kind of the proximity of those in relation to Blackbeard, Davy and some of your other prospects.

James Moffett

To continue what I just said about the rig schedule. Obviously we get a good flow test at Davy Jones and get a good offset, prove the Wilcox section is continuous and we have some deeper sands, and even possibly look at the shallow [ayawaw] could have a major impact on our ability to get cash flow coming from those.

We’ve had the discovery at Blackbeard west in the Miocene. Davy Jones we’ve discovered the Wilcox. Now what we do is to prove the commerciality and what kind of flow rates we can get out of it, and then all of the answers of how many rigs we get going that we should light up the whole shelf. As you’ve heard us say these big structures that deep water, every one of them have had highly coverage in the Miocene.

The Wilcox we expect the same thing to be the case, and after we get two or three of them down and prove that that’s the case, the rest of these big structures are going to attract a lot of attention as far as trying to get as many of them tested as we possibly can and of course the commerciality of the Davy Jones, Blackbeard complex and Lafitte will have a lot to do with our ability to get the money together to be able to attack the whole shelf and pursue these other plays.

Operator

You're next question comes from Noel Parks – Ladenburg Thalmann.

Noel Parks – Ladenburg Thalmann

There was the mention in the press release about the production guidance, the change to that. There was also the mention of delays in other projects coming on line I assume in addition to what’s going on at Flatrock. Can you tell us more about that?

James Moffett

That was strictly weather related. We had a tough month. I’m sure you’ll hear from many other companies reporting this quarter. We really had a tough season out there where you just couldn’t work. Many of the wells that we re-complete and our existing wells we acquired from Newfield and in our own wells, there was less flow through that rig.

But you get these big swells and north easterlies which are not hurricanes, but they’re just winter cold weather type things that you can’t keep the equipment on location. It’s just too dangerous. So therefore we had a lot of delays in re-completions and so we hope to get back on target and get a window here before hurricane season starts and get out there and finish those things. As we said awhile ago, one of the big impacts is the big wells at Flatrock and I just explain how we re-complete and get those things back up to big flow rates.

So we just adjusted and try to be conservative since we had such a tough quarter and the weather working out there on the shelf with these lift boats.

Noel Parks – Ladenburg Thalmann

Can you give a rough sense, other than Flatrock about what sort of production volumes are delayed and by roughly how much as a result of the weather. Is it just everything is pushed back a quarter say?

James Moffett

That’s a good guess. Weather letting us do it, getting out there and re-perforating these zones in these stack plays that we have will have the impact. I guess the most important things is what this does, it says the reserves aren’t going anywhere. It’s just a case of not having the oil production in the quarter we’re just reporting .

Noel Parks – Ladenburg Thalmann

But then of the we’ll say it’s $10 million or so, is that maybe half of it as these re-completions?

James Moffett

The $10 million that we’re short right now is almost completely something you can make up with the re-completion of the well at Flatrock. The other well could actually put us over raising our target if we can get out and get them on production now that we’re delayed a quarter.

Once you’ve had this weather and see these realities of when you can re-complete some of these wells at Flatrock, we just are trying to give you some numbers we know we can hit to be conservative and if we can get out there and do better, then everybody will be busting their tail to do that.

Noel Parks – Ladenburg Thalmann

I was also thinking about just your experience with Blueberry Hill and the various wells you’ve drilled since you went back onto that development. If you look into the future DPS prospects that you have, does the experience of Blueberry Hill change your thinking about how much of an interest you want to keep and how much you want to try to get taken up by partners going forward? I mean would we expect to see maybe you keeping a smaller working interest in some of your future deep cap stuff if you think it has as much potential for problems or just uncertainties as Blueberry Hill has turned out to have.

James Moffett

All those thoughts go through your head. The thing you have to remember is J.B. Mountain, which is now in production, produce 75 million. Flatrock, although it was complicated getting the sweet spot has produced just under 150 bcf’s as we turn it on.

In this one particular area where Blueberry Hill is just each of Flatrock, Mother Nature when she disappoints you and you see one of these big sands pop up that I said is 24% porosity with 200 feet of net, 350 feet of gross, obviously it’s disappointing and frustrating but remember when you fill the doggone thing up, you go right back up to the other side of the chart.

So B&A were to drill these wells for $25 million or $30 million, it’s important, and when they’re successful, because they’re close to infrastructure and they come on production within six months, it’s just a part of our portfolio that we’re looking at.

But to answer your question, all of those kind of things have to go through our minds and will be driven by the Sidetrack here, the underground flow that the operator experienced on Hurricane Deep even though the weather is running on target, those are hiccups that you don’t like to have to deal with in the quarter so Mother Nature gave us Davy Jones and decided to get our attention and say I still can give you some challenges.

But all of the above that you’ve mentioned continues to go through our mind as far as exploration, the psychology and where we go from here.

Operator

You're next question comes from Eric Anderson – Hartford Financial.

Eric Anderson – Hartford Financial

I wonder if I could start with a quick question back on Davy Jones. I think a couple of months back when Energy 21 held their first analyst meeting in New York, they had a page in their presentation, Page 112 in which they had a picture of the gas flare that had taken place at Davy Jones on January 31 which I believe lasted for two hours and twenty minutes or so. Can you give us any details as to what was going on there in terms of how that happened? Did that happen a lot or what does it potentially mean for what you’ve got there.

James Moffett

What happened was, when we were making one of the trips to do the logging, as you can remember us talking, we drill where there’s a lot of mud 118-1, 118-2, so that we won’t frac the shales as we drill in these deep holes.

When you come out of the hole, you have to replace the so called pump pressure or circulating density by raising the mud very slowly and come down the hole with say 18-6 much in the hole so the well will stay stable while your pump’s off and you run your wire liner through a pipe assisted log.

We were going back in the hole after having logged the well. We lost some mud. The well tried to come in on us and we circulated out what we call the drillers method where we basically put the well on choke and we let the gas bubble come to the surface, and that’s when the gas stream was so heavy that we lit the flare.

The reason why we’ve been cautious about that, as I’m sure [John Shiller] would agree with it, it’s very difficult when you see gas like this at the surface. You don’t know whether it’s what we call ballooning gas. In other words, when you frac one of these shales with you mud being too high, it literally opens the shale and as you flow the well back, the mud flows back out of that shale, some of that could have been shale gas. Some of it could have been formation gas.

We had it analyzed. It’s likely nobody’s smart enough that I’ve ever been exposed to to distinctly tell you by isotopes or anything whether some of this could be ballooning gas or reservoir gas. It was a strong flare and interesting, but we had to go ahead and circulate it out and keep our mud rate down, then just let the dadgum thing flow and get the equivalent of a drill stem test but you don’t take those kinds of chances with these deep wells.

Eric Anderson – Hartford Financial

What depth were you at at that date, do you remember?

James Moffett

Oh, we were I think close to 2D. We had drilled up all of our play sand.

Eric Anderson – Hartford Financial

I just unfortunately couldn’t really tell what you had there.

James Moffett

Well, some people might tell you that they can look at these different isotopes and what you get when you have a gas sample broken down. I’m not going to argue with them one way or another, whether some was oil gas and some of it was balloon gas. We’ll fight it out when we flow this well.

If there’s reservoir gas, it means it’s a nice indication that we got something down there that will flow. But the best way to give you the right kind of information that we’re all looking for is to get these things perforated, get them isolated in a completion and you’ve heard my feeling about it. With the amount of pressure and the clean looking nature of these sands and we just did it that gives me a good comfort.

We’ve got clean sands that are porous and with these pressures we ought to be able to perforate them and get out of them what we want. But trying to use this gas that was flowing while we were trying to get this well back in bounds so we can go ahead and put out log in and get our ladder run, I just didn’t want to put any more speculation behind that other than what was.

It was a matter of fact. You saw the flare and the gas was coming from the bottom somewhere in the section below our liner which was just around 22,000 feet.

I hope that clarifies it. I’d love to tickle your palette with it, but rather than do that, let’s let thing unfold here. It’s a big, big section covering 30,000 acres. I’d rather use that as an indicator. Let’s get the facts so we can all celebrate together.

Eric Anderson – Hartford Financial

Well the good news is that you got the liner set all the way down so that’s important.

James Moffett

I’m glad you brought that up because obviously people who haven’t run a five inch liner 6 ¾” don’t know just glad you are when you get these kind of mechanical things done. But that’s so important, and I appreciate you bringing it up because we learned a bunch of things with the Blackbeard west and the Davy Jones. We learned how to drill them. We learned what mud wedge you can drill them with and you can run these liners.

The deep holes are actually more stable than drilling some of the stuff above the salt well from 15,000 to 25,000 feet because the rocks are more consolidated which is why everybody talks about the temporary pressure. But to run a five inch line at 6/3/4 inch hole, this give you, oil based mud, gives you a lot of comfort that if we’re right and we’ve got multiple completions out here, that once we get the logging techniques down, we can get the cost of these wells down and then completing them is no different than completing well down to 20,000, 22,000 to 23,000 feet.

Eric Anderson – Hartford Financial

On that extra 5,000 feet of Miocene that you expect to run into on Blackbeard east, what’s the potential to find some oil in the very first part of it.

James Moffett

The pressure we’re going to be seeing, I think most of the engineers, the experts on heat temperature and hydrocarbons would tell you that you’re probably looking at gas. It’s going to be under less pressure so it may have a lot more condensate in it. As you go deeper, as you know, the higher the temperature, the condensate rate is expected to go down and you get into the dry gas phase.

There’s no question that we may have an opportunity to see some more heavy hydrocarbon condensate than we do down at the other depth because we actually think we’ll start seeing some, if our model, we could start seeing some Miocene sands above 23,000 feet.

And of course that’s important as dickens because in the Davy Jones well particularly, as you remember, we had a sand up to 26,000 feet above our pay sands. In the Wilcox actually when the prosecutors were working bang on for the east target, was 24% to 26% porosity so it’s going to be very interesting to see how much of the 5,000 is sand, how much of it is shale, what the sand quality and porosity is as opposed to the Miocene we saw at 30,000 feet.

And of course whatever we see affects the whole trend. I hate to say that. That’s so important to recognize that it affects the whole 200 mile wide trend.

Eric Anderson – Hartford Financial

My last question relates to back to Blueberry Hill. I think you’ve got a couple of wells now that you’ve got down that either you by-passed or Sidetracked. When might you be able to produce from a portion of those wells?

James Moffett

The last by-pass well we drilled which was the by-pass, was actually the third well we drilled. The original Sidetrack to find the big sand had 150 gross sand. We got a dip it with the third side track that we drilled and it can be completed and flow tested and produce from that zone. So we have one well there that we can complete.

What we’re trying to do is see if we can figure out who to get these things wrapped around. You’ve looked at these cross sections enough. You’ve got a big block of shale that’s a major shale ridge running down through here. You’ve got these sands that are strapped up against the side of them, 1,500 to 2,000 feet section.

It’s a perfect setup for the kind of reserve we’ve been talking about and that’s why we’ve just got to get this darn thing kicked out there and find out why we’re in 500 feet higher than the first well and only have one thin play sand. It’s had us scratching our head, but we’ll figure it out.

Eric Anderson – Hartford Financial

Before you start producing from the field, do you want to have a little bit more understanding in terms of the kind of pipes you’ve got to run out there at the production facilities you need?

James Moffett

Exactly. What we were hoping for of course is this big 350 foot sand that turned out to be wet was going to be full. It would have been another one of those 100 million a day wells, and we would know whether we would want to put a separate facility here or try to go back to Tiger Shoal.

So size of the production out here in 10 feet of water was really important to us, but doggone it, there’s only one way to say. When you drill and come up 500 feet on a really good seismic line with three out of five sands with pay in them, you expect to fill up the section and it just didn’t happen. That’s why we’ve got to get back off the west flank and get back into something that hopefully is going to have some continuity because the seismic is very straightforward. It’s just one big north/south access slap up against that high pressure shale.

Operator

You're next question comes from Richard Tullis – Capital One Southcoast.

Richard Tullis – Capital One Southcoast

Just going back to Blueberry Hill real quick, if you do end up producing from that one well at 150 feet of pay, what are you looking for or expecting flow rate, initial flow rate, something around 50 million to 75 million a day?

James Moffett

[inaudible] if you remember there was an up dip, I don’t know 107 feet. It’s got the 20% to 24% porosity. We certainly ought to be able to get a flow rate somewhere of 30 million or more out of it.

Richard Tullis – Capital One Southcoast

For the production guides for this year, the 170 million a day average, roughly how much production are you expecting from Flatrock to contribute.

James Moffett

Again, as I told you with this MMS’s where you can’t go in and re-complete a well even though you can take a well that’s producing 5 million and bring it back up to 60 million or 70 million a day, you just can’t move from the zone unless you can prove that you can drain another well. So we’re going to be constrained by some of that.

And we’re not complaining about that by the way. The resources, they don’t like to leave the ground either way. But that’s the kind of engineering challenge it is. We’ve got some great re-completions that are potentially 70 million to 80 million a day completions because they’re high on the structure and we just got to get to them and get the best re-completion schedule to show that we won’t leave any hydrocarbons behind.

Richard Tullis – Capital One Southcoast

At this time you don’t really know exactly when you can re-complete some of those wells like the 299 or the 231.

James Moffett

Well, to answer your question, a lot depends on the sequence of what happens to some of the other zones, but suffice it to say the wells producing right now just about 200 million a day. We get 300 million day when we get back up there, but 200 million a day is still probably the biggest flow rate of the shale.

Kathleen Quirk

We’ve assumed about 35 a day in our on average for the year in our 170 guidance.

Richard Tullis – Capital One Southcoast

You may have touched on this already. Boudan and Flag, when you expect to spud those?

James Moffett

Boudan will probably come pretty quick. It’s down on the southern end of the OCS 310 State track 340. It’s got some really interesting Flatrock type of features to it, so we hope to get to it within the next several months.

Operator

You're next question comes from Joseph Allman – J.P. Morgan.

Joseph Allman – J.P. Morgan

Does your 170 million a day for the year assume that you are able to do some re-completions between now and year end?

Kathleen Quirk

No, it’s basically the current rate and still some decline so we don’t have any significant re-completions in there.

Joseph Allman – J.P. Morgan

And just to clarify, you’ve got some re-completion opportunities at Flatrock and where else do you have some meaningful re-completion opportunities?

James Moffett

Those are going to come from the things that were delayed because of weather in this quarter and a couple of those have stack pays and 6 million to 7 million a day completions. So we’ve got some upside as we said. Once again, since we got our tail kicked by this weather in this quarter, we’re trying to give you something that we knew we could hit. We’re going to get in here and get some of these things as soon as we possibly can.

Richard Adkerson

We have, you can see half of our reserves over all of our nine pipes so we have a regular program of depleting zones and re-completing as part of the Newfield package.

Joseph Allman – J.P. Morgan

So the things that were impacted by the weather, you haven’t defined specifically what they are, but just miscellaneous things that are just part of the normal program.

James Moffett

We couldn’t conduct our normal program. What Richard said and what I thought I implied, is we go through these stack pays and re-completes. As one depletes and we get to – we just couldn’t get to the wells to be able to re-complete them.

Joseph Allman – J.P. Morgan

But you haven’t defined specifically what those wells are, is that right?

James Moffett

We can get a schedule of it. We’ll get it to you.

Joseph Allman – J.P. Morgan

At Flatrock is there anything – any of those wells producing zero right now just waiting on a re-completion?

James Moffett

The closest to that is a well that’s making about 5 million a day which is a 230 well. It has come big completions in the Operc and is in an Operc sand now that’s depleting. It came on at 30 million a day, it’s down to 5 million a day, but we can’t shut the darn thing because we don’t have another place to get to the Operc zone that it’s in.

We’ve got an Operc one and we’ve got the big sand above that, so it’s frustrating to sit and watch a doggone well produce five million a day because we could re-complete it, but those are the rules.

Joseph Allman – J.P. Morgan

Could you give us kind of a time table of results for this year for the wells that you’re drilling right now. For example, like at Blackbeard east, how long – I think you’re below 11,000 feet, how long do you think it will take you to get to roughly 23,000 feet where you start to see the Miocene?

James Moffett

If we have any luck 90 to 120 days we ought to be seeing some real good results.

Joseph Allman – J.P. Morgan

Is that the time to get to TD or is that the time to get to the Miocene?

James Moffett

To get into the Miocene.

Joseph Allman – J.P. Morgan

Then for the Davy Jones appraisal, is that also –

James Moffett

Well, we’re 4,000 feet service right now. If we get lucky and get that main stream, 90 days we could be a long way toward getting into some new stuff there too. Fasten the seatbelts guys. It’s an exciting ride. Frustrating at times, but the excitement always overwhelms the frustration. We’ve got enough going. Mother Nature might give us a few more surprises this year.

Joseph Allman – J.P. Morgan

You have two operator rigs running right now? Is that what you’ve got?

James Moffett

We have one rig at Blueberry. We have the Davy Jones offset and the Blackbeard east.

Joseph Allman – J.P. Morgan

So that’s three operated, correct?

James Moffett

That’s correct.

Joseph Allman – J.P. Morgan

And the Chevron can be operating the Hurricane B.

James Moffett

We will probably operate it.

Joseph Allman – J.P. Morgan

Does that mean you’ll have four rigs running?

James Moffett

It depends on how quick we get the Sidetrack done on Blueberry Hill. We might use that same rig on drill now. We’ve got a very good rate on it.

Joseph Allman – J.P. Morgan

At Blueberry Hill, in the release you indicated you have an impairment there. How does that relate to the gas price? Obviously the gas price went from roughly $5.83 at year end to close to $4.00 now. How does that –

James Moffett

It’s the fact that we didn’t add the reserves. We hoped we did have dip in the reserves. We had allocated to the wells including the value of the original well that was drilled there. We’ve been carrying it on books until we had enough reserves to offset it and leverage when it falls below it, you have to take the impairment. So it’s a non cash deduction. We just cleaned up the books. If we’re lucky and we get back into these big columns, the production will speak for itself.

Joseph Allman – J.P. Morgan

What reserves did you have booked at Blueberry Hill at year end?

James Moffett

I think we had about I think it was close to 30 bcf.

Kathleen Quirk

Our share was roughly 7.5.

James Moffett

So once again we have to use the number in this case. Our conservatism turned out to be right because if you had taken the up dip stuff we’d have a lot more. But let us get this Sidetrack done. As I said, we’ve got the big shale mass. We’ve got the big sands. Now we’re frustrated. Let’s just wait and let Mother Nature show us the way here.

Joseph Allman – J.P. Morgan

Last question just on Blueberry Hill, what you found so far, I mean if 30 bcf grows, that’s in what you’ve found so far. That does not rely on future success as far as you’re concerned.

James Moffett

Absolutely.

Operator

You're next question comes from [Dale Alexander – Darfil Associates]

[Dale Alexander – Darfil Associates]

You require so much land to drill on since 2007. Is there any way you can give us a conservative estimate of what your land is worth now for drilling?

James Moffett

Well, the lease sale that you just saw us go through would be the best way we could sort of give you some ideas about that. If you just go out and look at the acreage bought, $6 million, $7 million acreage prospect. The Apache purchase you just saw take place last week was a lot about land in the Gulf of Mexico, so you know, it’s got an intrinsic value of huge amount depending on the outlook depending how you feel about the wells that have been drilled.

But when you’ve got a 200 by 100 square mile area that you’ve got the lead position, in you can kind of use your own numbers as to how people want to evaluate it on a per acre basis or what the potential is.

Operator

You're next question comes from Joan Lapin – Gramercy Capital Management.

Joan Lapin – Gramercy Capital Management

It seems to me that with gas price where it is, if you’ve got stuff in the ground and you can’t get it out, it’s a long term benefit. Do you think I’m nuts?

James Moffett

No, you’re not nuts. There’s a lot of people would agree with you on that, but it’s still frustrating when we make these projections and can’t meet them, so it’s a question of short term gain versus long term gain. But all of the above is different ways you can look at it.

Joan Lapin – Gramercy Capital Management

One of the leases that you bought, England I think it’s called in that vicinity, there’s a whole bunch of competition owning a zillion sites right around there. You had some leases before but it seems like Mariner and others have a whole bunch more, Chevron, I guess UPL, whatever. So can you talk – you didn’t mention that at all today why you were interested in that particular lease and what you think happens with that area.

James Moffett

It’s just another one of the prospects that we had outlined and we were able to get. That was the only place we had any competition on the big structures we were trying to control, but this is a very, very big fissure. We already own acreage and have production, leases that we bought earlier in the year. So we’ve got another five, but it’s just another indication of how these people view these big ultra deep structures. Some of them cover 30,000 to 40,000 acres, so that six to seven 5,000 acre tracts.

Joan Lapin – Gramercy Capital Management

What’s the attraction to that? What’s the feature there that everybody’s lined up all over it.

James Moffett

Just like the other one. It just so happened to attract attention. More people either had data that they didn’t have on the rest of the play. We’ve mapped the whole area and all of them are very similar.

Joan Lapin – Gramercy Capital Management

So does it look like Davy or what does it look like? Is it similar to Davy or what’s there?

James Moffett

It’s similar to Davy. It another great big closure sitting there in that ultra deep play.

Joan Lapin – Gramercy Capital Management

As far as financing goes, on the last call you talked about the fact that now that you found Davy and this wonderful incredible discovery, that you thought that there would be a parade of investment bankers, bankers and others toward your offices. Has that in fact happened and what could you tell us about that? And also, in that context, I don’t know which of you wishes to answer, what is your preferred method of financing from here forward?

James Moffett

Let’s just answer very simply. The excitement of Davy Jones is well known throughout the industry. There’s a lot of opportunities that are coming to us, but we’re not going to comment on it right now. There are going to be a lot of opportunities, especially as we get more results and when we can talk about it, we’ll be very straightforward with you.

The answer is a lot of option that were out there and are out there, but really it doesn’t serve any purpose to discuss it right now.

Joan Lapin – Gramercy Capital Management

Can we be hopeful that there won’t be more dilution for us.

James Moffett

As I said, we’re going to discuss our refinancing opportunities as we figure out which is the best way to keep the balance sheet.

Joan Lapin – Gramercy Capital Management

How fast, how soon do you think you need to refinance with all of these projects that you have on your plate?

James Moffett

As we said, we’ve got a lot of opportunities. When we get more data, you’ll hear about it. We always keep you informed.

Joan Lapin – Gramercy Capital Management

As far as the, I think there was some conversation about this about an hour ago, but the mechanical things that you need to complete or to continue or to produce or whatever I guess at Blackbeard, somebody asked earlier why it’s 12 to 18 months. What’s taking so long.

James Moffett

We just try to give you a range. We’ll keep you up to date on that one. That’s just a range. If we can do it sooner than that, we’re just as anxious as you are to get the testing on these wells and we’re working every 24 hours a day to get that done. And that’s all we’re trying to do.

Joan Lapin – Gramercy Capital Management

What are the mechanical issues that have to be solved?

James Moffett

Getting the tie back string, the safety valve and the Christmas tree that will sustain the 25,000 pressure. It’s that simple.

Operator

There are no further questions at this time.

Kathleen Quirk

Thanks everyone. That concludes our call. Feel free to call us with any follow ups.

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Source: McMoRan Exploration Co. Q1 2010 Earnings Call Transcript
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