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McMoRan Exploration (NYSE:MMR)

Q3 2011 Earnings Call

October 17, 2011 10:00 am ET

Executives

James R. Moffett - Co-Chairman, Chief Executive Officer and President

Kathleen L. Quirk - Senior Vice President and Treasurer

Richard C. Adkerson - Co-Chairman

Analysts

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Duane Grubert - Susquehanna Financial Group, LLLP, Research Division

Eric B. Anderson - Hartford Financial Management, Inc.

Operator

Ladies and gentlemen, thank you for standing by. Welcome to the McMoRan Exploration Conference Call. [Operator Instructions] I would now like to turn the conference over to Ms. Kathleen Quirk, Senior Vice President and Treasurer. Please go ahead, ma'am.

Kathleen L. Quirk

Thank you. Good morning, everyone. Welcome to the McMoRan Exploration Third Quarter 2011 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 conference call by accessing our website home page and clicking on the webcast link for the call.

As usual, we have several slides to supplement our comments this morning, and we'll be referring to the slides during the call. The slides are also accessible using the webcast link on mcmoran.com. In addition to analysts and investors, the financial press has 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 our comments today, we'd like to remind everyone that today's press release and certain of our comments on this call include forward-looking statements. We'd like to refer everyone 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 are McMoRan's Co-Chairmen, Jim Bob Moffett and Richard Adkerson. I'll start by briefly summarizing the financial results, and then turn the call over to Richard, who will be reviewing our recent performance and outlook. As usual, after our formal remarks, we'll open up the call for questions.

Today, McMoRan reported a net loss applicable to common stock of $9.4 million or $0.06 per share for the third quarter of 2011 compared with a net loss applicable to common stock of $25.3 million or $0.26 per share for the third quarter of 2010. Our third quarter results included just about $23 million in insurance proceeds related to recoveries from losses incurred from the 2008 hurricane and $37 million in charges, including $15 million for unproductive workover expenses, $11 million in impairment charges to reduce certain fields net carrying value to fair value and $10 million in charges for adjustments to our asset retirement obligations associated with a certain of our oil and gas properties.

The third quarter 2011 production averaged 187 million cubic feet of equivalents per day net to McMoRan. That compared with 146 million cubic feet of equivalents a day in the third quarter of 2010. Our production in the third quarter of 2011 was higher than our previously reported estimates of 180 million a day because of favorable production performance.

Our third quarter 2011 oil and gas revenues totaled $134.5 million. That compared to $90.8 million in the third quarter of 2010. We had realized gas prices in the third quarter 2011 of $4.38 per Mcf. That was slightly below the year-ago period's average of $4.61 per Mcf. And our realized prices for oil and condensate averaged $100.94 per barrel in the third quarter of 2011. That was about 33% higher than the last year average of $75.78 per barrel.

Our EBITDAX or earnings before interest, taxes, depreciation and exploration expense totaled $66.7 million in the third quarter of 2011. And our cash flows from operations totaled $42.4 million in the third quarter. We had capital expenditures of $145 million in the third quarter of 2011.

We ended the quarter with a total debt of $562 million, which included approximately $262 million in convertible securities. On October 6, we completed an exchange offer of our $74.7 million of 5 1/4% Convertible Senior Notes. A total of $68 million of the existing notes were accepted for exchange for an equal principal amount of newly issued 5 1/4% Convertible Senior Notes due October 2012. We repaid the remaining $6.5 million of the existing notes, which matured on October 6. The terms of the new notes are substantially identical to the terms of the existing notes, except that the new notes have a maturity date of October 6, 2012.

We ended the quarter with a strong cash position of $642 million. Currently, we have 161 million shares of common stock outstanding. Assuming conversion of our convertible securities, which include the 8% Convertible Perpetual Preferred Stock, the 4% Convertible Senior Notes of our 5 1/4% notes and our Perpetual Preferred Stock, we'd have about 224 million common shares -- fully diluted shares.

I'd now like to turn the call over to Richard, who will be referring to the slide presentation materials included on our website.

Richard C. Adkerson

Good morning, everyone. Slide 3 -- Page 3 includes the highlights for this quarter, the fourth quarter of this year for the third quarter. The fourth quarter of this year is a significant quarter for us because we will be working to complete the Davy Jones No. 1 discovery and conduct its flow test. We continue with our drilling in the ultra-deep program with the Blackbeard East by-pass well, the Lafitte well and with the Boudin well in our deep gas program.

Slide 4 includes the details of the financial report for the third quarter that Kathleen just went over with you.

And then turning to Slide 5, at Davy Jones, of course, we have 2 successful sub-salt wells in this field. The Davy Jones No. 1 well logged 200 net feet of pay in multiple Wilcox sands. And the No. 2 well, located 2.5 miles southwest of the No. 1 well, confirmed our 120 net feet of pay in multiple Wilcox sands, which indicates continuity across this large structural feature and also encountered just under 200 feet of potential hydrocarbon sands in the Tuscaloosa and Lower Cretaceous carbonate sections.

We hold a 63.4% working interest and just over a 50% net revenue interest. And as I indicated this quarter, we are moving towards completion activities, which will allow us to flow test these wells. And then we have a new Wilcox delineation well in the northern part of the structure and a new well planned -- being evaluated to evaluate the Tuscaloosa and Lower Cretaceous sections updip to this well.

Turning to Slide 6. After the initial discovery, we assembled an extensive team of experts to help with designing and planning the completion activities. This team has made great progress in dealing with the technology equipment and the processes that are needed to develop the field. You can see the picture on Page 6 that the installation of the jacket for the production facility has begun. We are in the process of mobilizing the production platform for the No. 1 well in the central processing facility for the field. A rowing rig is -- that we'll use to complete the well will be mobilized in the next few days. To date, everything remains on schedule so that we can flow test the Wilcox sands and the No. 1 well by year end. And we are, of course, looking forward to these important results, which would mark the first production from this significant and emerging new ultra-deep geological trend.

Our team also continues to work on the completion of the No. 2 well. As you will recall, the zones in the Cretaceous that we plan to test in the No. 2 well are deeper than the Wilcox pays in the No. 1 well. In the last 3 months, we've done additional engineering and design work on the No. 2 completion. We now expect to commence its completion and flow test in the second half of 2012. Following successful flow test, we would expect production from both wells to use the new production facilities currently being installed. These facilities have initial capacity of 150 million a day expandable to 275. And production could commence quickly following a successful flow test.

Slide 7 shows the location of the Davy Jones field in connection with the current wells that we have drilling to the South Lafitte and the Blackbeard East prospect. And you can see Boudin is close by as well. With the Blackbeard East well, we commence drilling of the by-pass well at the end of August. That operation began at 30,630 feet. We're currently drilling below 32,000 feet to evaluate Eocene objectives encountered in the original well prior to the mechanical issue that we dealt with during 2011. The original well was drilled to 32,600 feet. The by-pass well is permitted to 34,000 feet. And we hold a 72% working interest and a 57.4% net revenue interest.

Previously, we had logged 178 feet of net hydrocarbon bearing sands in the Miocene, which we announced at the end of 2010. We are planning a 25,000-foot offset appraisal well to evaluate these zones further. And wireline logs have also indicated a potential hydrocarbon bearing sands in the Oligocene, in the Frio section below 30,000 feet, which we announced early this year.

The Lafitte prospect is located at Eugene Island Block 223 in 140 feet of water. We spudded that well just over a year ago. The wireline logs from interim logging operations in September and recent logging operations in October indicate several of the Miocene sands that appear to be hydrocarbon-bearing. The sands have varying thickness that aggregate approximately 250 gross, 150 (sic) M net feet, some of which are contained within a thin-bedded, sand-shale formation. These Lower Miocene aged sands are correlated to Lower Miocene sands seen onshore and in the deepwater of the Gulf and provide additional confirmation of our ultra-deep geologic model.

Lafitte is McMoRan's third ultra-deep prospect to encounter these Miocene aged sands below the salt well. The current depth of the well is 28,400 feet. And we have plans to deepen it to a proposed depth of just under 30,000 feet to continue to evaluate deeper Miocene objectives and possibly encounter the Oligocene section. At Lafitte, we have a 70% working interest and a 58.3% net revenue interest.

Ship Shoal Block 188, which is located within the Blackbeard West unit, which has 25,000 total acres. This location offers us an opportunity to evaluate Miocene sands seen in Blackbeard East above 25,000 feet. Our exploration plan has been approved. The well is expected to commence drilling before year end, and the -- with the rig that's currently on location at Boudin. Proposed depth is 26,000 feet. We have 67.3% working interest and a 51.5% net revenue interest in Ship Shoal Block 188.

At Boudin, which is above salt, is located in 20 feet on Eugene Island Block 26. It began drilling at the end of February of this year. It's drilling below 23,800 feet. We recently obtained approval to deepen the well to 28 -- 24,800 feet to test Miocene objectives. We hold a 53.5% working interest and a 42.4% net revenue interest in that well.

Slide 8 shows these prospects, as well as the whole series of additional prospects that we've identified to continue to evaluate this new geologic trend, which ties in significant production onshore with the significant production in the deepwater. And this is what is evolving out of our program, which gives us the encouragement with our activities.

On Page 9, we look forward to 2011 outlook with an annual average production of 187 million a day, which would be based on 170 in the fourth quarter. Capital expenditures, which are always subject to what we encounter as we drill these wells and new information as it becomes available, are currently estimated in the range of $500 million to $550 million. And our abandonment expenditures, we are estimating at $140 million with $60 million of that we expect to be covered by insurance. We continue to work to obtain additional insurance reimbursements from these hurricane-related claims.

Page 10 shows our model of cash flow sensitivities at current forward prices. Our cash earnings would be $310 million. And we show some variation for changes in oil and gas prices.

That is a summary of the overview. And Jim Bob, I'll turn the call over to you for questions, and if you have any comments, we can have those or we can go straight to questions.

James R. Moffett

We'll just take the questions.

Richard C. Adkerson

Okay, thank you. Operator?

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from Noel Parks with Ladenburg Thalmann.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

I guess what I wanted to ask was about Boudin, just want a little more insight into the deepening there, just what led to that decision whether you are happy with what you are seeing so far? Or didn't see what you were looking for and wanted to go deeper to see if you could find it?

James R. Moffett

It's a little of both. We do have a couple of loams, which are laminated. Obviously, have pay in them. It's a volatile well, which is what's been most interesting about trying to decide exactly what we have. When we drill the well and shut down for any period of time to come out of the hole and change bits or log. The well has up to 4,500 units of gas, untripped gas. So this is a significantly energized session. This thing was drilled on an amplitude that was -- look like a typical Flatrock type of structure above the salt well. We continue -- we have about 1,000 more feet to get to the fault, and so we're encouraged by the amount of hydrocarbons that we've seen so far and the volatility of the well. But the best thing to do is to see if this next 1,000 feet has this type [ph] sands that notes up above to add to what we already have in the well, Noel. And then we'll be able to give you a complete breakdown of just exactly what's in this well.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

And just so I understand, so are you considering or would you consider going beneath the salt weld even at Boudin?

James R. Moffett

No, because the salt weld play below the Boudin well doesn't make up underneath the Boudin. It is a salt feature below the salt weld to the north of us. This is strictly a play for above the salt weld.

Operator

Our next question comes from Leo Mariani with RBC.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Quick question here on Davy Jones. You just talked about this new Wilcox delineation well on kind of the northern part of your acreage position there. Just curious as to when you think that potentially could spud here?

James R. Moffett

Well, on that well, obviously everybody, including us, wants to get the information from the flow test on the No. 1 well. As you can see from the facility we've designed, we anticipate a substantial flow rate from that well. If the flow test is successful on it, with the No. 2 well it was drilled to the south, we know that the Cretaceous has a several hundred feet of potential hydrocarbon. We think updip of that well, which we can get considerably high over 1,000 feet higher to the north, the delineation well now that we have the information on the No. 1 and 2 wells, will add substantial information and delineate the Northwest feature. So we will be anxious to get in and drill it, assuming we get a good successful flow test on No. 1. So you can look for that well to be commenced immediately after we get the flow test and have enough information to go ahead and start the third well.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay. And I guess also with respect to Davy Jones, you guys basically said the jacket's being installed right now, as the platform is getting towed out. Just wanted to ask about the additional equipment that you guys are going to need from that flow test. Is that in the field currently? Is that finished manufacturing? Is that on its way? Can you just give us a status update on the rest of the equipment you're going to need out there?

James R. Moffett

All of the other equipment's available. The BOPs, lubricators, all the tie-back equipment. So there's no showstoppers. When we get on there, we will go right to the completion process, and the team that we've assembled has done a magnificent job of building things for the first time. So we are happy with the fact that the subcontractors as well as our own people have delivered the mail.

Operator

Our next question comes from the line of Duane Grubert with Susquehanna Financial.

Duane Grubert - Susquehanna Financial Group, LLLP, Research Division

Yes, Jim Bob, can you talk to us a little bit about the reserve booking requirement? So I think we're all looking forward to a flow test before December 31. But is there anything specific you've got to have other than just acknowledge that you've got a flow test. What kind of data are you going to get?

James R. Moffett

Well, great question, Duane, thank you. The flow test will, of course, be the clincher here. As you recall, the reason why we have a booked reserve, we have thicknesses and areas extent in all the other things to calculate the volume. But in the Ryder Scott type of reserve, you have to have a comparable and unfortunately, we have to go 200 miles to the south on the Wilcox to talk about the test, the Jack. And we actually go 100 miles north onshore to have any Wilcox comparables. So because the comparables are so far away, we have to basically establish our own parameters. So the flow test, assuming it confirms that the potential of these sands are what we anticipate, will immediately give us the information for Ryder Scott to take the thickness and the area extent with the 2 wells that we've drilled and put a recoverable factor on it and give us reserves based on those area extent. Exactly the performance of the well draw down, et cetera, et cetera, will give them and us a lot more feel for how far out there to reach. Because you remember, we think this structure covers over 120,000 acres down to the spill point. We have no water in the Wilcox sands. So if you just look at the thickness and assume 5,000 acres around both wells, 2,500 acres per well, and apply the thickness, you can come up with some fancy numbers. We've talked a little bit about what that is. But to answer your question, the flow rate will give them the ability to apply those formulas and give us volumes for the Wilcox reservoir.

Duane Grubert - Susquehanna Financial Group, LLLP, Research Division

And just to put closure on this one question, the timing, I know you guys have it down probably to the day of what you expect each element to be at. Where are you exactly relative to your plan?

James R. Moffett

We're on plan. We're on plan. As you can see, it's been a tremendous engineering feat to basically build the biggest equipment that's ever been built to test these pressures. But it's gone. My team would probably laugh if I said it's gone routine. But it's gone routine as far as we're concerned, though we never had any deal breakers. And the fact is at Cameron, all the other subcontractors have delivered just as we expected them. You may remember that all this stuff had to be tested in labs that were inseparable to the BOEM, formerly the MMS, and all of that went according to order. And that's why I say we've had no deal breakers.

Operator

Our next question comes from the Eric Anderson with Hartford Financial.

Eric B. Anderson - Hartford Financial Management, Inc.

Jim Bob, I wonder, could you just review for us the -- what you've been able to correlate in terms of the sands at Lafitte with Davy Jones and with -- in either Blackbeard East and Blackbeard West in terms of looking at that -- the theory that we've got cheap sands here? And so what have you seen there that you've seen in other wells?

James R. Moffett

Let's see, if we can go to the slides. You can turn back to Slide 7. Slide 7 has got Lafitte, Blackbeard East and Davy Jones. If you remember, Lafitte being west of Blackbeard East, and that gives you the so-called Miocene, Frio trend, possibly Wilcox with depth. And what I would say is that we've seen in the Lafitte structure, once we got under the salt weld, which if you recall, and we have some reference maps on the back of the slides, is at about a 45 degree angle. And that whole platform out there, which encompasses the Lafitte field, the Lafitte prospect, and Captain Blood and Barataria. Once we got under the salt weld, we started seeing a series of Miocene sands that were Lower Miocene in age and approximately equal to the sands that we saw at Blackbeard West and Blackbeard East. So what you see there is that gives you 2 points of control on this 200,000 acre, 200 square-mile area, which we refer to as the shale. Now what you can do with that, Eric, you can take and say, okay, I've got an Eastern well that has Miocene sands, with Lower Miocene, in the Middle and Lower Miocene age. And now we have a well at Lafitte on an East-West axis that has a 220 and 115 feet in it, and the sands are the same age. So that would give you the license based on what we've seen onshore to say that the wells you drill on that trend should all have the same opportunity for sands in this age. That's the kind of data we needed to start to put some parameters on where the trends could be comparable. As you remember, everything as far as the coastline, the recent coastline, if you look at the trend in the deepwater, all the deepwater wells after the discovery of the Thunderhorse, all are lined up east, west in the Miocene and the Wilcox trend. So suffice it to say that we've seen sand that give you the same data that we really -- that we've established in deepwater and have had established onshore because of all the drilling there. So to answer your question succinctly Eric, we believe that the Miocene sands will exist as we have predicted based on the drilling we've done. And we expect the Wilcox and Cretaceous sands to be on an East-West axis present in the Northern trend. We also have, of course, the Frio sand and the Blackbeard East well. If you look at that, that gives us a lot of hope that as we penetrate the Frio section in the Lafitte well as we drill deeper to the north, if you just look to the north, onshore just north of the Davy Jones, that whole area to the Central Louisiana in what we call the Frio trend has trillions of cubic feet of gas on fields out there like Chocley [ph] and Kappa [ph], South Jenning [ph], big thick Frio sands and the whole Frio channel it was feeding. The Frio sands, is just north of Davy Jones. And we believe that with the Wilcox sands that were developed in the deepwater and that the Frio sand, which didn't make it out to deepwater could be thickest right in the trend with Blackbeard East and Blackbeard West and Lafitte. We need to deepen this Lafitte well to prove that. The most important thing I'd say about the Lafitte well, is once we've got on the lower part of the salt weld, we saw one wet sand. And then from that point on as we drilled in the last couple of thousand feet, every sand we've seen has had hydrocarbon indicated by log analysis. So that gives us a really good feeling that these multiple sand, the stack and the layered-keg geology is just like it is onshore and deepwater. No reason to believe that our model hadn't been confirmed just as we hope it would.

Eric B. Anderson - Hartford Financial Management, Inc.

Does it feel you make optimistic about either Drake or Barataria?

James R. Moffett

Well, Drake is somewhat deeper and will be mostly Wilcox and Cretaceous. Just because of the depth at which it makes up, it gives you a lot of -- the most obvious value has been added to these Captain Blood trenches, which is to the south of -- just to the south of Lafitte, and the same platform that's delineated by this big down to the north striking salt weld/fault. So -- and Barataria are basically in the same big fall block. So Drake, all the rest of the big structures, they all have additional value now as a result of the fact that we're proving sands and hydrocarbons.

Operator

Our next question comes from the line of Richard Tullis with Capital One South.

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

Just a couple of quick questions for you, Jim Bob. What's the thickest sections you've seen to date in the Lafitte well?

James R. Moffett

The thickest section -- thank you for the question. We've -- the thickest section we've had is what we call the 26,000 sand, and it could be gross thickness of 130 to 160 feet. And what it is, is what we call an over bank levy channel. And as usual, we have to go a long way to compare and look for the analogy. The best analogy for this, Richard, is, as you pull this data upon your computer, is a field called Ram Powell, which is to the east of this, right off the mouth of the Mississippi River. And in that Ram Powell area, there's several fields that we're drilling out to shelf are Ram Powell. And the interesting part about this section is it's laminated. You heard a lot of those words, and it's -- was it 226 main barrel field? And the interesting part is that the channel part of the system, which is basically the channels that carry all this sediment out in the deepwater where the more blocking overlooking sands, whereas the over bank levies have a tendency to look, I'll call it like a Christmas tree, where there's the laminate star at the top. And you get more sand -- sandy as you go to the bottom. And this Christmas tree-looking feature has great permeability and porosity because you have these laminates, which are just as porous and permeable, as a blocky sand. But they are interbedded with shale, much like a bar of clay, becomes off the front of a glacier. So the real answer is, that sand by itself, is going to be a substantial reservoir on seismic. The 26,000 sand is coincidental with the reflector that runs for about 8.5 miles to the south of this well, which should give you some idea of how big some of these reservoirs that we've seen in the Lafitte to be. Because you don't have a lot of steep dip. It's kind of a general dipping three-way closure up against this big -- down to the north fault. And that fault is a huge thick sized event because it faults Upper Miocene on the down-tone side of that salt weld/fault juxtaposed to the Lower Miocene. So you have a 4,000 to 5,000-foot dam, if you will, sitting there and that's what's trapping the multiple sands. The model we compare this to when we identified the prospect was the Tahiti Field in the deepwater. So I hope that gives you some feel which it is to why we feel that the Lafitte well is once again fitting our model with the layered Miocene sands. And it's these analogies like Ram Powell, where -- they are logged down. It's a Ram Powell log, and it looks like they were drilled in the same field. Now we're having to reach their probably 200 miles to the east of the mouth of the river. But it is a huge -- great comparison to be able to find these Miocene sands that look from a topography standpoint comparable to some of these other fields. I hope that you continue to see that when we're having to go the 100 miles to 200 miles away on what has been known as a very explored shelf, it reminds you just how wildcat it is, and how big a slice of real estate was left out when the deepwater play was drilled off the shelf and into the deepwater. And this big slice of real estate, it has all the 50,000 wells above 20,000 feet producing. And we haven't reached as far to find any relative analogies. It always verifies the lock-in nature of what we are doing and how much is still left to be proven. And that's why we put the big potential on it.

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

Well, thank you, that's helpful. And then just lastly, the Boudin well, what was your pre-drill estimate for reserves on that one, Jim Bob?

James R. Moffett

I think it was in the 200, 300 Bcf range depending on how many zones we found and what the thickness was that would correlate with this big velocity event. I think you've all seen the cartoon of just how big this velocity event is, that represents this sort of drag full feature right out of if I wanted these big deposition of faults. It looks -- it's just like -- do we have a slide in here that compares it to Flatrock? So it's all about thickness. And that's why we're trying to get the well drilled deeper to see just how many of these hydrocarbon areas we can identify.

Operator

And your next question comes from the line of Duane Grubert with Susquehanna Financial.

Duane Grubert - Susquehanna Financial Group, LLLP, Research Division

Jim Bob, in terms of the learning curve of cost on drilling these very impressive wells, if we were to look back 2 or 3 years from now, what do think is going to be the most different about the way you guys drill the wells in light of what you're learning from well to well and cost?

James R. Moffett

Great question, thank you. What we've learned and this is going all the way back to the first well we drilled at Blackbeard by Exxon, is that the big hole that we and everybody else thought was going to be necessary to get the proper hole size when we got below the salt weld, we've been able to establish that the so-called expandable casing that we were on will let you drill these wells without having to start with a 24-inch hole. Because that's what really clocks you when you try to drill these wells, is drilling these 24-inch hole down to some intermediate depth of 12,000 to 15,000 feet and trying to set 20 inch. As far as we're concerned, that's taboo. We've been able to convince ourselves that we can go on these wells with no bigger than 16-inch casing. In some cases, 13 3/8. Now without getting in a lot of detail and boring anybody on the call, the reason that, that is possible is because we've had so much experience with these expandable liners in our play, which we call our deep-gas play, on the shore at Flatrock and JB Mountain, Long Point, some of these areas where we're drilling deeper. And we've been able to prove that the -- that you can use 3 or 4 of these expandable liners. And that they -- we've had absolutely 0 failure. We set these liners that you might run at 7-inch to expand to a 10-inch, when you run it and expand the liner. And what that lets you do, is to keep an 8.5-inch hole, which is what we did at the Davy Jones No. 2 well. So that you can use -- you can get logs, and data down without having to spend the money to do it on drill pipe and take multiple times to ever successfully evaluate the well. So the other thing that's really significant is, as we've seen at Lafitte and just talked about the sands there start just below 25,000 feet, just like we saw at Blackbeard East. So we've got a significant part of our objectives, if you will, when you put the measured section. And the measured sections is what we will put together that shows the sands we've drilled from the Miocene, Frio and Wilcox and now Cretaceous. And we can -- we now have from Lafitte to Blackbeard East a trend of Miocene sands that are right above 25,000 feet and below 25,000. But not in the 30,000 to 32,000 foot range, as was the case at Blackbeard West. And so from our standpoint, those wells can be drilled definitely with a 13.3-inch casing. And a good example would be that we've now drilled to 24,000 feet at Boudin. And our Wilcox is just over $50 million. So -- and we still have a big enough hole to take a completion where we could run tubing with a big enough size to get these 70 million to 100 million day flow rates. So again, without boring anybody, the pipe programs that we've been able to use and make a part of our well plan now, we've proved that the expandable liners don't burst with the heavy mud, et cetera, et cetera. So I hope we can move these wells in the 25,000 to 27,000-foot range to where we have a target of doing for $50 million to $60 million, as opposed to having to the same that you're going to have $125 million, $150 million, a well. And once again, we will try to talk about this when we have some conferences where we're looking eyeball-to-eyeball. We'll put some of these casing designs up, and show you how much that -- what a revelation it has been to get to a point where we can use the expandable casing as opposed to conventional casing, and not require the multiple streams of conventional casing that you have to start with such a big hole at the surface. That in itself has a potential to save up to $100 million per well.

Operator

Our next question comes from the line of Eric Anderson with Hartford Financial.

Eric B. Anderson - Hartford Financial Management, Inc.

We've had a number of months now of production from the Laphroaig well. And just wondering how that makes you feel about what you're going to do next with that prospect.

James R. Moffett

The well has continued to perform right in line as what we thought. It's indicating that the reservoir has some size to it. How big it goes to the north, Eric, we're still trying to acquire some more data. To get that done, the land situation is what -- somewhat complex to the north. But based on that well, we feel like you ought to be able to go to the north and shut off the structure with some sort of a faulting.

Eric B. Anderson - Hartford Financial Management, Inc.

That means potentially in 2012, you might be drilling a follow-up well to that one?

James R. Moffett

I think that there's a definite north offset location that will have to be drilled regardless of what the seismic looks like because we know we're on the south dip. The only way that the reservoir can expand is to the north. And it's just a matter, Eric, of deciding how far north we want to step out. The conservative way would just be to move north and sort of walk our way up the structure and to see how far it stands to the north. Frankly, because of the lack of the deep seismic that we need. We had thought the fault closure was closer to us as you went north. But the performance of both the Peterson well and this well, strongly suggests that the reservoir's bigger to the north. How much bigger? Is it another 100 Bcf bigger than we thought? Does it go 2 locations to the north and end up being bigger than the 100 Bcf play? That's the lock-out part of this thing. But nothing but our optimism from the performance of the well so far.

Operator

And there are no further questions in the queue. I will now turn the call over to management for any closing remarks.

James R. Moffett

Thank you, and we appreciate everybody being on. I'll just summarize and say one more time. The fact that we've got some key parts of control on both the north, south, and now the east end of this 200 square mile area on the shelf, we think that the model's being confirmed. Obviously, the flow test at Davy Jones that we've discussed in detail here is going to be critical. All our eyes are on that as they say. But we're happy that we're pioneering an improving trend like the Gulf of Mexico and the fact that we've stacked reservoirs on top of each other as has been done in the deepwater and onshore confirms that this is layered-keg geology. And that the brothers and sisters to the north, onshore and to the south, give us great anticipation as we fill in this area. And hopefully, with the success of the Davy Jones flow, assuming we get to what we're looking for, and the success we've had in drilling in Lafitte and the Blackbeard area and Davy Jones, there'll be other prospects that will be drilled by other operators. The reason why we don't have any more data than we do is that like it or not, we're the only ones drilling on the shelf as opposed to the deepwater trend, once the Thunderhorse discovery was made, and 8 or 10 companies jumped in, drilled 40 wells in the first couple of years. And that's why that trend developed so quickly. We think the same thing will happen as we get more optimism from proving the reservoir capabilities. As you know, there's a well being drilled almost to the -- over by the Sabine Pass. It's targeting the Wilcox. Don't know what the outcome of that well is going to be. They're in the Wilcox. So we ought to be getting some information. And there's a lot of other activity that we hear that people are sort of watching what we're doing. So we'd be pioneering in this area on a true walk-out play that has a significant Bcf potential that we've stated. We think that, that puts us in an unusual position since we control so many of the other prospects. So thank you for being on the call. And hopefully we'll be able to get you some more information quickly on all of these wells that we've been discussing.

Okay, operator, we'll terminate the call.

Operator

Ladies and gentlemen, and that concludes our call for today. Thank you for your participation. You may now disconnect.

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