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McMoRan Exploration (NYSE:MMR)

Q2 2012 Earnings Call

July 17, 2012 10:00 am ET

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.

Joseph Bachmann - Howard Weil Incorporated, Research Division

Joan E. Lappin - Gramercy Capital Management Corp.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Duane Grubert - Susquehanna Financial Group, LLLP, Research Division

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

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

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

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 Second Quarter 2012 Conference Call. Our results released earlier this morning and a copy of the press release is available on our website at mcmoran.com. Our 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 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 also accessible on our website. 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-Chairman, Jim Bob Moffett and Richard Adkerson. I'll start by briefly summarizing the financial results and then turn the call over to Richard and Jim Bob, who will be reviewing our performance and outlook. As usual, after prepared remarks, we'll open up the call for questions.

Today, McMoRan reported a net loss applicable to common stock of $75.5 million or $0.47 per share for the second quarter of 2012, compared with a net loss of $50.2 million or $0.32 per share for the second quarter of 2011. Our second quarter 2012 results included a charge to exploration expense for noncommercial well costs, primarily associated with the lease expiration of the Boudin well, totaling $56.3 million, $11.2 million in charges for adjustments and asset retirement obligations and a $4.6 million charge for impairments to reduce certain field's net carrying value to fair value.

Our second quarter 2012 production averaged 140 million cubic feet of equivalents per day net to McMoRan as compared to 197 million cubic feet of equivalent in the second quarter of 2011. Our production in the second quarter of 2012 was slightly below our previously reported estimate of 145 million a day in April of 2012, because of some unplanned downtime for repairs to platforms and third-party pipelines and some weather-related shipping delays.

Our second quarter 2012 oil and gas revenues totaled $87.2 million compared to $155 million in the second quarter of 2011. Our realized gas prices in the second quarter of 2012 were $2.44 per Mcf compared with $4.71 in the year-ago period, and our realized prices for oil and condensate averaged $109 per barrel, similar to the year-ago period.

Earnings before interest, taxes, depreciation and exploration expenses, or EBITDAX, totaled $48.3 million in the second quarter of 2012, and our operating cash flows totaled $11.7 million. And those were net of $16 million in abandonment expenditures and $9 million in working capital uses. Capital expenditures totaled $147 million in the second quarter of 2012. Our debt totaled $555.9 million at June 30, which includes $255.9 million in convertible securities. And we ended the quarter with $287 million in cash.

McMoRan currently has 162 million common -- shares of common stocks outstanding, and if we assume conversion of our convertible securities would have 224 million shares on a fully converted basis. And now I'd like to turn the conference over to Richard, who'll be referring to the presentation materials.

Richard C. Adkerson

Good morning, everyone. We are pleased to have this opportunity to give you a report on the status of our efforts of following up on this significant geologic success we've identified with the sub-salt trend, vast area spanning 200 miles on the shelf of Gulf of Mexico. And we're increasingly focused onshore in South Louisiana, looking at targets with a very large structures and major potentials, multi-Tcf potential. We also want to talk about the significant investments we've been making in developing proprietary processes and technologies to be able to drill and produce these prospects and what we're learning, where we stand with our current efforts. And success would give us a very significant opportunity to develop low-cost, long-term sources of natural gas.

In the second quarter, we have continued to advance our ultra-deep exploration and development activities. Operations are ongoing at Davy Jones to achieve a measurable flow test. Jim Bob will talk about specifically where we stand with that. We have, in addition to the Davy Jones No. 1 well, we have 2 wells that are currently in progress and drilling, the Blackbeard West No. 2 well and then the Chevron-operated onshore well, just on the coast of Louisiana, the Lineham Creek, onshore prospect. Following the flow test at Davy Jones No. 1, we will then be focusing on completing and testing the Davy Jones No. 2 well. On 2 wells drilled previously, the Blackbeard East and Lafitte prospects, we're working to submit development plans for those prospects in the third quarter.

We have developed a very significant onshore prospect that we expect to spud in the second half of 2012, the Highlander onshore prospect, which would be ultra-deep play, 68,000-acre leased block with a very large structure and again, Jim Bob will be reviewing with that.

We have previously announced in the lease sale that we were a high bidder on 14 leases, 6 were sole bids, 8 we made jointly with our partner, Chevron. And from the successful granting of these bids, and this would really enhance our whole series of our ultra-deep prospects that tie in with the work that we've done, the skills that we've gained and the information that's there.

On Page 5, it's a slide, that's the summary of the data that Kathleen just reviewed with you for your information. Slide 6, just ticks off the activities to date that we have done to advance this technology, as I said, we gathered a lot of information, had a lot of experience, invested a lot of money, but we have shown that these wells can be drilled and evaluated, each well that we drilled has confirmed the geologic model of these prospects below the salt weld. And that's a very significant accomplishment from where we started. We've seen high-quality reservoir, we've developed this expertise and technology for high-pressure, high-temperature completions that gives us a proprietary position in this field. And we are seeing prospects where we have the opportunity of applying conventional completion activities, which would allow us to produce wells at a lower cost.

So we are now moving forward this flow testing, which has taken time and -- but we're nearing the opportunity to see how the Davy Jones No. 1 well will flow. That would lead to the opportunity to identify reserves, additional drilling activities and then help us in assessing how we go forward with our other prospects.

Page 7 is a summary, Slide 7 is a summary that list the 5 ultra-deep wells we've drilled over the last several years. We have seen 8 different geological formations that we've identified below the salt weld. And if you look at each one of those, they give us development opportunities, these prospects, but they've also given us the information for setting up a whole series of other prospects that gives us the opportunity to apply this broadly across the trend.

Slide 8 is a summary of the Davy Jones No. 1 status report. We have progressed in getting to the point now of being able to conduct a flow test on this well. We have successfully perforated the F, D and the C sands and a portion of the B sands. And that gives us perforations across the vast majority of the pay count that we had originally identified on the logs. So that will give us the ability in the very near future of opening the well and seeing what flow test will provide to us.

Slide 9 shows the location of the Davy Jones field, the No. 1 well. As I mentioned, the No. 2 well, we will move after the flow test on the No. 1 well to complete and test it based on the results of the No. 1 flow test. This No. 2 well we encountered multiple Wilcox sands that we did see in the No. 1 well. And we also saw additional potential hydrocarbons in the Tuscaloosa and Lower Cretaceous carbonate sections, which gives us additional opportunities with that.

As I mentioned at Lafitte and Blackbeard East, which you see to the Southeast of the Davy Jones prospects, we will be submitting development plans with the Bureau of Safety and Environmental Enforcement during the third quarter of 2012. Both of these wells, as you saw on the earlier sands, saw a multi -- earlier slides, saw multiple potential productive sands. In the Blackbeard East well, we have the potential opportunity to complete these at depths of between 19,500 feet and 24,500 feet, which could allow us to use conventional equipment and technology and be done at lower costs.

The Blackbeard West No. 2 well, which is at Ship Shoal 188, is now drilling below 21,000 feet. Our current proposed target depth is 24,500 feet. It is looking at Miocene age sands. Just below the salt weld, it's about 13 miles east of Blackbeard East prospect. We have now set a liner at the well and encountered a high-pressure flow, immediately below the salt weld in May. Our success here would allow us to use conventional equipment to complete it, and we're drilling ahead with that. Jim Bob will give you report on that.

The other well we currently have drilling is the Chevron operated Lineham Creek well, which is located in Cameron Parish, Louisiana, just on the coastline. It is drilling below 19,000 feet with proposed total depth of 29,000 feet, a very large potential closure, targeting Eocene and Paleocene objectives. Below the salt weld, we have a 36% working interest in that prospect.

And as I mentioned earlier, the Highlander prospect, which you can see to the Northeast of Davy Jones, it is onshore covering 4 -- it's acreage in 4 parishes in South Louisiana, a very large area that this prospect covers. We got exploratory rights to 68,000 acres. We expect to spud our first exploratory well on the second half of this year. It will be roughly a 30,000 foot testing below salt, the horizons that we saw on the Davy Jones well. Exciting prospect, we have a 72% working interest currently in that, in the Highlander.

Slide 10 shows the potential for our onshore and offshore prospects now. We had on the shelf, we're seeing potential from our exploration prospects in the range of 100 Tcf equivalent, which just goes to show you just how large these prospects are. We've now identified potential for 3 onshore prospects, including Lineham Creek, Highlander and a third prospect that totaled 33 in cubic feet of equivalents. The onshore prospects give us a chance of approaching this in a different way than offshore, and we're very excited about it.

But in addition to the prospects that I've mentioned, you can see, particularly these -- many of these were enhanced with our recent success in the offshore bidding where we were able to acquire acreage that was adjacent or near to these additional prospects. But around the Blackbeard but prospects, we have a whole series of prospects, including Calico Jack, Barbosa and Morgan and Hook, all of which benefit from the drilling that we've done and our understanding of the geology. And then further to the West, the Captain Blood, Barataria and Drake are all big structures that have the chance to very large, great opportunities. And then, England is a group of acreage positions that with our partner, Texaco, that allows us to look at the area involved in Davy Jones and Lineham Creek. So all of this is coming together in a way that will allow us to have the opportunities to look at prospects beyond Davy Jones.

For 2012, Kathleen mentioned what our average production will be. Point out again, it does not include any production from Davy Jones 1 with a successful flow test and because of the location of that well, it's near markets and it can come onstream very quickly. And we have a general capital expenditure estimate for 2012, but it's going to be driven more by what happens going forward in our opportunities and so forth.

A lot of interest in what we're doing, and we couldn't be more excited about it. And Jim Bob, with that brief introduction, I'll turn it over to you.

James R. Moffett

Thank you, Richard. I will start with Slide 14. I thought it was important to point out a couple of things. This onshore shelf project that we are involved in has certainly evolved into a franchise. That's because nobody else has drilled, except for this Chevron wells, drilled onshore.

And I thought you'd be, as you can see that we got $185 million to develop the technology, to be able to complete these wells. Without the technologies to complete the wells, obviously, nobody is going to start if they can't complete. And you can see, we've got only 25,000 down wellhead in 3. We've got 25,000 surface-controlled subsurface safety valve, 3.5 inch, 7 inch and 9-inch tubular connections, 25,000 pound [indiscernible] stack. You can see they use [indiscernible] looks like some kind of a statue, but it's $35 million statue.

Choke manifold, the wireline controls and the fuel pumps, these have to be built and tested in the labs to satisfy the [indiscernible]. And the only ones in existence, these can be used over and over again.

We have already been getting most of inquiries of people that want to acquire the technology, and we'll just decide how recover the $185 million that we spent. So the franchise starts with having the equipment to complete the wells and then if we wish to go ahead into the next phase, and that's the exploration technology, besides making the drilling techniques to drill the wells. Let's take a minute on Slide 15. I know everybody is impatiently waiting for the Davy Jones tests, just like I am. The Davy Jones log shows you the zones [indiscernible]. We perforated the F, the D, the C, and a portion of the B. Now, we did this with a wireline and we're able to get the kind of penetration that we originally would hope to get in the F-sand. We should try to use a remote, just to give you an idea why we keep having some delay, we'll talking about for a minute.

When we perforated with the [indiscernible], what we find is about 40% of the perforating time which we spent is going to be what we called low-quality charge because apparently, this is [indiscernible] perforating to expansion some lease. So in a high-quality shots, as well as 165 feet of the 200 feet we intend to perforate, we have 3 layers that we would like the one we have with a remote control. So that's what counted as the delays.

The important thing is, we finished perforating, we're out of the hole with all the equipment below 165. We've got a tubing hole at 165. And that's the other reason why we continue to have some delays. In this case, when we got through perforating, we came out of the hole and we were out of the hole with a perforating gun. So we have no pipe in the hole, and the well is trying to flow on us, I guess the 185 column of mud, so that was really interesting for a couple of days.

We had to bullhead into the well to get this pressure off of the well. Now why is that significant? We had up to 1,750 pounds of pressure on the casing when we had to shut the wellhead, when it was trying to flow. And that was with an 185 column of mud all he away from the surface down to the perforations.

So what it obviously indicates is the perforations are opened, now, as you know, what we do now is we got the tubing out of 165, we're in the process of circulating now to heavy mud above these 165 to an 185 completion fluid. And that will give us the differential in the borehole. They said, why did you let wells flow before you ran the tubing.

When we originally attempted to complete this well, that was the rationale of using the remote control perforating gun across the F-sand. So we wouldn't be exposed to having the [indiscernible] in the hole, we have some pressure to surface.

But we've got to use the wireline. This is the kind of thing we had to expose our self too. I won't waste any more time on those details, but that's the kind of thing we've just had to persevere to be sure we get this right. The important thing, as I said, is if you look on Slide 15, we now have the majority of the stuff perforated with the casing gun, we should have 9 inches of penetration versus 3 inches that we got on the D sand. And remember, the D Sand is the sand that's layered for gas before we have to shut the end, to slide the rig. And that was important because when we shut it in, we had an elevation and pressure on the shut-in, that indicated that we had what looked like a really high-quality reservoir.

But we find out, because it's along with the F, and it's a part of the B, will all be comingled when we take D and we open the well up.

So we got the tubing in the hole, we're latching the tubing, button up the well and then next week we'll be getting close starting the process and getting the test going, everybody is anxious to hear the results. And it can have a huge, huge impact on the general area.

Let me just spend a couple of minutes so that we talked about this franchise. The lease sale was important because the Davy Jones West prospect and the England prospect where we bid with Chevron was important, and that it shows you that the confidence level we have at these reservoirs, and these prospects are going to be higher-quality reservoirs. And remember, Davy Jones and England is Wilcox and Tuscaloosa, Barataria and Captain Blood, Lafitte and Calico Jack and Miocene. And we now have a Frio, as well as the so-called Jackson section, and of course the Wilcox. And so we have a number of objectives, which it shows you, have been added since we started the program.

And the Davy Jones West for us is Miocene is just mainly West. I included some copies of some [indiscernible] which I hope is come cross on the slides. As you noticed, on Page 18, the Davy Jones discovery in the southern well and Davy Jones West, I know you have seen this [indiscernible] before, but the main thing is look at the size of the prospect from the East to the West. We're talking about spanning some 12 miles of territory. And it's a huge complex, which with just a small incline or saddle that you see right there where those numbers, 88b and 9b. So I thought you should see that while we established this franchise, these are world-class prospects. If we can just get the rest of the data on the flow test, we'd be off and running.

And the next slide, talk about England. First slide shows you the acreage we acquired and the size of this thing. England is a property even bigger than Davy Jones, surface area wise. You'll notice on this page on Slide 20, the seismic shows you the size of Davy Jones and Davy Jones West. As we've seen in the deepwater, and the shelf and now onshore and you'll notice there's no structures between Davy Jones West and England. That's a 27 miles spread. The reason why that's important is because again, if these reservoirs have good quality flow rates, we're talking about an area here where all of the hydrocarbons in this area have all gone to the Davy Jones complex or any complex.

And just emphasize, if you noticed on Slide 21, this is a close-up of the possible drilling location in England. And once again, you can see as you get into this sub-salt, which is sub-salt is the blue areas shown. These giant structures are just hidden from many of the prior drilling that have been done above the salt weld. Just amazing to have this kind of an opportunity in a well known basin, in the Gulf of Mexico. But it is what it is.

The next big structure which we just bought acreage is shown on 22, Slide 23, it is Slide 23, you can see once again, we provide a cross-section. Lafitte, as you remember, a well we just drilling are going to be submitting development plans on. [indiscernible] look at this big Captain Blood structure, sitting there, a primary structure once again, nothing between these things, it's just one big structure and then a big sand cline and you back up on this significant structure. All of this bodes well for, if the reservoirs are commercial, you got a have a huge rich area around Captain Blood, it's another one of these giant structures. There's just buried and was not visible above the salt weld.

And of course, on 24, there's the Lafitte and Barataria, picked up the new leases that are shown in green there to enhance that. And this is just another look at the way that Lafitte, Barataria and Captain Blood fit together. All significant features with big sand clines in between them.

And so on Slide 26, if we look at it, in the Calico Jack prospect, we bought that in conjunction with Chevron where they owned some nice BP acreage, we own acreage, we added one other block. A significant amount of the Calico Jack on Slide 27. Once again, it's just another one of these sub-salt plays, and you can see Blackbeard East on it and Blackbeard West. And these are structures decentralized in between them.

And so you can see 14.5 miles between the Calico Jack and Blackbeard East. So a significant group of prospects, which would enhance our recent position and to the franchise.

And of course, the evolution of the deep play onshore was inevitable as we started to continue to try data. And you can see the Lineham Creek well, which is at the drilling rig out there on the very west, Highlander is a prospect, which we hope to spud in the second half of 2012.

What we've done obviously is to take the data that came from deepwater to Blackbeard, Davy Jones and onshore and even past that, and what we're finding is as we emphasized before, is once again, this is all 1 big basin, the deepwater, shelf and the onshore, and we're finding several prospects in the onshore, which means we can drill with barge and land rigs and use completions. You don't have to have a big platform like we have in Davy Jones or like the platform were necessary in the deepwater.

I'll emphasize again when I say franchise. Outside the database, we've got some deepwater to shelf to onshore. And you're seeing all of the information which says this is 1 big basin, and the difference between Thunderhorse and the rest of the deepwater is that we're higher pressured, higher temperature because that's in the deepwater. They have the deepwater over the top of the structure plus they have a massive salt pillar so there's less pressure and less temperature. So when we go the shelf where we have sediment, onshore where we have sediment versus water, our pressures are up, our temperatures are up. We believe we got this thing figured out, and got it lassoed and we've learned to drill it and now, we're in the process of completing it. That's the franchise.

The next slide is a cross-section of Lineham Creek, and this is once again a cartoon that basically shows you that you've got the Paleocene, Eocene which are lower Wilcox and possibly Tuscaloosa as targets here and what we're seeing is a massive structure that basically is trapped up against salt weld, similar to the deepwater play.

Okay. And the next play is the Highlander, which we have now acquired 60,000 to 80,000 acres on, and it's a lease, a 30,000-acre closure. And the broad map on 30 shows you a map view, on 31, as you notice, you got a cross-section. And it's very similar to the Lineham Creek, very similar to Thunderhorse. They're similar to all of the big structures that have been successful. As you get onshore, it just popped out from under the salt weld. And so once again, to have a structure, its' got these big Wilcox and Cretaceous reservoirs, trapped up against the salt mass is just something that you think you have to go far. But here, they are sitting right underneath the old trend above the salt weld. So the beat goes on, and we expand the potential of this franchise of drilling these deep wells. Obviously, the onshore, if we can be successful, will be drilled at much less cost. And then even the shelf than obviously, the deepwater.

So that's where we sit, and that's why we feel the franchise has given you the opportunity to participate in a home run play.

One last way to look at this, we talked about this before but on Slide 32, I thought I'll just remind you. Before Thunderhorse was drilled, the prospects around the deepwater and you notice Mad Dog complex on the right side of the slide. The leases from 1988 to '95 before the Chevron discovery of Mad Dog were bought for $300,000 for a 5,000 acre track, which is a multimillion dollar field. Those leases were bought in that, and $150,000 for 5,000 acres. Tahiti, even before Thunderhorse was bought for $230,000. After the discovery of Thunderhorse, you can see what happened, 5,000 acre track were going not for $200,000, but for $85 million, just South of Tonga there. Halliburton went for $55 million for a 5,000 acre tract and down in by Buckskin, in Shenandoah well, 2 tracks for a total of $140 million.

What does this say? What this says is if you look at the map to the North that if we can confirm the commercial reservoirs in this shelf and onshore trend, the value of these prospects will be enhanced by exponentially. So Slide 32 is the sort of a guide to why this franchise can increase in value with the confirmation of commercial reservoirs on the shelf and onshore.

And the next slide, of course, is -- we talked about the Blackbeard ultra-deep exploration area. These are the wells that we are going to be filing our plans on at the Blackbeard East. We are currently drilling Ship Shoal 188. And as we've said, if you look at the map, we call this cupola plays where we have these velocity anomalies and on Slide 35, a blowup of Ship Shoal 188. Now if you notice, and I hope as you can see on your screen, the slide, if you look at the Blackbeard complex discoveries, we're talking about the Ship Shoal 188 well. The reason why this slide is important is because it blows up the [indiscernible] idea. And what we've done now is we drilled, we saw salt as we have predicted, about 140 feet of it. And immediately below the salt, we drilled into what appears to be a sand section, that's the sand and shale but it was a very sluggish and flowed, C1 to C5. And so we're now have set pipe to that and just drilled out.

So we'll stay tuned and see what happens as we drill the section below the salt. One other thing, if you notice above the salt weld there, some dark reflectors, which are similar to the reflectors we talked about at Barbosa and at 188. Well, that's actually Upper Miocene production. This has been found by on top of the salt weld in the adjacent block, Ship Shoal 189. Apache just drilled a well, it's 200 feet off our leased line, it's got 150 feet of play at about 18,500 feet. And that play obviously comes over to 188. But -- and just exactly how much is above the salt weld, we have to see. But it's somewhere approximately between a 50, 100 BCF total in those Miocene sands sitting on the top of this cupola play. But as I was saying the other day when we were looking at this thing, all these plays above the salt weld have been the traditional deep plays like our Flatrock play above the Davy Jones structure. But if you look at the size of the 188 cupola play, the play sitting on top of the salt weld obviously some good production, nice sands with good flow rates. But if you look at it, it's like a monkey riding on an elephant. So these targets that we have seen before above the salt weld have been the lifeblood of the shelf.

And really, onshore Louisiana and now that we know these big structures exist below the salt weld, you can see why the potential of this is exponentially bigger, bigger it to similar what we like our Flatrock discovery.

So great discoveries right above the salt weld. Fabulous discoveries below the salt weld. If we can confirm all of this.

So I hope that gives you a perspective of what we mean when we're talking above and below the salt weld and the relative size of these big features below the salt weld.

So if you look at the ultra-deep prospect, our shelf and onshore franchises as we call it, you see we have this multiyear prospects of 100 Tcfe. You heard it. We don't need to flock that around. But we have to do now is get the first one, we're in the red zone, and get it across the goal line so we can quit talking about what the flow capacity of the reservoirs on the shelf are.

So once again, we're working diligently to get you the test and be sure that we get the comingled sands buttoned up so we can get an idea of what the [indiscernible] probability of these reservoirs and this pressure and temperature in our shelf and onshore play.

There's some reference slides in here. I won't spend any more time. So we can talk about take some questions. But I hope this gives you an insight into why we have been so excited about this play ever since we reentered the Blackbeard well.

So with that, I will turn it the session over for question-and-answers. And Richard and I are here to answer whatever questions you might have.

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.

Try to find the right way to phrase this question. You have an enormous number of prospects, the excitement in yours, Jim Bob, and Richard's voice is palpable. Very, very visible, you can almost like see it even though I'm on the telephone. But the enormous financial costs involved and just to kind of give the idea, the most recent book value is about $1.7 billion. Chevron is $125 billion, ExxonMobil, $157 billion, Apache, $20 billion, Anadarko, $30 billion, ConocoPhillips, $67 billion. We're in a big boy’s game that is very costly. And I guess, my question is how close or are you to being in a position that if you lifted your kimono, your dress, whatever you want, pull up your pants, let your pants down, however, you want to say it, that a major would come in and put up this serious exploration money that we need, or in fact give us a price that would take the whole enchilada over it? I mean, how far away from that? Because we just can't afford to develop all these prospects in our own.

James R. Moffett

Lee, that's a great question. We'll try to answer it and be realistic about the opportunities. I might just mention in passing, there was a deal announced a couple of weeks ago, which would be pertinent to what you just said. Anadarko and our deepwater play and Lucius just announced that they're going to bring a partner in on this $2 billion platform that they're going to be building a portion of it. It’s just about -- just under $600 million. And they were able to get an investor. They had 33% working interest. Investor put up all of the money to build out the platform. It took us 7.5% working interest, and Anadarko ended up with 25% interest. So that's a 400 to 1 promote. Now all that, the reason why I bring that up is we've been talking about the kind of money that'll come into this play once we derisk it, i.e. prove as you've got these big structures, our commercial structures. So that's just one kind of money that could be here. And your point about the fact that we're a small cap company, taking on a major company play, is not the first time we've done it. We did it before we announced Southside rock, and we talked about the fact that we did it in Indonesia with the Grasberg. So it's not new to us to be a small cap company. Unfortunately, the Street has supported us, and we think that once we confirmed the commerciality of these plays that we basically have pioneered the shelf in the onshore and I can assure you that we've already have indications that there will be people that will come up with the bucks whether we do it with a combination of money from the Street and money from the kind of investor that we just talked about Lucius play that Anadarko just brought in. And I'll point out the play is in the shale, once people start getting into the shale play, the billions of dollars that flowed in to that play once we have the frac techniques when you look at it, the smaller cap companies really started that play. The majors didn't come in until that technology has been brought to a point that companies that were small cap, certainly no bigger than middle cap, were taking all the risks, trying to prove that horizontal drilling of those multistage frac. And once they basically proved they could do it, then the money came in, from the majors and foreign dollars is the multibillions as $200 billion, $300 billion, has come in to that play. Well, all of that was done by the guys that were taking on a major company play with a small cap, smaller cap public company. So it's -- you got to have confidence that you know what you're doing. I'm confident that our sounding database we had enough exposure, talking to other people with all the appearances that we made, talking about what's going on like the slides we just presented. And people are astonished at the data we've been able to tie from this deepwater play to onshore. We've proved we could drill these wells deeper. When the majors weren't sure they could do it, they actually walked away from it because they were concerned that you couldn't drill below the salt weld. Now we proved whether you can produce below the salt weld. So no question, Lee, that this is a major home run play. But we have partnered up with the major buying leases on the trend now. And there'll be more to come. But those are the best analogies I can make for you. We're a home run player, and we did home runs before, this isn't our first rodeo. And we appreciate the fact that the Street has supported our play for this concept. And we hope, we're going to be right again.

Operator

The next question will come from the line of Jeb Backman with Howard Weil.

Joseph Bachmann - Howard Weil Incorporated, Research Division

Just had a question looking at your onshore prospect, 30 Tcf number. Just I guess, through process of elimination, it looks like the onshore prospect, could be pretty significant in size compared to the other 2. Just wondering if you could give any color on B and leasing efforts around that prospect?

James R. Moffett

Well, the reason why we haven't been specific, we are still attempting to release that prospect. And to answer your question, Jeb, once again, as we just showed with the cross-section between Davy Jones and England, you have these big mountains, buried mountains below the salt weld and then you have these big sand cline, abysses between them, and that's what we're finding in the onshore is that you have this major 30,000-acre closures. And then, these deep inclines where you offer 20, 30 miles and you don't see them any, even with secondary structure. So what we've tried to do with our database is just like we did in the shelf, we tried to identify the major primary structures. And again, that's what they did in the deepwater when Thunderhorse was being drilled, everybody bought those big Mad Dog, K2 structures that just stood like a sore thumb. And then, of course, nobody knew what the objectives were because before Thunderhorse, they weren't even sure what the age of the stuff was going to be. And the rest is history. So -- and I might just say in accord with that, the patience we'd had to have and you'd had to have with this test on Davy Jones, if you look at that deepwater and the shelf play and the onshore play, there's only one well that's been tested and that's the deepwater well in the Wilcox. And that was the Jack well that was tested by Chevron and Devon. And that one well that was flow tested from the Wilcox has supported $100 billion worth of development effort that have been announced. So the Davy Jones when it flows would be only the second well in the shelf of the deepwater that's ever been flow tested, and that's because that we had to spend $100 million just to get a three-week flow test, not a completion but just a flow test. So we're talking -- you've seen the play, sub-salt play in Brazil, for instance. You read about it and you see that all of these plays have been going on in Africa and Australia. These aren't big plays, and they are -- when they're big plays, it takes a lot of money to play the game. But the structure is so big, you're not gambling on whether or not you got major accumulation. You're gambling on in terms of structural size. You're gambling on what the sand looks like and then, what the reservoir quality is. And that's what they did in the deepwater. That's what they did in Brazil below the salt. We are doing it here but we are on American soil. And if this works, it is going to be a major company play that we pioneered to develop this franchise. So we appreciate everybody's support, and we pray we're going to deliver the goods for you. That's what we're trying to do every day.

Joseph Bachmann - Howard Weil Incorporated, Research Division

And just 1 more quick question, if I may. Is the LWD tools still working at Blackbeard West too?

James R. Moffett

The LWD tool is still working. As I shared, we've got some LWD responses below the salt weld where we have these big gas flows with C1 through C5, and we have drilled out, haven't seen anything but shale below the first zones that we see below the salt, but we just made a couple of hundred feet where do see, is we see the Paleo still puts us in the zone 4 upper shelf. So we already have some more sands, and we'll just see if we can stack them up. As I showed you on that structure where you have the Apache, discovery sitting right above the top of the cupola play, it almost looks like a deeper image of that play, the C1 through C5 shows we have when this well was flowing on us before we ran this indication would indicate that we have a chance because we're still in the temperature and pressure window that we could have some heavy hydrocarbons not necessarily oil but gas with some fairly rich condensate.

Operator

[Operator Instructions] Your next question will come from the line of Joan Lappin with Gramercy Capital.

Joan E. Lappin - Gramercy Capital Management Corp.

Mike, I'm interested in the bids that you made with Chevron. In particular, let's see, you have some with them and some without them. How was it decided? Which you would bid on jointly? And which you would bid on your own? And could you characterize your general relationship with Chevron and their likelihood that since you're already in bed with them, they're the ones that are going to pony all this dough to cash us out?

James R. Moffett

Well, those are your comments, not mine, Joan. The answer is, Joan, that we, as you know, have been working for 10 years with Chevron in State Track 340. We made the discovery at JB Mountain and at Mountain Point and then of course, the big Flatrock discovery was made on the big State Lease 340 was the old Texaco lease that Chevron inherited. And so our partnership goes back to really to 2000 when we started in this area. The ultra-deep just started in a while, and the reason that we bid jointly with Chevron was because the plays that we had in England, Chevron had a major position that they were holding by production from shallower production. And we had purchased some leases ourselves. And West Davy Jones, Chevron had farmed out to this at Davy Jones. And therefore, they had all the information. And so that set up a natural joint bid at Davy Jones West. And then, the rest of the plays like Calico Jack, just so happened they noticed far removed from these other plays that Chevron had

[indiscernible]. And we had bid together for that reason. In the other plays, we didn't have any joint acreage with anybody. We owned 100% of play with our partners. So therefore, the data that we use to make a bid was not available to the other people. And so it's just an evolution of what we've been doing. The rest of the comments about Chevron should attribute them to you.

Joan E. Lappin - Gramercy Capital Management Corp.

Well, I'm going to go back in the queue. But are you going to have another call when you do get your flow test results?

James R. Moffett

I probably will have a call, the minute we get it, it may be at midnight. So everybody, be ready. I want everybody to know this thing, the same minute I do.

Operator

Your next question will come from the line of Joe Allman with JPMorgan.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Jim Bob, for the Davy Jones flow test, what kind of rates and pressure and time do you need before you take the next step? I'm kind of assuming that the next up work on the flow test with Davy Jones No. 2. And also, how much -- how many says or how much time you're going to pass by before you actually talk about flow test? Is it going to be first 24 hours or first week or what?

James R. Moffett

Are you talking about the flow test at Davy Jones?

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Yes, sir.

James R. Moffett

I just told Joan, we may have the call at midnight. When that thing comes to the surface and we get a flow test, you can rest assured, everybody is going to know it the same time I do. So it's a big event for us, Joe. We've been slugging it out for a couple of years. And so, it will get to you and to the rest of the group just as soon as we have it. As you know, when we have 18 5 mud in the hole because we got rid of the same bromide that caused us some chemical reaction problems when we perforated the D Sand. So we will have 18 5 mud in the hole from 16 5, down to perfs. We’ll have 8.5 completion fluid which is what we are doing right now. And we'll then pressure up on the tubing just to make the formation thing. We still got 18 5 mud above the 16 5. And then we will slowly bleed that pressure down so we don't take a big bump. But as I said in my portion of this call, we have 2 things that have happened since we've been trying to test this through. One of them was that when we perforated the D Sand with the tubing, hoping we can get enough penetration, 3 inches or so, to get past the skin damage as there was some. And that's when that flow hit us that we flared out there and then we had to shut the well in because we had to move the rig back, which was unfortunate. But the importance of that event was when we did have to shut the well in, the well popped up and pressure straight line. It went up to 9,200 pounds and still had a good bit of 18 5 mud and 8.5 completion fluid. The reason why that was significant was you can't get that kind of a immediate shut-in pressure unless you had support from the reservoir away from the borehole. Unfortunately, we won't know what the real significance of that was until we open this up. And then, we're going to have the S sand, the B sand, "C" Sand and part of the B all comingled. The first thing that happens is this well tried flow us a couple of days as I was saying, where we ran the hole with perforating guns. And so we had to bullhead some mud and then run in the tubing, ready to strip in if we had to. So it will open, now what we have to do is to get the mud and the completion fluid [indiscernible] and get this thing, clear soaked as we say in the patch. And that means that mud that's been in behind the pipe has been there for a couple of years since we started completing this well. We've got to get this differential in there and get this well to clean up and flow all that scan that's right around the borehole, flow it out there so we can see what a clean test is. Now there are a lot of controversy about the porosity and permeability. We know what the porosity is. What we have to prove now is what is the permeability with 30,000 pounds and the temperatures that we have. And do we have porosity and permeability, or do we have porosity and permeability and fracture porosity? Yes, the fracture porosity is going to be easily important because we know, as you can see from these slides, that we're in a compressional tectonic environment below the salt weld. Below the salt weld, you have a fraction reservoir in what we call soft rock, because above the salt weld, you have that trapdoor faulting which means everything's in tension and you have tension in tectonics. So you don't have thrust faulting and that sort of thing, but we know from the deepwater and from our cross-sections, very clearly on the side that these big flows were in a compressional tectonic environment. That's how the thrust faults show up. And when that happens, because the rock is more confident, because the rock is covered by more sediment, et cetera, et cetera, it's going to be more successful to frac-ing. And this is not the frac like we've been reading about in the [indiscernible] this is mother nature doing her nut cracking. And when you shorten these formations up by folding them and creating these big structures that have these similar signatures, you're going to get some fracturing. And we have seen it in some of the conventional cores. So those are our elephants in the room. Everybody that's ever worked Rocky Mountains or any of the trends that have foldout type tectonics, those that you're going to have permeability from natural porosity and perm, but you're going to have a lot of fractural porosity, the Ellenburger formation out in West Texas , for instance, which is a huge producer, it has 3% to 4% porosity. But it's a huge producer because it's fractured to heck and gone because of the flow tectonics out there. Rocky Mountain is the same way. You got well out there with 8% porosity, but there a big field. But they're doing it because of the fractural porosity. That's what we got to prove. And then anybody that knows exactly what that is going to be and not go ad nauseam here, the other thing that's clear is the one other well that was tested in the Wilcox at the Jack field flowed oil, it was heavy oil. It wasn't a high volatile oil, and it was cold. Now we got hot gas here. So what's the permeability to high gas and the reservoir at this depth with 30,000 pounds of pressure and primary fracture porosity as we just discussed? Well, I can tell you, Joe, if everybody knows -- if anybody knew [indiscernible] they'd already be way running off away from us. But as we said, we're a pioneer just like that test out in the deepwater jack with all the kings' horses and all the kings' men, that were working out there, nobody knew until they spent $100 million to see what the permeability of the oil is going to be. Again, as I say, I think it's 20, 21 to gravity of oil, and out there in that deepwater is the cold zone we got. So we got similar type things because it's the same age formation. But that's where it stops. We got 30,000 pound of pressure, which is 10,000 pounds more pressure than they had. We've got higher temperatures and the higher temperature in this case is going to once again, the pressure and the temperature with this gas is going to improve your chances of having permeability in these reservoirs with both natural and fracture porosity. But that's the hundred billion question here now. And I wished that after looking at it logs for 40 years and looking at data that I could tell you. But everybody in the industry is watching to find out what the flow capacity were, just like they were at Jack. So that's a long answer to your question, Joe, but that's where we are.

Operator

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

Duane Grubert - Susquehanna Financial Group, LLLP, Research Division

Yes, Jim Bob, I've got a question, I think, you could really be helpful on in terms of uncertainty. You've shown you can drill the wells, you can log them, you can perforate them. So the first part of the question is if there are any uncertainty about additional completion practices that might be needed? Like do you suspect you might be gravel packing on any of the stuff you're looking at? And the second part of the question, same scene with uncertainty. On the exploration side, you talked about we don't know until we complete the wells what the capacity of the rock is to do. But could you remind us that at this point of your exploration, discovery momentum is fantastic, but what is the specific geological risk beyond rock quality?

James R. Moffett

Actually, Duane, let me see if I can answer the question in 2 parts. The completion and stuff, we -- that was the good part about the test, although it was a short test on the D sand, as we had the pressure on all the equipment. And while the well was flowing, until we shut it in and when we shut it in and had that shut-in pressure, and so everything was -- everything held, nothing leaded, the tree and the lubricators and the safety valves, nothing malfunctioned. So we got the thing, but there, we can flow well with 30,000 pounds of pressure, we know that. As far as the exploration side of this and whether we have a gravel pack, the answer to that question is for the very reason that I described, the rock below the salt weld where you have this fold belt with this possible fracturing whether that's natural porosity, this rock is so hard that you can flow these wells at high rates and where has it been done, Mobile Bay is one good example, for instance. Mobile Bay was [indiscernible] as opposed to the plastic. But was it a good indication just about the same temperature we have at very high pressures. And they flow those wells at $125 million, $150 million a day. And that reservoir stayed together, didn't blow apart. So your gravel packing is done above the salt weld, as you know, where you have rock that's considered soft rock. Once we get below this salt weld, we're in Hard Rock country, just like the Rockies, and that's because of the set up the load and the pressures and the temperatures that you have of the so-called Hard Rock. And so we won't have any gravel packing that kind of thing won't be our problem. These reservoirs are going to stay together as opposed to flowing and high rates, flowing gravel and silt and that sort of thing. So I hope that starts on your question. If I missed something, you tell me.

Duane Grubert - Susquehanna Financial Group, LLLP, Research Division

That's very helpful on the completion side that we don't have to worry about figuring the gravel pack down there. If you could just quickly go over the specific geological risk. You've got beautiful structures, you got all the data. Is there a trap or hydrocarbon source or any risk? Or do you feel just like, man, this 100% success, it can never say 100%, but this momentum should continue and we don't have a specific fundamental risk we're worried about?

James R. Moffett

There is no fundamental risk about source rock, and that's because we've proved beyond the shadow of a doubt that the deepwater and the shelf and the onshore is all 1 basin below the salt weld. It's the -- you have Gulf of Mexico depth of center, and so we don't have to worry. We've already seen pay offshore deepwater and then back onshore, we've seen it in the Miocene, and we're seeing it in the Wilcox and we're seeing it in Tuscaloosa, big, big amounts of it. So source to these rocks is not a question. We've got it North and South of us in the same depth of center. So we're down to the last straw. I keep talking about the Jack well. Until that well was tested, all those were drilled out there after Thunderhorse if you're remember, Thunderhorse was Miocene and when they drilled the Jack well, they thought they were going to find the Miocene sands. Well, lo and behold, when they went down and drilled it, the Miocene sands had literally shaled out of it and so those beautiful structures were Wilcox, shocked everybody, including me because the sand just made a lot further south than anybody ever anticipated. That's why we set out there for all that time without being drilled. But once they saw the Wilcox and saw the low gravity oil and in this case, the fact that they have the salt canopy and the deepwater and don't have the temperatures they have, temperatures are their worst enemy out there because they have cold water with pipelines laid on, on the bottom in the deepwater and they got cold oil, this lower gravity didn't have a volatile gas to move it. So we know that the exploration risk here, we've eliminated. You seen these structures, that's why we include the seismic where we can get permission from seismic companies to show it with these licenses we have. We want you to see the enormity of these structures, these are world class structures. Why are we drilling these kinds of things as a small-cap company because you just don't get a chance on U.S. soil with a proven basin with proven hydrocarbon source rocks to do this. And when you get it, if you've been into this business long enough, you got the confidence to do it, you see a lot of opportunity and you seize it. And that's what we did, and we drilled the first shelf well below 30,000 feet. Everybody had walked away. They just said, the pressure is too high and impenetrable, in other words, you can't drill them and you couldn't log them. They were dead wrong. It wasn't that way. And our theory proved that was wrong. And now, we also proved that we can log at these temperatures. We had to stem it with that and we cost us some money between us and the service companies, we finally got the logs where you've seen the log on the Davy Jones well and some of these others wells we've shown you. So we're right down to the doing. We know there's the structures we know at the right age that correlate to the structures that are already productive. We've got the production to the North and production to the South in the same age rocks. That's just get this thing tested and put the tail of it. I know you're ready, and you can bet I'm ready.

Operator

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

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

I just wanted to ask you about Highlander and just get a sense of when you actually acquired the acreage? And how you identified that it was that target you wanted? It could also just give us a sense of what sort of depth the targets are at? And whether you think that everything there can be reached by using conventional equipment?

James R. Moffett

First of all, after making the time for deepwater shelf, the first thing that we did, especially with the Tuscaloosa Trail up the north of Baton Rouge, we knew that if we had use our seismic to take this shale play on up there underneath the salt weld in onshore. We had a good chance of finding some similar type structures. And what we had with these huge 2 D lines, yellow lines, that we've gotten our seismic database. And sure enough, when we saw that kind of stuff back to the North, we had a revelation. You can correlate just like we did from deepwater shelf, we can correlate right up underneath that salt weld and boom, they started popping out. The line infrastructure that Chevron and ourselves are drilling. It just popped up a 30,000-acre structure. And we went back up to Highlander, the salt mass and the closure just pops out at you. And the 3D seismic, you wouldn't know you're not looking at the deepwater. So once again, it was just so obvious that this was a structure that is at the right age, because it's got Wilcox and Tuscaloosa, which we think we'll get to about 30,000 feet. And of course, you got the big Tuscaloosa Trail play up North of Baton Rouge. And then, you have the Tuscaloosa Cretaceous play where they've seen these sands 200 miles South of Davy Jones and the well. So you can call the well to Davy Jones. And now, we've done is take it down and moved it onshore. To be honest with you, once we got it figured out and mapped this all 1 big basin, it's just so simple that if you got the seismic, you can't miss it.

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

Great. And when did you put the position together?

James R. Moffett

We have acreage for over a year.

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

Okay, great. And do you have the costs or anything you could tell us, a ballpark?

James R. Moffett

Well, what we've done is we've tied up almost about 70,000 acres. And what we did with a lot of it was, because they're big land owners up there, we bought what we call options so that we could tie up the big tracks and they have selection clause there where you have to select a minimum of 20% or some number like that. So it let us cover the whole play. And of course, 30,000-acre plays as you've seen lately, onshore South Louisiana. The answer is we've seen it since 1950. And so trying to put a play of this size together, we just have that to sort of go on under radar so we took these options and then started buying the leases on the smaller tracks. And I'd say, we probably got $25 million tied up in leases if you take into consideration the options that we have to exercise, assuming we are successful. So if we use a huge play, it's unheard of since the 40s and 50s and if you have something this big that's got rock and source area that I just described before in my soliloquy about the exploration mission of the shelf in the onshore.

Operator

Your next question will come from the line of Leo Mariani with RBC.

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

Hey, just really quickly on the Davy Jones 1 production test. You talked about coming out with the results very soon after testing it. How long a period of time do think we'll need to see after the test before that well actually starts commencing commercial production, assuming that's capable of doing that?

James R. Moffett

It's ready to go, to answer your question. As soon as it gets cleaned up, all the production equipment and all the slated at the end of line.

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

Okay. And I guess, how soon after would you guys move to Davy Jones No. 2? Would that be basically immediate, we can expect potentially you guys starting to get after that here in August?

James R. Moffett

Absolutely, we just talked about and some of the questions. First of all, assuming we've get a big test and I know everybody is waiting just like I am to a great news going to be start to compete the Davy Jones. We've got all these other wells that will be prospective.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

I guess, however, the plays, Jim Bob? You referenced this a number of times is being capable of commercial production with conventional equipment. When would you expect to attempt to produce some of those?

James R. Moffett

Say that again?

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

Just a question on some of the cupola play structures you identified. You commented that you should be able to produce those with conventional equipment. When shall we think about when you might start this is a production on some of those structures?

James R. Moffett

Well, those things, assuming we have the production, anywhere similar to what we hope and those things you be ready to go just right away. And the equipment is available, in fact, conventional stuff and you take and you find an old platform that's already there, you try to get some space on it as opposed to having to build it the way we did the Davy Jones. So if we find those things and turn out to be productive like the 24,000-foot stuff we have at Blackbeard East and the Ship Shoal cupola play, Barbosa, et cetera, that will be just like putting Flatrock on production.

Operator

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

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

Jim Bob, just real quickly. Given the experience drilling in Blackbeard and Davy Jones, Lafitte and $185 million invested in completion equipment. Going forward for the ultra-deep wells, what are your expectations now for drilling costs completions, facilities, what do you think you could get them down to?

James R. Moffett

Well, a good example of that would be the Ship Shoal 188 well. We're down to 20,000, almost 22,000 feet now and about $70 million that we're really cruising along, below 60 before we run into this gas flow that popped us in the salt weld. So by running smaller pipe as the big string, which was a revelation that we did get the cost of this one down that number and still stay big hole size. And so we ended up with 7-inch casing, not the 5-inch casing that we had run at Davy Jones. We've been able to do that using expandable pipe, and the expandable pipe has been around for a long time but some people were afraid to use it in these high pressures. And that has performed just like it's supposed to. So we can drill and end up with 8.5-inch holes, and that's the before people thought in conventional chasing, you'd have to drill 20-inch holes up to get to your first, now, it's just costing too much money. So the fact is that the drilling costs will not be an average of hopefully the deep stuff, the mid-deep like the cupola type of play like the 24,000 foot sand we have at Blackbeard East and then of course, if you go onshore, another good example would be we'd be talking about using land rigs or barge rigs, which are at $60,000, $70,000 a day versus $120,000, $140,000 a day. So the rig rates are going to be average now, but the main thing is we've been able to use smaller hole at the top of these holes pipe. So the answer is, we have to get the cost down. And of course, the service companies who are working with us to do that. It took us months to log Davy Jones just because the equipment kept flaring at these temperatures. So the service companies get to work and beefed up there by the time we got ready for wells, how Lafitte 30-plus-thousand feet and never had a bubble with the wireline as opposed to having using drilled Davy Jones. So I can't tell you what the laboratory this has been, but it's been a hell of a laboratory. And because of that we don't have to make the same mistakes twice. So when I say pioneering, when I say franchise, I'm telling you, that it's exactly what it's been. And I don't want to repeat myself, but people who went through this in the deepwater the only difference was is it because the Thunderhorse discovery was oil and the pressures out there because they have the deepwater, the salt over the top of these reservoirs were 30,000 pounds, they were 17,000 to 19,000 pounds. People jumped into that area, and you had majors and you had independents. And you must have 40 different people out there as opposed to us being the only people during this. You say, Jim Bob, that major is stupid, it's the only one in this field to put them enough to go and try to do this. Well, that everybody can get a shot on that. But the reason why it was there for us is because the first operator that we didn't there that tried to do the well couldn't get down below 30,000 feet. And I analyzed the data and the logs and predicted that the pressure would be lower as opposed to higher, and we were right. That's what's let us drill below 30,000 feet to begin with. So we you were saved, i.e, huge amount of money. We have to and the answer is that the pioneering that we've done and clearly, we've -- those can be used being used today, it's been in service 20 years or more. But they just one, so we have to build the thing and had to wait to build it and then wait until it test in an API lab so that would be approved before you even attempted the completion it with. And all that other stuff you see on the rest of the slides. We don't have to spend that money again. And we can have people that were needed and assuming we were right in that these reservoirs are going to be there, there's some more of these structures not quite as big as the one at Highlander, that would be people chasing these onshore like we did at Tuscaloosa Trail during the production boom as we call it. So this is a science and we've pioneered, and that's why it's a franchise.

Operator

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

Joan E. Lappin - Gramercy Capital Management Corp.

Again, I guess, after your recent -- these last few comments, you question I had, you had said a couple of months ago that you weren't going to go forward with Davey 2 until you charged all of your people and all of their various functions to come up with white papers to discuss the mistakes and whatever what you've just referenced. So have there been any important findings that have come out of that mission that you're willing to share with us? As to what you can do to speed up the completion of Davey 2? And for these other wells going forward?

James R. Moffett

Well, Joan, it was as I was talking about, you're exactly right. Since I, even before you and I talked and I talked about the white paper, we have been sleeplessly going through every phase of drilling and completion. And so I our team of people who worked all over the world have been working on this with me for several years. I've been on the phone with Presidents of service companies, and I've been on the phone with our consultants, guys at Mobile Bay and South Texas Wilcox and stuff in the Middle East. And we've got every brain, as you can imagine, and we've been going through how we cannot make the same mistakes twice. Like this, I'm no perfect, that thing by leaking and not firing so we had to take this thing so it cost us $50 million. The thing is there, even the wireline case puts you in parallel like we have the whole flow last week. But it's a risk you can take. You can't put this remote stuff in these high pressures and temperatures until the service companies improve the ability from not to leak, they got to be better sealed. So there's not an hour that goes by that Jim Bob is not talking to all the people that are going to come forth with how we avoid making the same mistake twice and how we can do things grab on cheaper and still pass muster as to what you have to do to achieve and your own comfort that when you grab one of these tigers by the tail, and you're going to test a well, that's got 30,000 pounds of bottomhole pressure. And we are bringing this stuff to the surface and you can't afford to be wrong. And we feel like we're good enough to do that.

Joan E. Lappin - Gramercy Capital Management Corp.

So would you say at this point to go back to Lee's opening question, that you would just rather get money from Wall Street or would you rather get money in expertise from an oil patch partner?

James R. Moffett

And I say, those are your words and what I said was he asked me what the sources of money were, I bought up this most recent Anadarko financing. I brought up all the money that's coming into the shale gas play. I hate to say again but the shale gas play that has attracted millions of dollars, was done by small-cap players. They went in and pioneered this horizontal drilling and the multistage frac-ing, which I'm not an engineer, I'm taking my hat off to multistage frac-ing and drilling those horizontal but the main thing to do that small-cap companies did. The majors bought their way in after the damn thing was derisked. So I didn't say where we preferred to get the money. I was asked what the sources of money could be, and so the answer is the McMoRan shareholders have taken this with, the McMoRan shareholders have supported us and supported us pioneering and trying to develop world-class play that everybody, if we're right, will jump in with both feet like what they've done in the shale gas. You just take the money and add it up and look at the guys that's on the Marcellus and all these shale gas plays. They weren't majors, they were independents. The majors wants to play with this risk, the majors came with big piles of money. And they'll same thing here, absolutely. So what we look at is how do the guys that took the risk that backed us get the money that they deserve for having been patient and going through all of this. If we're right, we're going to make sure our shareholders get paid for what we did.

Joan E. Lappin - Gramercy Capital Management Corp.

Okay. I have one last question. Did the detractors seem to still think this well isn't going to flow? And it seems to me that the problems we've had over the last 2 years have been wells wanting to flow when you didn't want them to flow. So I just wondered if you have any observation of that?

James R. Moffett

Say that last, I'm confused about what your question was.

Joan E. Lappin - Gramercy Capital Management Corp.

Well, I'm asking you, it seems as if the problem has been you're getting kicked, you're getting wells flowing at you when you don't want them to, and yet people seem to think that somehow, there's nothing down there that's going to come up the hole. It doesn't make any sense to me. It seems to me your camping it down, and they're questioning if it's ever going to flow up.

James R. Moffett

Well, Joan, I think you've capitalized it very well. I'm looking at logs, I'm looking at data and I'm looking at the away the well reacted, the way that D sands flow to the surface or we had it shut it in, the pressures that popped up. I'm looking at what the well was like when we drilled it, we drilled this well and every time we turned around, it was in our face. We tried this well while we were drilling a couple of times we had so much gas in the mud system. So all I can tell you, Joan, and loyal shareholders, we know that this log looks like gas production. Other people know that they've got the log and see it by now, all agreed that this log has gas in it. I think most everybody agrees that the porosity is in there. The fact is porosity is the same there. The people that say that say that this well won't flow are looking at information and they're smarter than I am because everything I see says that the rock is there and it had been drilled where we were drilling when we first brought up, the sand had the mud logs on it. Everything tells me that this is reservoir and it should be with 30,000 pounds of behind it, it ought to flow. And that's my case and I've stated it numerous times. So I don't know on the people who say it will flow, and then have playing. But this is one that I can assure you. There ain't no answers in the back of the book on this one. If there were answers at the back of the book on this one, the play would already be gone or it would be in the books like the deepwater. The amount of money that they spend out there in the deepwater to drill those deep wells and float those platforms is enormous. And we may be spending a lot of money but it will be a pittance compared to what was sent out there if we can get over this hump. So I don't know what to say to the detractors. If the detractors had information about the log and have some technical ways to back up their statements but, I can't worry about that. I've had detractors all of my career before we found Flatrock. A lot of people said that the rocks below 15,000 feet would be tight. We flowed that son of a gun at 100 million a day, 3,000 barrels, and all those detractors were saying that even above this salt weld were going to be too high pressure, where are they now? They took their talk and ran for cover. So it's a big bet, Joan. And the answer is we have to take our information and use our instinct.

Operator

There are no further questions at this time. I will turn the call for management for any closing remarks.

Richard C. Adkerson

Well, thanks, everyone, for your attention. Thanks, Jim Bob, for the information you provided to the participants for today's call. We're obviously very excited about these opportunities and look forward to reporting to you on our progress as we go forward. Thanks, everyone.

Operator

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

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