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Executives

Kathleen L. Quirk - Senior Vice President and Treasurer

Richard C. Adkerson - Co-Chairman

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

Analysts

Leon G. Cooperman - Omega Advisors, Inc.

Duane Grubert - Susquehanna Financial Group, LLLP, Research Division

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

Eric B. Anderson - Hartford Financial Management, Inc.

Joan E. Lappin - Gramercy Capital Management Corp.

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

McMoRan Exploration (MMR) Q4 2012 Earnings Call January 18, 2013 10:00 AM ET

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, and welcome to the McMoRan Exploration Fourth Quarter 2012 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 homepage and clicking on the webcast link for the conference 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 accessible on the Webcast link at 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, 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 the slide materials. As usual, after our remarks, we'll open up the call for questions. Today, McMoRan reported a net loss applicable to common stock of $1.2 million, $0.01 per share, for the fourth quarter of 2012 compared with net income of $28.4 million or $0.16 per share for the fourth quarter of 2011. The fourth quarter 2000 [sic](2012) results include $39.7 million in net gains associated with the sale of 2 traditional Gulf of Mexico property packages and impairment charges totaling $34.5 million.

Production for the fourth quarter of 2012 averaged 119 million cubic feet of equivalents per day, net to McMoRan, that was in line with our previous guidance and compared to 170 million a day in the fourth quarter of 2011. Our oil and gas revenues during the fourth quarter totaled $80.6 million compared to $118.6 million during the fourth quarter of 2011.

Our realized gas prices in the fourth quarter of 2012 were $3.68 per Mcf, as compared with $3.57 in the year-ago period, and the realized prices for oil and condensate averaged $104 per barrel in the 2012 period compared with $111 per barrel in the year-ago period.

Our earnings before interest, taxes, depreciation, amortization and exploration expense totaled $37 million in the fourth quarter of 2012. We used cash in operating activities totaling $28.9 million, which included $31 million in working capital uses and $28 million in abandonment expenditures.

Capital expenditures during the quarter totaled $89.5 million. We ended the year with $557 million in total debt, which includes $257 million in convertible securities, and we ended with a cash position of $114.9 million.

We currently have 162 million shares outstanding. And assuming conversion of our remaining convertible securities, McMoRan would have approximately 224 million shares on a fully converted basis.

The press release contains an update on our announced transaction whereby Freeport McMoRan Copper & Gold would acquire McMoRan for per share consideration consisting of $14.75 per share in cash and 1.15 units of a royalty trust, which will hold a 5% overriding royalty interest in future production for McMoRan's existing ultra-deep exploration prospects.

In connection with the transaction, the royalty trust form was filed with the SEC, a registration statement on Form S-4 that includes a preliminary proxy statement for McMoRan, that also constitutes prospectus for the royalty trust. We expect to conduct the shareholders meeting for the vote in the second quarter and close the transaction at that time.

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

Richard C. Adkerson

Thank you, Kathleen. On Slide 4, we have the highlights from the fourth quarter. And during the quarter, we continued to advance our ultra-deep exploration and development activities. We have 2 rigs drilling ultra-deep wells currently. Both of those are located onshore. At the Davy Jones No. 1 well, operations continue in our efforts to conduct a flow test on the well.

As previously disclosed, we completed the sale of 2 packages of conventional non-core Gulf of Mexico oil and gas properties during the fourth quarter. And our results in the quarter include a $40 million gain on these transactions. And in this announcement, we are disclosing that we recently completed the sale of the Laphroaig Field onshore for $80 million.

Slide 5 includes the financial results and is there for your information. Kathleen just summarized all of this information. Slide 6 includes our reserve roll forward for the year. Important to note that this does not include any reserves or results from our pending ultra-deep activities, but the progress with our production activities and development activities will allow us to add reserves when that information becomes to the point of where it meets SEC standards.

We did include, in this year, revisions, principally from upward revisions, for our positive production performance from Flatrock, which resulted in additional reserves for the year.

The Flatrock field is summarized on Page 7. This continues to be a positive story for us by year end, including current reserves and historical cumulative production. You can see that this field is a 500 Bcf equivalent field, and we continue to produce from it and have behind pipe reserves that we'll develop and continue to aggressively achieve production for it.

Page 8 summarizes our ultra-deep, sub-salt drilling program, which we call our sub-salt franchise. It shows the progress that we've made to date in terms of having successful drilling activities, acquiring acreage positions, dealing with the technology challenges of drilling and completing wells. And we have had positive drilling results from 7 wells drilled to date, in which we found sands that conform with our geologic model and have indications of positive future significant production opportunities.

Slide 9 shows the map of our current status of the report. At Lineham Creek, as we previously reported in November, this well located right on the shoreline of Louisiana, it's operated by Chevron, has encountered what appears to be hydrocarbon-bearing sands above 24,000 feet as identified by wireline logs. The well is targeting objectives below the salt weld. It's currently drilling below 26,500 feet towards a proposed total depth to test the primary objectives down to 29,000 feet.

The Lomond North ultra-deep prospect, which is located in what we call the Highlander area in St. Martin Parish onshore in Louisiana, is drilling below 13,500 feet. This has a proposed total depth of 35,000 feet and is targeting multiple sand target objectives below the salt weld.

The Blackbeard West No. 2 ultra-deep exploration well in Ship Shoal Block Island 188 in the shallow waters of the Gulf of Mexico was drilled to a total depth of over 25,500 feet in January. As previously reported, we set a production liner, which would enable completion. We're preparing to release the rig. Through logs and core data, we have identified 3 potential hydrocarbon-bearing Miocene sand sections between approximately 20,800 feet and 24,000 feet. Initial completion activities are expected to focus on the development of sands in the Middle Miocene section of the well, located about 24,000 feet. Our pressure and temperature data indicate that completion at these depths could be done using conventional equipment and technologies.

Operations at the Davy Jones No. 1 well to achieve a flow test are ongoing. During January, we reperforated the Wilcox zones in the well with through-tubing perforating guns. Recent operations confirm that the perforations are open and that fluid could be injected through the perforations into the formation. We're currently evaluating plans to pump a hydraulic fracture treatment to facilitate hydrocarbon movement in the wellbore. We plan to incorporate the information we got from Lineham Creek, involving core data and log data, in evaluating future plans for the Davy Jones No. 1 well.

The completion and testing of the Davy Jones No. 2 well is expected to commence following the review of the results from the No. 1 well. This is a well drilled on the same structure with a larger wellbore, and we look forward to testing that well.

Development plans to complete and test the Blackbeard East and the Lafitte well are pending approval from BSEE.

Slide 10 has a cross-section of the Lineham Creek well. As mentioned earlier, we're drilling below the salt to evaluate the primary targets in Eocene and Paleocene below the salt weld down to 30,000 feet.

This is an exciting opportunity for us to take this concept that began in the shallow waters onshore, and success here indicates a series of potential prospects extending further onshore to the northeast.

Slide 11 is an aerial map of the Lomond Creek structure in the Highlander area, the prospect covers 30,000 acres.

Slide 12 summarizes the gross unrisked potential of the shelf prospects, which are significant. Offshore, we see unrisked potential of a very large amount of 100 Tcf, and onshore, 30 Tcf. These are very large structures with -- which provide for this potential for us to review.

To give an indication of what this might mean to us, we have our model, which we shared with you before, on Slide 13, to illustrate the significant value potential of this ultra-deep play. It shows the value for each 4 Tcf equivalent gross, and our interest is roughly half that based on drilling and completion cost of $200 million for each well and recovery of 200 Bcf on a model basis. Including facilities cost, we'd have finding and development costs of approximately $1.50 an Mcf, and this just illustrates just how very significant value could be added with success in our program.

And finally, on Slide 14, we have a summary of the efforts we are undertaking to use our Main Pass Energy Hub as a potential deepwater port facility and terminal to offload natural gas to floating LNG vessels for export. This of course is the facilities that were part of our former sulfur mine at Main Pass 299. It's located offshore, just east of Venice, Louisiana. The project would use these existing structures that are on the site in roughly 250 feet water. Many of you will recall that the site was previously approved in 2007 as a deepwater port for the import and regasification of LNG. And now we're looking -- as other former regas facilities, we're doing for the potential for exported natural gas.

In January, we obtained approval from the Department of Energy for the export of domestically produced LNG by vessels from this facility to countries that have entered into free-trade agreements with the U.S. We are preparing an application to be able to export to other countries. The proposed modification of this facility would accommodate offloading to floating LNG vessels, and that would require some additional permits and commercial arrangements to justify the significant capital. To do this, we have a partner, United LNG, which is working with us to develop commercial relations that will allow this to go forward.

So that is a summary of where we stand with our program and our efforts. And with that, Jim Bob, I'll turn the call over to you.

James R. Moffett

Richard, let's just take questions and answers. I think that'll be the best place for me to jump in.

Richard C. Adkerson

That sounds good.

Kathleen L. Quirk

Operator, we'll open the call for questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question will come from the line of Lee Cooperman with Omega Advisors.

Leon G. Cooperman - Omega Advisors, Inc.

Maybe I can ask you to peer into the future, if you're willing to. And to make it easy for you, I'll give you the assumptions that I'm going to give you for the questions -- surrounding the questions I'm asking. The deal closes in the second quarter as expected. Your planned drilling program moves ahead as you anticipate. You find in the ultra-deep what you think that you have. When does the first income flow come to the royalty trust owners?

James R. Moffett

Looking at our portfolio of prospects, the onshore well will probably come on first, and Davy Jones No. 2 and No. 1 would be on about the same time. In other words, we have the facilities in place for Davy Jones, and we will put that on when the wells are complete. And because of the onshore wells being above 25,000 feet, prospects that we now see as a result of -- the result at Lime Creek. So those would be the most likely to come on first, Lee.

Leon G. Cooperman - Omega Advisors, Inc.

Okay. But whether this translates, would you guess -- if at all goes according to your plan, do you think we're 2 years away from cash flow to the royalty trust owners?

James R. Moffett

Certainly.

Leon G. Cooperman - Omega Advisors, Inc.

I'm sorry, I didn't hear you. I apologize.

James R. Moffett

Yes.

Leon G. Cooperman - Omega Advisors, Inc.

Okay, good. Well if -- Jim Bob, if you're right on what you have in the ultra-deep, isn't the potential for the royalty trust to be worth almost as much as we're getting for our shares in MMR? Especially if you're right.

James R. Moffett

If you're saying the success rate that we hope to have, Lee, that's certainly something that would be achievable.

Operator

Our next question will come from the line of Duane Grubert with Susquehanna.

Duane Grubert - Susquehanna Financial Group, LLLP, Research Division

Jim Bob, on the news with the Davy Jones status, you mentioned that you've reperforated it, you know the holes are open, and you're thinking about doing a frac job. Can you walk us through what do you visualize? Is it near bore damage? Or why would you be thinking about a frac job? And how big might that job be?

James R. Moffett

Duane, if I knew the answer to whether this thing, this small frac, would accomplish what we think it will -- the problem is the near-bore damage. We can pump into it, but since we don't have any profit [ph] in the fluid that we're basically doing a liquid fluid frac with, we don't get the profit [ph] in the fracture. And therefore, the fracture appears to want to close when we quit pumping. That's why we're talking about getting some profit [ph] in there, in the mini frac, like the liquid frac, which was successful in showing that all the perforations are open. And the best way, with one of these deals, you've got to just take it step-by-step, and we've had a lot of steps here. But based on the D-sand that we perforated back when -- in March of last year, when we didn't get the perforating gun to fire off to [ph] the F sand, that information, what we hope to do that will leave [ph] all of our perf open, is to get some profit [ph] so that the near-hole sand [ph] damage can let the reservoir flow into the borehole, and then we will get a better idea of whether or not that borehole damage can be fixed with the mini frac. And that may lead us to a conclusion that we need to go to a bigger frac. But you've got to stay -- as you know better than anybody, you've got to take your time and not get too far ahead of yourself when you put in fluids, and especially the size of frac that you're going to do. It's a small frac. When we get past the near-hole sand [ph] damage, then you do it, and you don't go in there and -- with a [indiscernible]. So we hope that we -- that this mini frac, 100,000 pounds of sand or more, getting in here [ph] and that, in this formation, have a chance to be to exposed to the bore with that [ph] sand [ph] damage, we'll get a good idea of how effective that is and whether or not we need -- what that'll do is do the trick like this [ph] were a cleanup or whether we need to go through a larger frac.

Duane Grubert - Susquehanna Financial Group, LLLP, Research Division

Okay. And just a quickie on reserves. You guys used the words preliminary assessment of reserves. Is the book still open as to whether or not Lineham Creek might be bookable for end of year 2012?

James R. Moffett

We are looking at that very closely. As you know, the big problem is we've got to meet SEC standards. So you've got to have enough information that your independent engineers can go by the book and qualify the reserves as proven. So we got a lot of information there, Duane, and we should be getting to the point to have enough information to -- because the reservoir [ph] , 25,000 feet. And the data is -- we're getting the data as we drill deeper in the Wilcox. And so we're close to knowing whether we can qualify those reserves by -- to get them in 2012. But we just need a few more things to meet the SEC requirements.

Operator

Our next question will come from the line of Noel Parks with Ladenburg Thalmann.

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

I just had a quick question. I noticed the Lomond slide that you had in the presentation, Slide #20. I just was curious about what you could tell us about the well location choice. It looks like it doesn't avoid the salt as much as it apparently could. But on the other hand, it looks like it's also targeting a bit shallower then you would have, I guess, further southeast, if I'm reading it right.

James R. Moffett

Say, Noel, try that bit one more time?

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

Just interested in hearing about the Lomond well location, just how you chose that particular location and its position relative to the salt?

James R. Moffett

Well, what we tried to do was to be far enough away from the salt that we don't get tangled up in it. But be as high on the structure as we could with this test so that we would be in a position to test both the Yegua, the Wilcox and the Cretaceous.

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

Great. And just one thing to -- just to make sure I understood. Did -- in the prepared remarks at the top, did Richard say that the data from Lineham Creek actually could be helpful in figuring out how to do the stimulation at Davy Jones No. 1? Did I get that right?

James R. Moffett

What we're referring to there is the Lineham Creek well is on strike with the Davy Jones. And what we hope to do with -- as we get into Wilcox, and since we got the bigger hole being drilled, we hope to be able to get the conventional cores at the end of the Wilcox section. Now if we can get a conventional core out of that well, let's just see what the petrography of that rock is. In other words, since it's really on strike and about a similar depth, any information we can get that would let us see what the rock looks like in a conventional core, which we weren't able to get out at No. 1, could you give you a lot of insight into what the quality of the rock is, et cetera. So what it means is, Noel, is as we drill, England, for instance, which is right between Davy Jones and Lineham Creek, hopefully by that time, we'll have completed the Lineham Creek well. And any of that reservoir data that comes from one of those wells that's on strike with the Davy Jones or England or Lomond North, all of those wells in that trend would've ended [ph] . One data point can give you another technical bit of information that can be very important to the whole trend. In other words, if you remember our comment, we have a 200 by 200 square mile area here that goes from the shelf all the way to the Tuscaloosa trend north of Baton Rouge. And if you look at the data on some of our slides, we've got 5 or 6 data points in a 200 by 200 square mile area. So even though the Lineham Creek is 55 miles away from Davy Jones, if it's on strike, if you remember, all these trends run parallel to the coastline. So if you find the sand and you can correlate it to your Davy Jones well and vice versa, then if we got information on any of these wells that are on strike with each other, that gives us more data than the individual wells have had. It can tell you what your petrography of the rock is like, what's your porosity, your perm, what the analysis of up-hole core is versus the sidewall core. In some cases, you can't even got good samples that might not be too viable [ph] to investigate in the core lab. So that's what we're talking about, Noel. As I've said many times, out in the deepwater, where you got all these big structures that have been pursued for the last 5 or 6 years, that you have 20 operators out there. Today, we only have, on the shelf and onshore, we only have our wells and the one well that's being drilled by Chevron at Lineham Creek. And so any data points you get, especially if you're looking at the Wilcox, which is basically going to be right in this very shallow water shelf and then onshore. And if you look at the Miocene on the shelf, those wells are going to all relate to each other and we will be able to correlate the darn things because you can correlate them on seismic. And we've seen already, in the wells that have been drilled, the idea that the wells are on strike, and following the coastline on these various bio-stratigraphic units, would give us a big opportunity. So once again, not to get away from answering your question, definitely, information from Lineham Creek and the Wilcox will be important to help us try to understand what the rock in the Wilcox, and possibly the Cretaceous, look like. And if you'll notice that England is a prospect that we and Chevron control. It is about halfway in between Lineham Creek and Davy Jones and includes Davy Jones West, which we also own in conjunction with Chevron, that's right on strike. So I hope that just sort of gives a feel for what corridor, to put it into geo morphilizing [ph] terms, any corridor that we see that is bio-stratigraphically equivalent across this whole area will give us more data, so that's the reason why we made that reference.

Operator

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

Eric B. Anderson - Hartford Financial Management, Inc.

I wonder if I could get you to talk a little bit more about Slide #14, which is the company's efforts to export LNG. I know at this point, there must be at least a dozen export facilities that have been proposed for the United States. And I'm wondering, if we look sort of down the road, you've got a much different approach here in that you'll be exporting from a water location. And obviously, that comes with some benefits, maybe some little more complications. But just wondering if you could frame for us sort of the company's value proposition for doing it this way and how that may help ultimately being one of the dozen-or-so facilities that really gets this industry going a few years down the road?

James R. Moffett

Thank you for the question, Eric. The quick answer to that is, is it because it's the only the facility that's away from the coastline. It's in 200 feet of water, it's out there but you can bring the big ships in. As you know, there have been a lot of publicity with this LNG. We saw 4 or 5 years ago, people were worried about these big tankers coming all the way into the port on the coast, worried about whether the change [ph] might represent an explosion hazard, biohazard and all that stuff. So just the fact that we're 200 feet of water and 37 miles offshore would be the only offshore facility that's being planned. But why, why are we out there? We've got these 2 major structures that all look like 3 football fields long and we've got the type of structural construction that can take the weight already built. So they have to go out there and look at the installation of the structure that can carry the weight that's necessary to put an LNG facility out there in 200 feet of water. I don't know whether the number is $700 million or $1 billion to replace that metal that's already there. And right below it, as you remember, is a salt dome that's 2 miles in diameter. In that salt dome, using a store, using individual caverns, 0.5 billion barrels of oil, you can store Tcfs of gas, and you can do all in natural gas because you do all the natural gas, butane, propane, because once you make these caverns in these big salt domes, which is where all emergency reserve of fuel is today on the coast of Louisiana and Texas, once you make those compartments to store this stuff in these salt dome, it never changes shape, and you basically recover 100% once you put in one of these caverns. So the idea is that you can take the gas, as the pipelines are already in existence, take it out there to the facility, store it in the dome. As you get ready to put this stuff into liquefied natural gas to be able to export it, you just take away some oil [ph] right there out of the storage compartments and put it in the LNG, pump it into the ship and away they go. So the reason why this has attracted people that we're talking to so far is the very thing I just described, that you can buy up gas while it's available and buy it cheap, and put it in this dome, you're not committed to have to limit buying gas just from -- just to keep your facility running. You can buy gas and not have to put it right into the LNG facility. So if you have an event that lets you buy gas at better price, and if you wait into the future, it gives you a predictable price that you can pin down, that's what most likely is going to differentiate this deepwater port for LNG as opposed to being on the coastline.

Eric B. Anderson - Hartford Financial Management, Inc.

So if you got permission to proceed, would you think about ordering one of these floating liquification platforms at a time, because I know that in your diagram, you've got 6 of them here located or listed here, and that would be obviously many multibillion dollars that -- of capital that would be required?

James R. Moffett

Well, obviously, as you know, we have contracts to get the financing. So I think the answer to your question is, Eric, depending on just how unique any flotation just turns out to be, when you look at it in contrast to pursue it on its own land, if we get the contracts and the contracts are financeable to be able to put these floaters in, if we -- it's a -- the volumes of gas is there and the off-site contract to move the gas to wherever we're going to move it are in place. It's a financeable project. And frankly, it wouldn't matter if you have 1, 2, 3 or 4 that are ready to go. If you got the contract on those 4 facilities, then you ought to be able to finance them.

Eric B. Anderson - Hartford Financial Management, Inc.

Okay. Well, I appreciate you going over the differentiating factors that this program represents.

James R. Moffett

Deepwater storage right below the dome changes the whole ballgame. So those 2 things are what makes it different, 200 feet of water and sitting right over the top of one of the biggest salt domes in Louisiana.

Operator

Your next question will come from the line of Joan Lappin with Gramercy Capital.

Joan E. Lappin - Gramercy Capital Management Corp.

I guess, at this point, I mean, we're sort of watching you sell Laphroaig, sell whatever -- some of the other stuff you did last quarter just to kind keep going, and all this money keeps going down the hole at [indiscernible] Davy. Why have you refused to just for now, anyway, move along with Davy 2? I don't understand that because that well was supposed to have long since been on production, and you haven't even started it, the completion of it. And I just find that very perplexing. I understand that this became a science experiment. I understand all of that. But I don't understand what -- is it the fact that you didn't have the money to do both? Or why did you not proceed with Davy 2? And when will you?

James R. Moffett

It's a good question, Joan. Obviously, we get -- each of these decisions that we've been through, we thought would be successful. And so the rig that was on No. 1 was going to go to No. 2. And so what we decided to do was take advantage of all the information that we were getting on the Davy Jones 1, so we'd know how to best get the No. 2 complete. But the answer is, we need to move on. We had the other wells that we discussed earlier at Lineham Creek that got going down to the depths, so it also gave us some more data on what to do and not to do as far as putting different completion fluids on the formations in the Wilcox. And remember, we also have, in the No. 2 well, we have the Cretaceous limestone, which is deeper than the Wilcox. So this consideration of whether you perforate the Cretaceous as well [ph] and see what kind of well it makes, those are some considerations that we need to look at while we are completing No. 2.

Joan E. Lappin - Gramercy Capital Management Corp.

Could you amplify? I'm a little confused now as to what exactly you're doing with Davy 1. I guess, you have -- the guns, did the Schlumberger [ph] guns fire this time, but they didn't fire hard enough or deep enough into the structure? Or -- I'm sort of lost now as to where exactly -- what exactly is going on there. And I...

James R. Moffett

Good question, Joan.

Joan E. Lappin - Gramercy Capital Management Corp.

And I assume the sale of Laphroaig to Energy XXI yesterday is somehow related to all of this.

James R. Moffett

Well, only because we -- they've been joint ventures with us in the onshore and the offshore, and they have -- they wanted to consolidate their interest in Laphroaig and made us an offer that we felt was a good offer. So they just consolidate one of their [indiscernible] interest in [ph]. But it's just coincidence that we were operating with them in the onshore as well as the offshore drilling, that's the only way they're related. But importantly, on the No. 2, what I was pointing out to you is we do have the Cretaceous with pipe running through it. And the information from Davy Jones 1, although we haven't been able to get the well on production, could have given you the information. So that we move on No. 2, you got the Cretaceous, you got the Tuscaloosa and then you got the Wilcox sands, those are your alternatives to completing No. 2. So it's not just the same by saying we got [indiscernible]. We didn't have the Tuscaloosa in the No. 1. We didn't have the Cretaceous in the No. 1. So that's why we're trying to do this in the right order so we know what to focus on when we complete the No. 2.

Operator

Our next question will come from line of Richard Tullis with Capital One Southcoast.

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

Jim Bob, staying with Davy Jones No. 2. How quickly could you move to completion there? Is there any specialized equipment that has to be ordered or is in process?

James R. Moffett

We've got everything that we need. We had to use some of the tubing to replace some of the tubing at Davy Jones 1 that was -- that had a problem. But to answer your question, we have everything we need to get a rig on there. And as I just said to Joan, decide which of those zones we're going to perforate since we have the 3 bio-stratigraphic units, the Cretaceous, the Tuscaloosa and the Wilcox.

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

Okay. And then jumping over to Lineham Creek real quick. Some of the, I guess, valuation work that was done and some of the filings related to the acquisition, I guess, noted that -- or estimated some liquids component in Lineham Creek wells, I guess, somewhere between 15%, 20%, something like that, do you agree with those estimates? And two, what did you see in the Lineham Creek data that you didn't see in, say, some of the earlier discovery wells?

James R. Moffett

Well, the main thing is the possible hydrocarbons above 25,000 feet. As we've said before, with that 25,000-foot level, above it, we have a window that can have the condensate as opposed to dry gas. And then below 25,000, we thought it was going to be predominantly dry gas because of the temperature and the pressure. And in the case of the Lineham Creek well, if you look at the bio-stratigraphic unit that this pay [ph] above 25,000 feet exist, if you go all the way across the trend, even into Texas, we're looking at -- had a tendency to be a rich condensate. So this is more taking these trends that we keep talking about parallel to the coastline. And this one, it looks like it's -- the age of the sands, if they turn out to be hydrocarbon bearing, that appears to be a little lower [ph] . If you correlate those sands across -- even into Texas, you have a band of area that's pretty rich in condensates. Some of the wells in Texas were a little shallower than this one. And these aged rocks have 50 to 60 barrels per million. So since it is a condensate trend, that's why people threw in to the model on this particular zone, Lineham Creek, that you could have 10 million to 20 million -- sorry, 10 to 20 barrels of condensate per million because of the high condensate rates, and they just push down from 15,000 to 18,000-foot level as you get along the trend. And so, instead of making it 50 to 60 barrels a million, because of the increasing temperature, the temperature and pressure, they decided to say there's a condensate, but they didn't go all the way into the sand. It's going to be 50 million to 60 million barrels -- 50 to 60 barrels per million. So that's why as we go onshore and go into the shallower portion of the sub-salt, ultra-deep play, where the temperature and pressure have a chance [ph] to the hydrocarbons, the shallower it gets, the more likelihood that you will have a rich condensate. But if you take this one more step and go up to Flatrock, which, as you know, sits right above the top of Davy Jones, Wilcox, the Flatrock field, what you get is Miocene, so it's younger than the zone at Lineham Creek. But at Flatrock, those wells came on production at 100 million a day of gas and 3,000 barrels of condensate, so and that was around 15,000 feet. So it's strictly a matter of how deep you are and do you have production data in the same bio-stratigraphic unit that would tell you, is it going to be more condensate rich than another? So you make a comparison. So you look and see what's going on onshore in the shale play. The Haynesville and some of those formations were good reservoirs, but they didn't have the high condensate rate. Maybe these other reservoirs are being pursued in the shale play, the Bakken and some of the Eagle Ford, just to have a proven oil lay, they call it in these big reservoirs. And so, it's no difference in that sort of estimation, if you have the same reservoirs to east of you, even though you're 100 miles away, you see a tendency for these wells to be high condensate in these higher pressure wells. So you go to a certain point and they'll be below 25,000 feet, the temperature goes up and the pressure goes up and the formation has a tendency to crack, just like in a refinery, so you end up with dry gas in these deeper, hotter sands.

Operator

I will now turn the conference back over to management for any closing remarks.

Kathleen L. Quirk

Thank you, everyone, for your participation today, and we're available for any follow-up questions you might have.

Operator

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

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