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McMoRan Exploration (NYSE:MMR)

Q4 2011 Earnings Call

January 17, 2012 10:00 am ET

Executives

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

Kathleen L. Quirk - Senior Vice President and Treasurer

Richard C. Adkerson - Co-Chairman

Analysts

Gregg Brody - JP Morgan Chase & Co, Research Division

Joan E. Lappin - Gramercy Capital Management Corp.

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

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

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

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

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

Leon G. Cooperman - Omega Advisors, Inc.

Eric B. Anderson - Hartford Financial Management, Inc.

Operator

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

Kathleen L. Quirk

Thank you, and good morning, everyone. Welcome to the McMoRan Exploration Fourth Quarter 2011 Conference Call. Our results were released earlier this morning, and a copy of the press release is available on our website at mcmoran.com. Our conference call today is being broadcast live on the Internet, and anyone may listen to the call by accessing our website home page and clicking on the webcast link for the call.

We also have several slides to supplement our comments this morning, and we'll be referring to the slides during the call. The slides are also accessible using the webcast link on mcmoran.com. In addition to analysts and investors, the financial press has been invited to listen to today's call, and a replay of the webcast will be available on our website later today.

Before we begin today's comments, we'd like to remind everyone that our 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 our 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, who'll be referring to the slide materials on our website.

Today, McMoRan reported net income applicable to common stock of $28.4 million, $0.16 per diluted share for the fourth quarter of 2011, compared with a net loss applicable to common stock of $84.3 million or $0.83 per share for the fourth quarter of 2010.

Our fourth quarter 2011 results included $39.1 million in insurance proceeds. During the fourth quarter, McMoRan settled claims from the 2008 hurricane events and recorded gains associated with the final settlement and other insurance reimbursements. Since 2009, we recorded $155 million in gains associated with the 2008 hurricane events.

Our fourth quarter results also included $9.1 million in impairment charges to reduce certain fields' net carrying value to fair value, and $11.4 million in charges for adjustments for asset retirement obligations associated with certain of our oil and gas properties.

Production during the fourth quarter of 2011 averaged 170 million cubic feet of natural gas equivalents per day, net to McMoRan. That compared with 144 million cubic feet of natural gas equivalents per day in the fourth quarter of 2010. Our production in the fourth quarter was in line with the estimates that we reported in October of 2011.

For the year, our production averaged 187 million cubic feet of equivalents per day compared with 161 million in 2010.

Our fourth quarter 2011 oil and gas revenues totaled $118.6 million compared to $95.1 million during the fourth quarter of 2010. Our realized gas prices in the fourth quarter of 2011 of $3.57 per Mcf were lower than last year's quarter average of $4.05 per Mcf, and our realized prices for oil and condensate of $111.46 per barrel in the fourth quarter were higher than last year's average of $83.23 per barrel.

Our earnings before interest, taxes, depreciation and exploration expense totaled $67.6 million in the fourth quarter of 2011, and our operating cash flows totaled $48.5 million for the fourth quarter, which included -- which were net of $56.6 million in abandonment expenditures, $39 million in insurance proceeds and $2.5 million in working capital sources.

Our capital expenditures for the fourth quarter totaled $105.6 million. We ended the year with total debt of $553.6 million, which included $254 million in convertible securities, and ended with $569 million in cash on hand.

Currently, McMoRan has 161 million shares of common stock outstanding. Assuming conversion of our convertible securities, McMoRan would have approximately 224 million shares on a fully converted basis.

I'll now turn the call over to Richard, who'll be referring to the materials in our slides.

Richard C. Adkerson

Good morning, everyone. I'm going to go through the slides, and then Jim Bob will be available to respond to questions afterwards.

We are now proceeding with the completion activities for the Davy Jones discovery. On January 15, our team successfully retrieved a piece of equipment that had become lodged in the well bore in December last year, last month, and now, this clears the way for us to proceed with the production testing for Davy Jones. Afterwards, we will then test the Davy Jones No. 2 well, which was a successful delineation well, which I added to our resource potential from the Davy Jones area.

We have 4 exploration wells now in progress: Blackbeard East, Lafitte, where we're proceeding with determining the resource potential there. We have spudded the Blackbeard West No. 2 well, and we've commenced operations at the onshore well operated by Chevron, the Lineham Creek well. All the data that we're seeing in our drilling continues to support the potential for the ultra-deep trend to involve the major new geologic opportunity for us that spans a wide area over the Gulf of Mexico Shelf.

In 2011, we had favorable production performance. It was actually 17% higher than our original plan going into the year. And as Kathleen said, we ended the year with $569 million in cash.

Slide 4 has the details of the financial information that Kathleen just reviewed for you.

And Slide 5 shows the reconciliation of reserves going into 2010, and where we ended up with. Now it’s important to note that we don't have any reserves assigned yet, proved reserves assigned yet for our ultra-deep wells, Davy Jones or our other wells. The Davy Jones is pending the production tests I referred to earlier. So the reconciliation shows our production for the year, which was offset in a significant way with revisions because of our favorable production performance for our properties principally at Flatrock. So we ended the year with 255.8 proved reserves equivalents, and our PV under SEC’s was $829 million on an SEC basis.

Page 6 shows our Flatrock wells, the ultimate recovery including volumes produced to date and our remaining roughly 200 Bcf equivalents shows over 450 million of ultimate recovery from this property. The chart on the right shows that 2/3 of our remaining reserves are nonproducing, and with only 17% producing, you see this in our production. Outlook for this well, we continue to produce from zones. And as they deplete, we'll be recompleting other zones to restore production and actually increase production in future years as we go forward.

The charts on Slide 7 gives further information about our reserves showing the relationship of our producing reserves to our nonproducing reserves. By volume, 60% of our reserves are natural gas, but because of the disconnect now between oil prices and gas prices, a majority of our relative revenues comes from oil.

The story with us, of course, is our potential from our ultra-deep exploration opportunities, and we've given information on that, based on our current projects that we are either drilling or have lined up to drill on Page 8 to show our gross resource potential, the sand sections that those potentials are related to and what our company's net share of that would be, based upon our ownership interest. And this is -- shows a very substantial amount of over 8 trillion cubic feet of equivalents associated for our share of the potential from these projects.

The map on Page 9 shows the location of the Davy Jones field and also the location of the wells that we currently have underway, the Blackbeard East and West, Lafitte, which you can see is south of Davy Jones and the Lineham Creek Chevron-operated well, which is just on the coastline in South Louisiana.

Davy Jones is shown on Slide 10. We now have, of course, 2 wells that we have drilled that have very positive logging information that confirmed the presence of Wilcox Age Sands and structural continuity. It confirmed the prospectivity of Tuscaloosa sands and Cretaceous Carbonates, as well the next important step as I referenced is to complete the flow testing of the No. 1 well and then move onto the No. 2 well. We're looking at a new delineation well for the Wilcox in the northern part of the structure and other drilling opportunities to evaluate the Tuscaloosa and Lower Cretaceous sections as well.

Our company's working interest is 63.4%, and our net revenue interest is over 50% for this Davy Jones. The testing of this Davy Jones wells involves a -- has involved a very significant technical undertaking. We have advanced the technology and the equipment and the processes needed to develop this well. The production platform for the No. 1 well has been installed with processing facilities and pipeline infrastructure substantially complete. The flow testing is expected to occur before the end of the first quarter after the successful recovery of the lodged piece of equipment. Following the successful flow test, we would be able to establish production very quickly because of the location of these prospects, this prospect in the shallow waters near-to-market pipelines. And after the test of the No. 1 well, we'll move forward with the flow test for the No. 2 well in the second half of this year.

The initial capacity for the production facility would be 150 million cubic feet per day, but we have the capabilities of expanding that substantially higher in the short term.

The Lineham Creek project is located in Cameron Parish, Louisiana. It has a significant structural feature that gives us great opportunities to test the ultra-deep below the salt weld, and this well has a targeted depth of 29,000 feet. Chevron is the operator with a 50% working interest, and our company's working interest is 36%. You can see this is 55 miles to the northwest of the Davy Jones discovery on the trend of the area that we've been focusing on.

Our chart on Page 13 shows the location of our existing wells that are underway, as well as other prospects that we have identified that we are looking forward to test, and confirms the tie-in of the geologic features that have been shown to be productive onshore, as well as in deepwater. And so we're going forward with that.

The Lafitte well has been drilled to 32,400 feet. And over the weekend, we ran logs on the Oligocene section and recorded 40 incremental feet of potential hydrocarbon-bearing sands between 31,300 feet and 31,700 feet in the Frio section. And this is the second well that we've seen this Frio section in.

For 2012, our production estimate reflects the continued depletion of our properties. As I mentioned at Flatrock, certain of the well intervals that we're producing will be depleting as we go forward and then recompleted, which would give us the ability to have higher future production from Flatrock. But for 2012, we're projecting 130 million a day. This does not include any production from the Davy Jones No. 1 well. We'll be updating production outlooks following the production test from Davy Jones 1 well.

On that basis, our first quarter production for 2012 would average 155 million cubic feet a day. Our capital spending is always driven by the opportunities that we have, and the results of our drilling and development activities. We're going into the year looking at spending in the same range as our 2011 spending of roughly $500 million a year, but we'll update you as we go forward with that.

We're also planning to continue our program of dealing with our abandonment obligations and project spending roughly $60 million on abandonment during 2012.

Our chart on Page 15 is a chart that we show each quarter looking at cash flow sensitivities, looking at projected 2012 cash earnings based on various production levels. Based on our outlook of an average of 130 million a day, that would generate cash earnings of $190 million, and you can see the variances that would occur for changes in oil and gas prices below that. And then we've also shown what that would be at 150 million a day or 180 million a day as an indication potentially of -- as potential for outlook for production from Davy Jones, following a successful production test and getting that well onstream for a portion of 2012.

That's the summary. Jim Bob, do you have any comments you'd like to make before we open the floor for questions?

James R. Moffett

Yes, I think I'd just like to point out a couple of things. At the Blackbeard East well in particular, we have a logging to try to evaluate the Big Sparta sand that we saw in mud log, which is why we are – which is why we sidetracked the well down. And so we hope to have some information on that for you.

Blackbeard West, if you look at -- reference Slide 19, I'd like to remind you that's a very interesting well for us, because as you remember, when we drilled Blackbeard East, we had what we thought was a signature for salt to be into sub-salt – excuse me, to be in the salt weld. And we drilled through the salt weld at Blackbeard East, we found productive gas sands as opposed to salt. We then began to curiously follow that salt weld to the west, and we have 2 prospects that are keying off of what we call our cupola play.

And remember, the cupola play is a very simple gorge, because the cupola and the igneous petrography and volcanic vocabulary means the top of the volcano where before the volcano erupts, oil and gas as it come up through the fracture, lava come up and then finally build up like a pressure cooker, and finally the thing blows its lid. Well, obviously, in the case of the salt weld, W-E-L-D, which acts almost like a metal top, a rooftop, if you will. So we coined the phrase cupola play, and you'll notice that Ship Shoal 188 is the No. 3, and it's important because it's keying off of Blackbeard East. And to the west, you'll see Barbosa that has a significant cupola. And when I say a significant cupola, I mean, if the reflectors are not salt, and frankly, we don't believe they are after looking at Blackbeard East, but if they're not salt, there should be gas accumulation.

Now that's important, because if you'll notice 25,000 feet is below the target for all these cupola plays on this page, and that means we can use conventional equipment and have really, certainly not shallow sands, but sands above 25,000 feet. And if the cupola velocity anomaly that we’ve model it anywhere near the rest as gas and not salt, we could have some significant thicknesses in order to have pretty good sand quality based on the Blackbeard East sand quality. This would all be Miocene, by the way.

So importantly, because the holes are shallow, shallower I should say, the well cost is going to be significantly reduced. We had been talking to you about, because we're drilling a smaller hole, we said 16-inch pipe as opposed to 20 inches which was used in the Blackbeard West by the first operator. And we've already got this intermediate stream set, which is 16-inch pipe and we're below 13,000 feet this morning, and we spent just over $20 million. So if things go well, the important thing is, these wells hopefully can be drilled for just over $50 million. That’s lots of money, but compared to the other cost, it's a significant improvement. And yet, we still get a shot at these sub-salt, high-pressure prospects.

So the Blackbeard West well, which we had set pipe on, and we're awaiting information from Blackbeard East and Blackbeard West 188, that big 25,000 units being held by production, or what we call suspension of production, in this well it was significant because it satisfied the requirement of the BOEM to hold that 25,000 there. As you can readily see, you correlate it from 3 to 2, it’s a fairly close offset. So let's wait and see what this velocity anomaly is, let's see if it's salt or whether it's of kind of high-pressured shale or whether it's like Blackbeard East suggest, it's Miocene hydrocarbons. And the gas that's in there, as I say, has migrated up through the fractures from the ultra-deep, and hits that cupola, hits that rooftop, and so that's a significant difference in the cost of the wells, cost to complete. And yet, we could have some really high flow volumes that could actually brought on production quickly because you've got a lot of shallow platform, shallow water platform [indiscernible] it's sandy.

So I also call your attention to Lafitte. Lafitte, of course, we've already reported as several Miocene possible hydrocarbon sands. On Page 21, you'll notice the Cris R, which is a textbook-looking sand there. The yellow, of course, is the sand, showing the good gamma-ray deflection and there is still recoveries [ph] of shale. So that should have a big impact. The reason I mentioned the Cris R is in several conversations I've had at presentations, in person, people are asking me, "What kind of potential does a Cris R sand at 60-feet thick?" I have a log, which is now available to everybody, by the way, on the Macondo well. And the Macondo well, why am I bringing it up? Because it, of course, lot of people thought, that thing was blowing wild, and it was a huge reservoir. It may be in laterally spent [ph] a very big reservoir that supported those kind of low rates for all that time on an uncontrolled basis.

But if you take that log, ladies and gentlemen, and lay that log down on the Cris R Miocene sand and Lafitte, they're almost identical. But the Miocene reservoir that was in the Macondo well was much shallower and had a 13-pound mud environment, where we are in an 18-pound mud environment, which means we have significantly higher pressure. And if we push more hydrocarbons to the sand at this depth with more pressure, so we'll see what it will flow. But that's a good analog.

And on the right side of your slide, you'll see we got into some Frio zones. They're thinner zones that are inter-bedded with shale. Now we don't know whether it's on the top of that darned thing, but the base of where it looks like we're seeing hydrocarbons, which is about a 400-foot section. We don't know whether that's one big reservoir that's got what we call members. There was a Frio formation with 6 or 7 members. And you perforate them all, whether those are individual zones that stack on top of each other and would perform if we perforate them all, as though it were one reservoir.

Now the other significance of taking a minute of your time on that is, this is the second well. The second well below the salt weld on the shelf that we've drilled, that has seen Frio sands. The Frio sands are gone in the deep water. So across this Frio trend, which we thought we would -- had pretty well established with the Blackbeard East well, if you take the Blackbeard East well and lay down the log and correlate it with this Lafitte Frio section, the doggone thing’s some 80 miles away, looks like it was drilled in the same borehole. So it says if the Frio has some expanse here, we'd know how thick the sands were onshore.

So we've got a good hand that as we drill out these wells, some of these sands should thicken up. And we may have -- we, actually, on this well, this section, not to bore you with geology, this section is known as the lower Frio because it is in what we call the marshes [ph] test bow mesh and streamer. Van Peter [ph] in those zones that we correlate 150 miles to the north onshore up around Lafayette, Louisiana. What we did was we had a 4 million year unconformity right above this, and we faulted out what we called the Cameron, my gypsy [ph], and I bring that up because that's a huge producer to the north, trillions of cubic feet of gas as they say. So we don't know whether we faulted it out or whether it was non-deposited. But with that 4 million year unconformity, it could be a parallel fault to the bed, or perhaps, the reservoir to begin with, that being near the Lafitte fault is shown in purple on the cross-section.

Now one last thing. That means that we've seen from -- since we drilled out of the pipe, we've seen from 25,000 feet now to 32,000 feet. Every reservoir, i.e., sand that has had porosity, has resistivity and appears to be hydrocarbon-bearing. So that means that this area at Lafitte, which is bordered on the west by Barataria and by Captain Blood to the south, both significant features that we can drill. That means that you got hydrocarbons that are being trapped from 25,000 feet, 32,000, which is a big area of entrapment.

What am I saying? I'm saying that this thing could cover a big area and be productive like, very much like the Tahiti, Maddog, Puma, example in the deepwater. So stay tuned. We'll see what happens.

This slide, #22, depicts what I just told you. Here's a Lafitte well and you got hydrocarbon coming from 25,000 down to 32,000, which is as deep as we -- almost 33,000, which is as deep as we drill. And Captain Blood, as you can see on the right side of this slide, is a significant 4-way closure, jumps out at you on the side, I mean. And of course, Barataria to the west of Lafitte is a significant structure also. So it's a huge area of some 100,000 acres that we can drill. And each of these wells gives you a good hand as to what you might expect on those other prospects.

Looking at Page 23. If you refer, excuse me, let me flip one more slide. Let's flip back to -- let's flip back, I’m trying to get you on your computer so you can have a -- excuse me, I'm just getting -- people are coming here, flipping my slides for you. This is back on. If you take the information it shows you on the wells that we're drilling on the shelf, you notice the Davy Jones well is just north of Lafitte. And if you take down the Lineham Creek prospect, which is 55 miles to the -- you go to Slide 9, is what I was going to ask you to look at, Slide 9, which was in Richard's presentation.

If you look at Lafitte and look at Davy Jones, it's about 80 miles south of Davy Jones. And you look at Lineham Creek, which is 55 miles to the northwest. You look at Blackbeard, which is about 80 miles to the west and southwest, to the east and southeast, if you look at the Blackbeard wells, Lafitte wells and Davy Jones, once again, we have got those points of control because Lineham Creek hasn’t gotten deep enough yet to give us any control. Our seismic database has predicted the depths of these various objectives, whether it be Wilcox or Miocene or Frio or Cretaceous, and that gives us a huge confidence, and for you to be able to say in a complex like the Gulf of Mexico that you can use 4 control points, and with saying that the seismic ties are giving us the topography of this subsurface, that's what we -- the most significant thing that we've done.

So with that, I hope that gives you a good insight into where we are for the aspiration program. And, Richard, I'll turn it back to you all to open it for questions.

Richard C. Adkerson

Okay, good. Thanks, Jim Bob. Operator, can you open the line for questions?

Question-and-Answer Session

Operator

[Operator Instructions] And your first question comes from the line of Lee Cooperman of Omega Advisors.

Leon G. Cooperman - Omega Advisors, Inc.

I kind of -- your enthusiasm comes through, and I understand that every step of the way, your theory is being confirmed. So we have 2 opposing forces. We have one which is declining production, declining cash, declining reserves, against the comment on Page 3 of your slide deck that says data continues support potential for major new geologic trends, spanning 200 miles in the Gulf of Mexico Shelf. So my question is, how much longer do you think it takes for the data to kind of tell you definitively what you have where you can get on a call like this and say, “Eureka, the $1 billion we're spending on exploration gave us that $50 billion or $100 billion play?”

James R. Moffett

Well, I think as we've said, thank you for the question, Lee. I think the most significant thing is flow test. And the reason why the flow test is significant, the logs we have and the data we have would be sufficient to book reserves and start to get these reservoirs on production, except the fact that we don't have a good analog that is in near vicinity. And unfortunately, under the definition of proved reserves by the SEC, the reservoir engineers, Ryder Scott, insist that we have a nearby analog. Now if you get that, then everything else becomes bankable. And that's why we feel that the test is imminent, and the fact that the data is so clairvoyant when you take the seismic, and for instance, this cupola play I talked about, one of those things, which would be the second penetration in there, which would also give you enough data to where you start to create your own analogs. Then your acreage position becomes an asset, which you can decide if you want to bring in partners, whether you want to leverage financing against proven bankable reserves. Your options there then become multiple, and we're very close to that, with this test at Davy Jones, because it'll give you basically the confidence, that even though the [indiscernible] are not all Wilcox, as we said before, the logs have similar characteristics. And with deepwater wells now that have been tested in the Miocene, there's only one that's been tested in the Wilcox in the onshore production. Just to the north of -- once we have people at our, and most importantly, ourselves, convinced that this is really a piece of the puzzle that just fits right in, and says that this is trend, this 200-mile-wide trend is just going to be just like the onshore trends and the deepwater trends, then that's when the values are there. And we've seen that there's a lot of people that are interested, despite the low gas price, we see money coming in from all over the world that have taken big positions in proven gas plays. So to answer your question, Lee, it's imminent, and that's why we're so anxious to get a couple of these things under our belt here, the first half of the year, exploration-wise and production-wise. And we think we'll be off to the races.

Operator

Your next question comes from the line of Noel Parks of Ladenburg Thalmann.

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

Just wanted to get a little detail. It sounds like you did get that stuck tool out at Davy Jones. I just would like to hear a little bit more about what was involved in getting that out, and whether it was -- happened faster than you thought when you announced the problem, I think it was on January 5. And then also assuming you do move forward, what the timing for Davy Jones No. 2 looks like.

James R. Moffett

Thank you very much, Noel. Well, obviously, we had a bad break by this little motor coming into. If you look at the statistics of these mud motors, there's been thousands of them running wells and this thing just happened to come apart on us. Now the fact is, this one of the deeper plays that the mud motor is being used. And when it parted, it was just lodged in this inside the casing. So we knew we could retrieve it. But the questions then become, and unfortunately, when you're anticipating something like this test, everything becomes news, and we’re complimented so many people are interested in the operations. But frankly, it was a simple matter of taking the hole size we're operating, was 3 3/4 inches, actually, the idea of the pipe. And we had to go down 23,000 feet and grab this 4.5-foot fish, and you can't feel much weight change. So we just had to be delicate with it and clean it out. Some pieces of metal were in the well where they come from. And we TNA’d the well, we had to grind up these retainers up the hole, and some of that metal, instead of circulating out, apparently towed out into the smaller pipe. And it put a bind on this motor. So now that we've got that done, we're already back to washing. And hopefully, in 7 to 10 days, we'll be from 23,000 to 29,000. And obviously, we're going to be very cautious about how much strain we put on the mud motor because this is a similar motor that we had in the hole. But it becomes a drama when you have so many people, including ourselves, that are anticipating this flow test. So that's really why the thing became a news item.

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

And Davy Jones No. 2 now, when do you think that might come online?

James R. Moffett

With the success of Davy Jones, we can go right over to that. We've got all the equipment to test, the broad bangers [ph] and all the equipment we use can move over to Davy Jones 2. And then we'll go through the same procedure there, and hopefully, we got bigger pipe in that well. So if we do have any kind of problem, similar to this mud motor failure, it's just that much easier to work in the bigger pipe. But that ought to go smooth, and hopefully, with the success of the No. 1, this industry says [ph] the No. 1 we get over and get that thing flowing and it’ll go right into the facility, because we have a transit room, and we'll just run a flow line over there, and it'll go right into the same production line that the No. 1 is going to go in.

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

And so you think midyear still looks reasonable for No. 2?

James R. Moffett

The more we have these unfortunate delays at No. 1, that just moves that back slightly. But let's just say that it will be closely following the completion of the No. 1 well.

Operator

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

Eric B. Anderson - Hartford Financial Management, Inc.

And just quickly, Jim Bob, I calculate, it looks to me you've got about 600 feet more to go on Lafitte and 700 feet more on Blackbeard East. Just wondering if you could sort of comment on kind of the reflectors in both wells that you're looking for and maybe what lies below there?

James R. Moffett

Eric, the big factor in that question is, as you know, we had to sidetrack this Blackbeard East well. And before we had that mechanical problem at Blackbeard East, we had drilled. And by mud log and gas shows and what was called sand, and we knew it was a spark because of the Paleo. And so we drilled back down through that, and we're trying to log it right now. If it is a reservoir, and so it's about 300-feet thick on this big structure, that could be TVD for us, and we would take that production. Because as you know in that well, we have, above that at 30,000 feet, we have the Frio sand that's obviously productive and then above that, we have the Miocene sands that are productive in the 24,000-foot level and up at 19,000 feet have some additional. So the Sparta and the sub-Sparta that we drilled so far, indicates that the section in Sparta was very thick. And so therefore, it may put the Wilcox at Blackbeard East deeper than we would want to go for the Sparta. So that's the sort of plan going forward there. In Sparta, at this logging operation which confirmed the thick zone, it was mud -- shown by mud log in the original hole would be extremely important, because that would mean that the Sparta sits right below us at Lafitte. Once again, we're 80 miles to the west. But the way we've correlated it in the Miocene and now the Frio, we're sitting right on top of that Sparta. So that Sparta would be an objection we'd want to go get, because it's not far below our current TD. And then going back to the Blackbeard West original hole that we drilled deeper and had the Miocene pays, we're sitting right above the Sparta, and frankly above the Frio in that well. So that would give us a target to go back and deepen the Blackbeard West well. So to try to keep this in an organized fashion, Eric, we’ve said that these layer cakes that we've been adding, the Miocene and then below that, the Frio and below that, the Sparta, and below that, the Wilcox and below that, the Cretaceous. Now that we've drilled and located the depth of those things, East, West, we expect those layers will be present all the way across this 200-mile trend. So I hope that gives you some idea of when these wells sort of determines what the section below our current TD on these wells is going to look like.

Operator

Your next question is from the line of Richard Tullis from Capital One Southcoast.

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

I know you've mentioned a flow test at Davy Jones is being imminent. Do you expect to initiate that within the next 1, 2 weeks there?

James R. Moffett

If we can get cleaned up, it would take us 5 days. It could take us 10 days. We're being very cautious after having this hiccup with this doggone small mud motor, Richard. But if we get that done, then we would be basically setting the perforating guns in the well. And then we run our tubing, and it is inserted to what we call a polished bore receptacle at 16,000 feet. And we run our tubing and put the clearing there, go down and perforate the well and then stand back. So that's sort of the days that we've got in front of us. And those -- that could be a 3-week period depending on whether we -- everything goes smooth from here because it ought to be, once we get all this silly mechanical stuff out of the hole like the bare rider [ph] set up, it should be -- nothing is routine at this depth, by the way. But it should be as routine because you don't have any obstructions there. It's mostly running, screwing pipe together and testing the connections and then putting on the tree and flowing the well.

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

Okay. And then just quickly, could you roughly walk us through the guidance for 2012 dropping from the 170 per day in 4Q to the 130 in -- for '12? I mean, how much of that is Flatrock? And how much is just declines elsewhere?

James R. Moffett

Well, as we've said, Richard, since we haven't been able to add production because of the obvious lack of flow rates, flow testing and the only thing we have -- had been producing are the properties that we had discovered and/or acquired prior to our focus on this ultra-deep. We started basically 2 years ago. So what we have in our producing category is production from Flatrock and the other legacy properties we had and many [ph] that we had discovered long point and others and main pass. And then you have, of course, the properties that we have acquired from Newfield, and so that's the properties that we basically are reporting to you as far as the production decline. Now Flatrock, although it's produced about 300 Bcf already, is still in the early ages of producing. So we could have some more surprises as we re-perforate reservoirs. There’s multiple in that situation. It's getting more predictable as we get pressures and recovery on the different wells in these layers start to pile up production history. But that's basically why we've seen a decline. The reason why we are patiently waiting to see if we can prove that we've got this new trend that we've been talking about is because the kind of structures we're drilling, Richard, if we're right, with these multiple horizons, hydrocarbon-bearing, as Flatrock was, that's a good example of what we hope to do at something like Davy Jones and at Blackbeard and at Lafitte, where we've seen multiple pay, is to be able to bring these things on production. And the big deal is the structure at Flatrock was a very big structure for being above the salt weld. It was about 3 miles wide and about 4 miles long. If you take the size of that and compare it to Davy Jones, Davy Jones is 20,000 acres big, whereas Flatrock was like 5,000 acres big. If these reservoirs are what we think they are, especially things in the Miocene like this cupola play that we’re drilling, if it's successful, those wells will come on production. And you look at all the big fields that we've been comparing to, the big giant fields that have the big closure, 15,000, 20,000 acres big. And look at the fact that there's -- some of those fields are still producing that were discovered in the '50s, '60s and '70s, we're talking about having a pipeline of properties that would have 30-, 40-, 50-year lives because they'll be in these stacked reservoirs. We won't want to be going in and drilling acceleration wells for all of these wells. We'd be basically perforating and coming up the hole and bringing these wells on production. So you're going to have -- if we're successful and we get the kind of drainage we hope to get from these reservoirs, you'll have long life completion, and then you'll have flowbacks that will also be long life. So you’re going to see things like the shale gas plays that have flush production for 6 months and then flatten out with limited production for years. Whereas, if our geology proves up and we have the kind of lateral extent with multiple reservoirs, we’ll be having some of these wells that will still be producing 30 years from now. And that's really what this play is all about. As opposed to we spent a lot of money proving up the area and proving up where the targets are, our challenge is to continue to reduce the cost of these wells. I mentioned the cupola play a while ago. I hate to mention it again because we’ll know here pretty quick if that cupola play is right just like the sands up in 19,000 at Blackbeard East. That could set up some stuff that we did too quickly with smaller rigs, smaller pipe and obviously, less than half the cost of the well that we're drilling below 25,000 feet, and all that could come on production with those reservoirs, if they look like the other Miocene reservoirs that we've seen in the deepwater and in our own wells, those are going to be wells that are going to have high flow rates, and we're talking about using the extent of these velocity anomalies like at Barbosa being anywhere from 1 to 2.5 Tcf gas. We can pop a lot of those wells down. So that's why when I answered Lee Cooperman’s question, that's where we will be able to start taking things through the bank and decide how we want to finance a multiple-well development program, which would generate the kind of cash flow I reiterate. If we’re right and these things cover much area as they do, these wells will be on production and these doggone fields will be producing 30, 40 years from now just like all the big fields they produced onshore, Mound Point and Tiger Shoal where we drilled in Flatrock underneath. Those fields were found in the late ‘40s, and they're just now on their last leg. So it'll be a new definition for a cash flow stream, as opposed to the treadmill you get on where you're drilling wells that deplete or have flush production in less than a year. So that's why the trends, the shale gas play versus the play we're drilling is more like the conventional reservoirs you see in the Gulf Coast.

Operator

[Operator Instructions] Your next question comes from the line of Leo Mariani of RBC.

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

Just to follow up on Davy Jones in terms of the first production tests, what do you guys think the capacity of the equipment's going to be on the test here? Are you guys going to be limited at a certain potential rate here?

James R. Moffett

We've said theoretically that because in this first well we sidetracked and therefore, the smaller hole with the tubing that we have in this well, and 2 7/8 tubing, that we may be limited about 70 million a day. And we really don't know because nobody's ever tested the well at 30,000 pounds of bottom-hole pressure; friction loss and things that would eat up your pipe just from flowing through this hot gas through too high a volume. But theoretically, we think we're talking about something around 70 million in this first well because of the size of the tubing. The next wells will have bigger tubing like the Flatrock field to this shallower just to the north of us. We flow those wells at 100 million a day, 3,000 barrels of condensate. So but on the first well we think we'll likely be limited to something like 70 million. And of course, we’re hoping that we would have a flow rate that could have sustained rates at that or more in the bigger pipe well that we drill as follow-up wells.

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

Okay. And I guess, so it's not really a related question but a question on Lafitte here. Basically, you guys announced, I guess today, that you found an additional 40 feet of Frio pay. You talked about the Frio being present across a pretty big area of the shelf is, I guess is the hope here. I noticed that you guys did not update the potential at 1.3 Tcf here for Lafitte. I mean, do you guys think that that's going to go up here in the near future here in terms of what you think Lafitte can have?

James R. Moffett

Well, we didn't update the so-called potential reservoir or resource because we felt like based on the thicknesses that we saw 200 feet, plus or minus, that, that was sort of what we had in mind when we're talking about the Miocene by itself. And so rather than add new numbers, we had enough stretch in the original resource number. If we’d have had, I think we had 170 feet in the Miocene. If we’d have had 250 feet in the Miocene, then we might have had a reason to add a resource. But we just logged this well. We're trying to give you these updates as quickly as we possibly can. And we wanted to study what the possibility of what this 4-million year gap in the Frio where we need to fault it out or scarp it out by that conformity, one of the major cycle themes called Miodeep [ph]. In other words, as you move around in here and you go over and drill Captain Blood or Barataria, you could find out that in this well, and we actually didn't see the entire section, but frankly, the reason we can't say more than that, we're correlating from wells 80 miles away, and you can’t necessarily pick a fault that says, aha, we faulted out 100-foot sand that is going to be productive in all set wells. But we have to put our antenna up when we see the Paleo go and have a 4 million-year hiatus. How much section did we not see? And the offset wells would tell us that you just can't pick a fault with a well 80 miles away, unfortunately. And that's going to give us -- that's going to be one of the more other interesting things that’ll happen as we start to develop these structures and drill some development wells.

Operator

Your next question comes from the line of Biju Perincheril from Jefferies.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

Following up on Davy Jones, when the mud motor got lost in the casing and then you try and dislodge it, is there any risk at all that its casing could be compromised and you may have to run some testing there, add some more time to the when the testing -- when the flow test can be done?

James R. Moffett

No, the pipe was not compromised. We've already -- first thing we did when we got the mud motor out of the hole was go in and pressure up to 5,000 pounds. But what we used to get the fish -- fish equipment out of the hole, we had no cutting edges on the sides of the shoe that we were using. And we didn't really ever burn over any metal. We grabbed it and yanked it out, as opposed to trying to grind it up. But to answer your question because of the shoe that we had in there, it's a very stiff hook up. And with no carbide on the outside of the threading shoe just on the bottom surface, there's nothing that you can thread the pipe with. So but we already tested the pipe at some 5,000 pounds the minute we've got this tube out of the hole.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

Perfect. That's very helpful. If I could ask a follow-up, you talked about the Blackbeard East some of the shallower sands below -- or above 25,000 feet. What are the plans? Is that something that can get drilled this year? Or...

James R. Moffett

Well, frankly, the only thing we've been doing is trying to get this deeper part of the hole, evaluate the Frio and the Sparta because if we're going to -- if we end up with a significant reservoir deep, we will move another rig on and a smaller rig and drill a much cheaper hole to drill a well to test those sands. But we’re waiting because if we don't find a significant reservoir that we're looking for in the deep part of Blackbeard East, then we'll plug back and complete the sands in this well. But you don’t want to -- you can't do both. You can't make dual completions, for instance. So that's why we haven't moved another rig in to drill the “shallow” 24,000-foot portion of the hole. Those are some of the things that is just good business practice to leave yourself that plug back if you decide you're not going to take a completion in the deep. And therefore, we may use this well for the development or the completion in the shallower Miocene in this well. That's why we've been waiting to see what the results of the deeper part of the hole is.

Operator

Your next question comes from the line of Joan Lappin of Gramercy Capital.

Joan E. Lappin - Gramercy Capital Management Corp.

I have several questions. I mean, it's all related to natural gas prices. Obviously, they're like sickeningly low. And what impact will that have on you going forward? Now you've talked a little already about the fact that you're a much lower cost producer than the shale people, who I don't know how they are even bothering. They need $6 or $7 to breakeven. So you could you give us some sense of what your actually breakeven is now? And also, as gas prices have inverted from where they were a few years ago and you went after your main pass license, that was to import. But now, it would make more sense to export. So what would it -- how much time and energy will it take you to do that? And what would be the tipping point that would make you want to bother?

James R. Moffett

Thank you for those questions, because they’re both very relevant. There's a lot of predictions out there what's going to happen to the gas market. But the fact that people are willing to spend the money to, all of a sudden, talk about exporting gas from the United States into the Asian markets where they’re getting $10, $12 for the LNG, we're watching that very closely. Let me answer the second part of your question first. If you remember, we have this substantial platform over this salt dome, which was going to be the dome that was going to be used once the gas was re-gasified when you brought a ship in here. So we were going to be able put up to 0.5 Tcf gas into that dome to -- after it re-gasified. The platform we have out there, there are 2 of them, look like big football stadiums. They're that big in size. We have plenty of room to reverse the process and take the gas and liquefy it and then load it into ships. And the storage area that we have by using the salt dome storage which, as you know, is the -- there's 46 domes across the Gulf Coast that have these storage caverns. We [indiscernible] those caverns, to put gas in those caverns and have a resource while we were sitting there liquefying the gas to be shipped LNG. And of course, having that do it out there in the water, so these big tankers don't have to come into the ports just like they were -- just like we – the advantage we had when they were going to be coming in to get their gas re-gasified, it all does flip. And so we are actually considering that fact. But frankly, with oil selling for what it sells for and the price it’s costing people to keep these oil tankers full and waiting for the best place to unload, we've had many inquiries about storing oil in this dome. And that's an interesting part about the dome. The caverns can either be put to use for oil storage or natural gas storage, and you can actually do both at the same time. You can have some of your caverns with natural gas, some of your caverns with oil. And this salt dome is one of the bigger salt domes in the Gulf Coast in terms of its surface area. But it would -- it is the only facility that would be in the water, so to speak. The metal that you'd have to spend to put another facility out there couldn't compete with us. That metal is probably worth $500 million to $700 million just the way it sits now. So as far as gas prices are concerned, you made the comment yourself how the so-called $6 to $7 per Mcf cost is going to continue to be spent if gas prices don't go back up to $6 and $7. There's all kind of reasons, but since we're not in the shale play, we won't try to be experts at that. We know that there are people that have lease commitments deep drilling the hole, their acreage. But the answer to it is, is that the long-term life of these reservoirs, as I explained before, we've been through these cycles of gas and all these projections about gas being over the demand. What I'll tell you is in the minerals business, we've seen it happen. You can't keep producing product and generating product at less than replacement cost because when you do, it's just a defining moment as to when the cycle turns. Using copper as an example, when we first found the big copper mine in Indonesia, copper prices was 7 below replacement cost, and you had high-cost producers in the United States all over. You had [indiscernible]. You can go down the list, Newmont. And all the copper that was being produced was being produced and sold at $0.80. And it was costing $1.50 to find it and produce it. And people just took it for granted that it, well, hell, it would just go on forever. And when that did flipped, the gas price went -- excuse me, the copper price went from $0.75 to up to $4. And nobody, 0, predicted that, that was going to happen. So you cannot produce at less than -- you cannot sell and have your replacement cost be below the cost you can sell for an extended period of time, and that's just Economics 101. So there’s guys smarter than we are that understand why they're doing what they're doing, drilling, as you say, wells that have replacement costs of $5 to $7 at these kind of prices is their business. But that's why we think if we are correct, and we have these 15,000, 20,000-acre structure with multiple pays that would be like storage tanks, that those kind of paydays would come to us. And that's the difference between the 2 plays.

Joan E. Lappin - Gramercy Capital Management Corp.

What – but at this point, what are your costs compared to that $7?

James R. Moffett

Depending on how many reservoirs we find above 25,000 feet or below 25,000 feet, we will get a better definition. And if you take the reserve sheet that we have that puts these resource gas behind the plays, our finding costs and development costs for these cupola plays, for instance, which are significant, are going to be much less than the current cost. But on our deep stuff, we had estimated about a $2.50 breakeven cost is what we were projecting before we found these shallower Miocene reservoirs that we continue to talk about. So the key here is we know now we're going to drill 5 wells out there. We know significant savings that we can put to work to try to get the costs of these wells down. And now that we've spent all the money, for instance, to get these bigger blowout preventers and test equipment that's required to test these wells, you don’t have to spend that money but one time. And so we’ll get a lot better answer for you when we know how many reserves we're going to have above 25,000 feet and how many we're going to have below 25,000 feet. And we've already discussed the fact that we reduced the casing size or what the original casing design was for the first deep well drilled by another operator, and we've seen significant savings there. Watching wells like the Ship Shoal 188 where we're this morning right above 14,000 feet, and we’ve spent just over $20 million. If that 188 cupola play is successful, it will give us a layer of much cheaper wells to drill development wells, et cetera. So we’ll try to define that for you as we continue to define our -- the depth of our objectives.

Joan E. Lappin - Gramercy Capital Management Corp.

So would it be fair to say that if you did a comparison today to Macondo and showed us a log of one next to the other, and we know that thing was gushing oil. And you've always insisted that you're going to find gas because of the extra weight of the rock over the water. But the question is, I guess, what will also be a key factor for you is how much liquids you're going to find down there. And I mean, your presentation to the -- Kathleen's stuff today shows you're getting these huge prices on the liquids and nothing on the gas. But that it goes into this equation as to where your breakeven is and whatever. So I'm just wondering on Davy 1 or 2 or any of these other wells, what kind of assumptions you're making as to whether there'll be liquids in there or not.

James R. Moffett

That's an excellent question. Let me answer the same way I just did about our cost of drilling. The reservoir that we're drilling for -- at Ship Shoal 188 that involves Barbosa and the shallower part of Blackbeard East that we defined, which I hate to repeat myself, we thought those -- that our reservoirs would be mostly below 25,000 feet. But those reservoirs, they go up as high as 17,000, 18,000 feet. If this cupola concept is correct, and you've seen the data that stands out like a sore thumb, if we prove that up, those depths that we could expect to have some condensate. So until we confirm that the Blackbeard East reservoirs that we have between 19,000 and 24,000 feet are not just at Blackbeard East but have a wider distribution across the rest of our prospects, that could have a huge impact on what our condensate rate would be. It's only when we get into this 30,000-pound bottom hole pressure and 400-degree temperature that the petrochemical side of what can be produced comes to pass. In other words, it’d be dry gas below 25,000, and we could have substantial liquids above 25,000. For instance, as you’ll remember, we had about 3,000 barrels a day, 100 barrels -- 100 million cubic feet a day and 3,000 barrels of liquids in the Flatrock test. So these reservoirs we're seeing above 25,000 feet, we just got to get a test on them, frankly, so we see what the condensate ratio is.

Operator

[Operator Instructions] Your next question comes from the line of Joseph Allman of JPMorgan.

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

Just a question on your reserve revisions. So in terms of -- it seems that Flatrock is performing better than your expectations. I don't recall seeing you mention that earlier in the year. I know that Laphroaig seem to be doing better. And then could you just explain the revision related to the NGLs? Is there some new contract? Or what makes you book these additional NGLs now versus before?

James R. Moffett

Well, frankly, it's the price of what they're paying for the dang thing, Joe. They’ve always been a factor. It's significant that the prices going up adds value to the natural gas liquids because it costs a lot of money to put the facilities in to extract this darn stuff. And when liquids prices go up and all of a sudden, your profit off of an NGL becomes significant versus what it was when you were having to spend all this money to separate this gas, as opposed to just selling higher BTU gas, all of that comes into play. So not just for McMoRan, but everybody is having the effect of how valuable these NGLs are just like we just got through talking about in answering the last question. Because whereas, let’s just say before, it was costing $1 to get these liquids processed, and you were selling gas for -- excuse me, selling oil for $35, $50 a barrel. All of a sudden, the first money you made was limited because of your high cost of recovering the NGLs. The higher the oil price goes, that's all profit. And so I think you'll see everybody, not just McMoRan, will start to have a significant increase in revenues if the oil prices hold. It’s a whole lot like the shale gas play where people have focused on going into the trends that have liquids because the profit at $100 a barrel is so significant. But we talk about $100 oil like it's commonplace. Is it going to stay there? Well, we'll see. But that's the most important reason why the NGLs, all of a sudden, become so much more significant than they've been in the past.

Richard C. Adkerson

Joe, this is Richard. In the past, this had been reported as wet gas. So the volumes didn't get reported, but it was included in the PV calculations because the liquids would get valued in that calculation. Going back in history, liquids had always been reported separately and with these higher liquids prices, we talked with Ryder Scott, and they were separated out because we think it's more accurate reporting to show those volumes, as well as the PV effect of the revenues.

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

Yes, okay. Because NGL prices were fairly high a year ago as well. So is it just -- so what made you do it this year? Was it just a difference in the pricing or just the...

Richard C. Adkerson

No, it was just the review of the way the reserves reports had been repaired and what others had been doing. And we just had a discussion with Ryder Scott and mutually agreed that this was the better reporting.

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

Got you. And could you talk about – and how much was Flatrock a part of the positive revisions?

Richard C. Adkerson

Let's see. There's a footnote on Slide 5 that gives the details. It's 26.6 of the total. The other major ones were Main Pass 2.99 and Laphroaig. But there's Footnote 1 on Page 5 that gives that detail.

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

And Flatrock is actually performing, the production is higher than what you previously had modeled?

Richard C. Adkerson

That's right, and this goes on to actual production and pressure test and all the things that reservoir engineers look at in determining reserves.

Operator

Your next question comes from the line of Gregg Brody of JPMorgan.

Gregg Brody - JP Morgan Chase & Co, Research Division

Would you mind talking a little bit about what you see on the borrowing base side in terms of what banks are using floor price tax, how that might impact your borrowing base?

Kathleen L. Quirk

Gregg, this is Kathleen. We've just gone through a borrowing base review late in the year, and the banks affirmed our borrowing base at $150 million. They have been, over time, decreasing the natural gas prices, and they run it at various levels, and every bank's different. But they'll run it at a certain level and then stress test it. But in our particular case, our borrowing base was reaffirmed at the $150-million level.

Gregg Brody - JP Morgan Chase & Co, Research Division

Okay. And then you've said in the past that when you tested Davy Jones 1, you would potentially book reserves, and we thought that might happen before year-end. And so is it -- is there the potential that we could actually see a reserve report after you test the well by midyear, maybe immediately? Is there – are there any thoughts there?

Richard C. Adkerson

Well, that's certainly a possibility because the flow test does give the basis for determining the reserves, and we're just going to wait and evaluate what the circumstances are then. But we'll be reporting, as all of you know, we're a very transparent company. So we'll be reporting information as we get it.

Gregg Brody - JP Morgan Chase & Co, Research Division

And just my last question for you. Just with the recompletions you were talking about at Flatrock, I didn’t get the sense that was – any of that was happening this year. But could you give -- is some of it happening this year, and how much is in the budget right now?

Richard C. Adkerson

It's an ongoing process, but the recompletions that we were referring to are basically beyond 2012 with the impact coming in, in 2013, but it's a normal -- and beyond that. But it's a normal course of business. These were multiple pay sands in the individual wells, and as you complete, you want to capture all the economic recoverable volumes that enter a particular completion. And as that completion depletes, then the recompletion will be made to other zones, and that's the normal course of business for fields like this.

Gregg Brody - JP Morgan Chase & Co, Research Division

So it sounds like it's mostly next year.

Richard C. Adkerson

Beyond next year, beyond 2012.

Gregg Brody - JP Morgan Chase & Co, Research Division

And then just I'm sorry, one more. The abandonment costs, you took them down a bit from this past year. Could you talk a little about why it is lower? Is there potential for that to go up or down in your...

Richard C. Adkerson

Well, there's always the potential, but we're completing some of the abandonment obligations. We're spending money to do it. We have a very active program of trying to spend money to complete abandonment costs, so that we reduce the risk of having platforms out there in the Gulf. So what you're seeing is actually work being done, and that work being done over time. We look for low-cost ways of doing it, and we'll continue to do that. And like all estimates, they're subject to revisions as we get more information about it.

All right. Well thank you, everyone, for your interest and your questions. If you have other questions, route them through David, and we'll get them answered. Again, appreciate everybody's interest. It's going to be an exciting 2012 for McMoRan. Jim Bob, do you have any closing comments?

James R. Moffett

No, Richard. Thank you.

Richard C. Adkerson

Okay. 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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