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Executives

Kathleen Quirk – Senior Vice President and Treasurer

Jim Bob Moffett – Co-Chairman, President and CEO

Richard Adkerson – Co-Chairman

Analysts

Nicholas Pope – Dahlman Rose

Joe Allman – JPMorgan

Noel Parks – Ladenburg Thalmann

Jason Wangler – Wunderlich Securities

Duane Grubert – Susquehanna Financial Group

Eric Anderson – Hartford Financial

Richard Tullis – Capital One Southcoast

Gregg Brody – JPMorgan

McMoRan Exploration Co. (MMR) Q2 2010 Earnings Call July 19, 2010 10:00 AM ET

Operator

Ladies and gentlemen, thank you for standing by. Welcome to the McMoRan Exploration Second Quarter Conference Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. (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 Quirk

Thank you, and good morning, everyone. Welcome to the McMoRan Exploration second quarter 2010 conference call. Our results released earlier this morning and a copy of the press release is available on our website at mcmoran.com.

Our conference call today is being broadcast live on the Internet and anyone may listen to the call by accessing our website homepage and clicking on the webcast link for the conference call. As usual, we also have several slides to supplement our comments this morning and will be referring to the slides during the call. The slides are also accessible using the webcast link at mcmoran.com.

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

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

On the call today are McMoRan’s Co-Chairmen, Jim Bob Moffett and Richard Adkerson. I’ll start by briefly summarizing our financial results and then turn the call over to Richard who will be referring to the slide materials and will, as usual, open up the call for comments after our formal remarks.

Today, McMoRan reported a net loss applicable to common stock of $21.7 million or $0.23 per share for the second quarter of 2010, compared with a net loss of $100.6 million or $1.40 per share for the second quarter of 2009.

Our second quarter 2010 results included significant items. First was a $13.7 million impairment charge recorded to DD&A to reduce the carrying value of certain fields. We also recorded $9.2 million in gains for insurance proceeds associated with recoveries related to the 2008 hurricane events in the Gulf of Mexico.

Our production in the second quarter of 2010 averaged 165 million cubic feet of equivalent per day net to McMoRan. It was lower than our publicly reported estimates in April 2010 of 170 million a day, primarily because of unscheduled downtime for maintenance on pipelines and other facilities.

Our oil and gas revenues during the second quarter totaled $104 million, that compared to $94 million in the year ago quarter. Realized gas prices in the second quarter of 2010 of $4.66 per Mcf were approximately 20% higher than the year ago quarter of $3.92 per Mcf.

And our realized price for oil and condensate of $76.20 per barrel were approximately 30% higher than the year-ago period’s average of $58.24 per barrel. These realizations do not take into account our gains and losses on derivative contracts.

Earnings before interest, taxes, depreciation and exploration expense totaled $59 million in the second quarter and $143.7 million for the six months ended June 30th. Our operating cash flows, which were net of $24 million in abandonment expenditures during the quarter, totaled $11 million and $91.5 million for the six months ended June 30th.

Our capital expenditures during the quarter totaled $60.6 million and $101 million for the six months ended June 30th. We ended the quarter with total debt of $375 million, which includes $75 million in convertible senior notes. We also had $217 million in cash at the end of June.

Our basic shares outstanding currently approximate $95.5 million and assuming conversion of our remaining 8% preferred stock and outstanding 6.75 mandatory convertible preferred stock, our shares outstanding would average between 109 million and 111 million shares.

Now, I’d like to turn the call over to Richard, who will be referring to the slide materials on our website.

Richard Adkerson

Good morning, everyone. In the second quarter, I’m going to be reviewing this summary starting on page three, so you can follow along on the slides. We are -- we will be providing where we stand with our Blueberry Hill sidetrack well as part of our deep gas exploration program.

We have had drilling in this area. It’s highly prospective with complex geology and now we have seen indications of hydrocarbon-bearing zones that we are now testing and we will continue to drill to evaluate deeper prospective intervals that have been indicated as being highly prospective, based on early drilling that we have done.

In our ultra-deep gas exploration program, we have advanced drilling on two of our wells. The Davy Jones offset appraisal well, which is located in 20 feet of water and 2.5 miles away from our original discovery at Davy Jones is being drilled. And then, at South Timbalier 144, in a well that is drilling now below 18,000 feet, we are drilling the Blackbeard East exploratory well. This is a well that is east, obviously east of our original -- nine miles east of our original Blackbeard well and we will be reporting on where we stand with that drilling.

And then we are doing work to progress the development activities for the discovery well at Davy Jones, we completed the well designed in the second quarter and now we are procuring equipment. Following the Macondo blowout on April 20, we have been working diligently and have completed by June 30, the necessary certifications that’s required by the Bureau of Ocean Energy management to allow us to continue with our activities -- all of which, of course, are in the shallow water and not in the deep water.

The details of the financial data that Kathleen reviewed are included on page four. And then we have the map on page five, which shows the location of our very significant amount of acreage that we have in the Gulf of Mexico. We have rights to over 1 million gross acres including 200,000 in the ultra-deep trend, all -- virtually all located in the shallow waters of the Gulf.

Just as a reminder that our exploration strategy is focused on really two types of plays, the deep gas play which we have been working on for the past 10 years, including drilling wells that are in general terms between 15,000 and 25,000 feet, drilling to Miocene age sands above the salt well. And then beginning with our acquisition of the new field properties in 2007, we have been pursuing ultra-deep gas plays which again in the shallow waters, not in deep waters, but drilling to deep water type exploration targets below the salt well and these wells typically go at depths beyond 25,000 feet.

Our targets are on the shelf, generally in very shallow waters, but within 500 feet. They are very large targets, similar in size to the targets the industry has been drilling in the deep water, but the physical part of our operations are significantly different from the deep water because of the shallow water location where we are drilling from jack-up rigs and barge rigs and don’t have the technical challenges that the industry faces when it is dealing in deep waters.

We also, by drilling in this area, are typically near existing infrastructure that has been used for historical operations. And so that allows us to bring new discoveries online more quickly and also at less cost than deep water development, even though they are similar size of prospects.

We don’t operate in the deep water. And so accordingly, our exploration activities have not been subject to any of the drilling suspension activities that have been imposed by the Department of The Interior. We are dealing and working on the new regulations and enhanced safety certifications that affect all operations in the Gulf but as we work through those, those reflect the historical practices that our companies have been following in terms of the way we have been drilling things.

We completed the certifications, as I mentioned. Some of the permit processing is taking longer, but we are working through that in a reasonable fashion. Page six just gives some details that describe the differences between the drilling operations that we have and the operations that are required to drill in the deep water. We have been working with regulators. Jim Bob and other members of our team have been working with the regulators as this process unfolded to educate them on the important differences between shallow water and deep water.

We have been pointing out that shallow-water drilling on the shelf has been done successfully and safely for over 50 years, involving drilling of 50,000 wells. Well control is an established science in the shallow water primarily managed by the selection of pipe points and control of mud weight during the drilling process.

Kill weight mud is maintained to the surface in connection whenever wells are temporarily abandoned, thus preventing the well from flowing. The equipment necessary to prevent our stop any uncontrolled flow is, including the blowout preventers, located above water and is easily accessible for testing or repairing whenever that is necessary.

In the unusual situations of where uncontrolled flows are encountered in the shallow water, the location of the blowout preventers allows for access and interventions to seal the well. And as I said, these operations have been done very safely over many years and over a huge number of wells.

So, in addition, in drilling in the shallow water, the targets are almost always natural gas targets, where, in the deep water, it is generally an oil province. So the environmental risk associated with any blowouts are much less in the deep water. And all these points we have been making to the regulators so that we can end up with some reasonable ways of going forward and so far they have seemed to recognize this and provided for ways for us to continue our business plan and our operations that we’ve designed.

Page seven shows in shallow waters, we are able to use jack-up rigs. In very shallow waters, we use barge rigs and the newest distinctions that they are making for the suspension activities are operations involving subsea blowout preventers or floating facilities and none of those are used on any of our operations. And the Department of Interior has been acknowledging the difference between shallow water drilling and deep water drilling as we go forward.

Our second quarter production, we have a slide that we show each quarter that has the location of our producing properties and their flow rates. We averaged, as Kathleen said, 165 million a day. Production in the second quarter was lower because of some unscheduled downtime, maintenance on pipelines and other facilities.

Production from the six wells in the Flatrock field averaged a growth rate of 187 million a day, 35 million net to McMoRan in the second quarter. Below, we are doing recompletion activities and this will be up close to 200 a day gross by the end of the year.

Page nine shows a map of Blueberry Hill. We need to complete wireline logs or log information by wireline or and we are also -- as Jim Bob will talk about, looking to get information from LWD logs to determine the porosity of these sands that we have seen and to get our arms around the potential net pay.

The current depth of the well is in a resistive sands, so we need to drill further to determine its thickness. The wells we drilled in 2009 are located about 3,000 feet north of where this sidetrack well is being drilled. Established hydrocarbons in three different zones below 21,000 feet and of course, this is located in the JB Mountain/Mount Point area where we have the Flatrock field and other discoveries and we are very excited about its prospects. And Jim Bob, do you want to make any comments at this point on where we stand with Blueberry Hill?

Jim Bob Moffett

Richard, what I would like to do is wait and we will look at this on slide 22.

Richard Adkerson

Okay. Good. Okay. In terms of our deep gas exploration program, the second half of the year, in addition to the work we will be doing at Blueberry Hill, we have prospected Eugene Island 26 Boudin. This has a total depth of over 23,000 feet, testing Miocene objectives and has the significant gross on risk potential of 300 Bcf equivalents.

The Hurricane Deep prospect is located south of the Flatrock structure in 12 feet of water at South Marsh Island 217. As we previously reported, the operator of drilling operations at the time encountered an underground flow and a sidetrack well at approximately 18,450 feet last February. This sidetrack well was abandoned.

We now plan to step in and re-drill the well during the second half of this year. And our cost to re-drill the well would be covered under our insurance program. And we will operate the well, targeting a depth of 21,750 feet and looking to test significant Gyro sands encountered in the Hurricane Deep well that we drilled in 2007 and looking at deeper potential. Again, this is a significant prospect with 350 Bcf of equivalents.

The Platte prospect located in Vermillion Parish in Louisiana, near a well we drilled on acreage owned by Exxon back in 2006 that was completed as a commercial well, we call Pecos. It is targeting a depth of 18,700 feet. We will operate the well and plan to drill commencing late this year with a 50% working interest, gross on risk potential of 150 Bcf equivalents.

On the -- in our ultra-deep program, we plan to spud the Lafitte ultra-deep exploratory well in the second half of the year. Information we gain from drilling Blackbeard East and Lafitte will enable us to develop plans for the future operations where we stood with the Blackbeard West, our original well.

As we previously reported, the Blackbeard West well will -- South Timbalier 168 was drilled to right at 33,000 feet in 2008. Our logs indicated four potential hydrocarbon bearing zones that require further evaluation and we have temporarily abandoned the well.

In May 2009, the Bureau of Ocean Energy granted us a geophysical suspension of operations to extend our leases in that area and that will allow us to the value weight whether to drill deeper, drill in an offset location or complete the existing well.

The slide on page 11 has a map of Davy Jones. Previously, we reported that we re-entered an abandoned well bore, began drilling just over a year ago. In February of this year, we reached a depth of 29,000 feet. We saw on wireline logs 200 net pay in multiple zones. We’ve set a production liner.

We have temporarily abandoned waiting completion equipment. And this indication from this well indicate very substantial addition and exploitation development, exploration activity and could make this one of the biggest discoveries that has been seen on the shelf in many years. And Davy Jones was recognized, for example, recently by the oil and gas investors as the best discovery in this past year.

And then, these ultra-deep wells that we are drilling, Davy Jones, Blackbeard and the correlations to the deep water and then into significant production in the Sand section zone shores are redefining this geology landscape below 20,000 feet in the Gulf of Mexico and gives our company tremendous opportunities as we look forward.

With respect to the original Davy Jones well, we have made excellent progress since our last call in terms of completing engineering studies. And we have a team that is working to come up with a development design, equipment design, equipment purchases and so forth. And we are looking to be able to complete and flow test this well in the third quarter of 2011.

The Blackbeard East ultra-deep prospect that we have, we plan to drill about 800 feet more, 600 feet to 800 feet more. But for our next casing point in 19,000 feet, we currently have 13 5/8 inch casing in the hole and plan to set a 11 7/8 inch casing at our next pipe point.

We expect to penetrate the salt well at plus or minus 20,000 feet. We are targeting middle and deep Miocene objectives that were seen below 30,000 feet in our Blackbeard West well, as I mentioned nine miles to the west as well as younger Miocene objectives.

Slide 14 shows charts, cross-sections for the similarities. It shows the similarities of the Blackbeard East and Lafitte ultra-deep prospects. Our models suggest that the perspective sections in the Miocene at Blackbeard East and Lafitte start around 22,000 feet. These perspective sections appear to be more than twice the drilled Miocene section that we saw in the Blackbeard West well in 2008, which is shown on this cross section. The Lafitte well is expected to begin drilling in the second half of 2010, targeting middle and deep Miocene objectives. It is located at Eugene Block 223 in 140 feet of water.

Slide 15 illustrates – Those of you who follow this have seen this before, but shows the ultra-deep focus in the shelf of the Gulf of Mexico and how it relates to the deep water and then its correlation to these sand sections that we’re seeing to be highly productive in years past on shore in the Gulf of Mexico. Our high bids on the March 2010 lease sale were approved by MMS during the second quarter. We picked up 17 new blocks, 75,000 acres. It includes the right for three deep gas prospects and eight ultra-deep prospects.

Slide 16 shows our 2010 outlook. Our updated guidance for production, this year would result in annual average production of 160 million a day with second half at 145 million a day. Our CapEx guidance is unchanged and is always subject to events as they transpire in our exploration and development programs. We have increased our reclamation estimate by $30 million for the year.

The increase is not a reevaluation of the work that we had previously projected, but we are doing more work. We are accelerating some past reclamation work from hurricane damage. And we expect this – some of this cost to be covered by our insurance programs. We are approaching this in a very prudent way to reduce our risk as we go forward from this past damage and from just our general abandonment work.

Slide 17 shows the typical slide, we present to give an indication of our cash flow-generating capacity for our company. The forward price case is down $45 million from our last call because of price changes in production guidance. The current estimate is based on $4.56 gas prices, $77.75 oil prices for the remaining six months of this year and reflects the forward pricing curve. And you can see that based on the foreign pricing curve our EBITDAX would be $230 million and you can see the variation.

Our financial policy remains one of – looking at our balance sheet and maintaining liquidity to enable us to pursue all these exciting activities. Our capital spending is going to be driven by opportunities. We want to commit our capital in a disciplined way using partner financing to access our higher potential opportunities. These are big plays and will require capital and we’ll be looking as to how to deal with that as we go forward.

And with that I like to turn the call over to Jim Bob and look forward to your comments. Jim Bob?

Jim Bob Moffett

Thank you, Richard. Let me just refer to a couple of things, if you could refer back to slide 14 on your visual aids. The important thing about Blackbeard East and Lafitte prospects compared to Blackbeard West is that – As Richard said, we expect to see substantially more section in the Miocene.

If you look on the exhibit on 14 and compare Blackbeard East to Blackbeard West, you will see the amount of orange color that is shown there in the circled area, it really represents the bottom of the salt well. As you’ll note, we penetrate the bottom of the salt well at about 22,000 feet in Blackbeard East, where we penetrated and Blackbeard West is about 28,000 feet. The same thing is true for Lafitte, if we penetrate just below 20,000 feet the Miocene section.

Now, if these geologic models are correct and these large structures are tracking the way Blackbeard West was, what that simply means is, is we have an opportunity to see a number of Miocene sands that were shoved out of the Blackbeard West well and we can start finding pay.

Some of these big structures are trapping as shallow as 20,000 to 22,000 feet which would make a huge difference in the number of net pay that we would have in the wells, just simply because of the expanded section of opportunity. That has a big impact on the play, because whatever you see in Blackbeard East and in Lafitte, is going to also reflect on the new acreage that we just acquired, plus some of our acreage that we were holding on prospects like Captain Blood and Barataria and Barbosa.

So in other words, the Blackbeard West defines some of the Miocene section that is seen across this whole trend, both the Blackbeard East and Lafitte as it adds some capacity to that.

I will also just mention quickly on the Davy Jones offset. One of the things is that we hope to see – The Davy Jones offset as opposed to our initial discovery well there, is we expect to see at about 500 feet high, hopefully, the same sands that we saw in the number one offset. And we are going to have, by virtue of the fact that we’re drilling a bigger hole here than we did in the original Davy Jones well where we deepened an existing well. We hope to be able to get wireline, too, in that hole. It might give us an opportunity to get some reservoir data because of the additional 500 feet in elevation.

And also to really define what the complete section looks like. And as you also remember, recovery would be 500 feet high in the bigger hole. We are going to make an attempt to deepen below it easy of what we are seeing in the original Davy Jones discovery to see if there’s any more Wilcox, below our pays that we had in the Davy Jones number one well.

And most importantly, on the seismic, there’s a definite indicator that there is a substantial amount of missing section, which we believe may be age equivalent to the Cretaceous Tuscaloosa in the onshore play. We’ve mentioned this on several occasions. This could add a significant amount of potential objectives, not only in this Davy Jones number two well but on the entire Davy Jones structure. And of course, all the other plays that we have surrounding is, John Paul Jones to the north, et cetera.

So these were drilling wells that we are drilling are not only going to have an impact on the well itself, but they are going to continue to give us a definition of what the complete section of opportunity is going to be. That is emphasized. We have some slides, what you call reference slides. I’ll just call your attention to a slide. Let me see, I think it’s slide 24. Excuse me. I’m trying get the right slide here for you.

First of all, let’s first take a minute and look at 27. 27 is important because it refers just, as I said, to the trend that we will be playing. You’ll notice that the Blackbeard, Lafitte, wells, they are shown there about in the middle of that cross-section, which we call our Dancing Dragon.

And then we’ve got the Davy Jones registered north of that. You’ll see in the orange is the Miocene of Blackbeard and Lafitte type wells, which are just shots of the Davy Jones well. In the Davy Jones well, you’ll see the section which is shown, is in yellow, is the Tuscaloosa. Of course it projects right back up to the old False River trend.

The reason I want to make sure we recognize how much section of opportunity could be added by the Blackbeard East and the Davy Jones offset by deepening to the Cretaceous, is on page – on slide 28, we always try to point out the obvious. And that is, if you look at this slide 28, you see Blackbeard, Davy Jones are the only two penetrations on a 200 square mile shelf.

And we show, the distances from the big discoveries that have been noted in the deep water Knotty Head which is Miocene, Thunderhorse, which is where we set the whole thing up and getting all of the Big Tiber, Kaskida wells which are Wilcox. So once again, Richard mentioned that there had been 50,000 wells drilled on the shelf, but only two of those have seen pay, which is the Blackbeard, we saw the Miocene pay and Davy Jones, we saw the Wilcox play.

So it’s a frontier area sandwiched in between the developed area that has been going on since the discovery of Thunderhorse in the deep water 10 years ago. And of course, south of the onshore play where you had Wilcox, Tuscaloosa play in North Louisiana.

And remember the Tuscaloosa is a synonym in Texas for the Woodbine, which is the big Cretaceous producer in the historic East Texas field. So you have some very petroliferous units that are sitting there that have never been seen on the shelf before. And that is really why the Blackbeard and Davy Jones well have opened up the shelf by redefining the depth at which those things occurred. We had originally thought they would be much deeper in the section.

So we’ll have a lot of information coming from the Blackbeard East well, which is below 18,000 feet, very quickly. And of course we hope to get that information on Davy Jones on the offset. We’re below 11,000 feet on that well. We talked about Blueberry Hill for a minute. Let’s go back.

Let’s look at slide 22 which is in the reference slides. Slide 22 shows a cross-section across Blueberry Hill. What we’ve tried to do is to once again discuss, why we think this prospect has the big potential that was suggested by the first three wells which were drilled on the left side of the cross-section.

This is a cross-section across the Blueberry prospect. And the important thing is, is those first three wells we drilled that suggested different pay sands and below those sands, which we never were able to drill to, we believe are the JB Mountain Gyro 9 sands and they are shown in orange below that.

In the Central fault block, which is where we are drilling right now, you remember that after we drilled the first three wells, we drilled this number nine well which is shown on this cross-section as the number nine well. But you will notice on the sidetrack on number nine. And what happened was when we went to offset the original three wells, we got tangled up in these – in this disturbed area and went into this big shale mass, which we thought would’ve been a little bit more to the east of us. But as it turned out we got tangled up in it.

So we had to kick the well, the number nine well to the west. And that is the well that is shown in the middle of the slide 22. And what you see crosshatched there are basically three zones of interest the lower latter two being the thickest of the three. And on that situation, we’ve seen on our LWD gamma ray redistributed that could indicate hydrocarbons. We always caution that with these deep wells on the LWD, we don’t have proximity. So when we see these we just give you sections. They can also be either tied or be invaded sands from all oil based mud.

It doesn’t look like that’s what we have here. The significance of the zones that we are in, appear to be resistive and possibly harder to cover there is that they are the same age, approximately, as the zones that we penetrated to the north in the three sidetracks.

That’s indicating, as we suspected, as we drilled the first offset, that there’s a fault. It’s over a 1,000 feet flow which is main fault and we couldn’t see it as clearly as we have to recognize now, because we drill to 24,000 feet, plus or minus and we haven’t seen the Gyroidina bug yet and yet we are getting into these sands that appear to be the beginning of this Gyroidina section.

If that is correct, as you’ll notice there’s a multilayered orange section shown. And we know that JB Mountain to the west and the Flatrock field to the north, how important these sands can be. If you fill them up in terms of their potential flow rate and the thickness gives you a lot of reserves. Of course, this stuff is located in 10 feet of water. As significant as it can be for the Blueberry Hill, if you look at slide 23, you have to look closely.

What slide 23 is, is a whole area known as state track 340 OCS 310 that we’ve been working on for 10 years. Most importantly, any area in the middle which is shown in orange and yellow, if you look on that slide you’ll see Flatrock.

In the northwest corner, we’ve got a circle around the side of Flatrock. Then, you got to the south of that, JB Mountain and then Blueberry Hill. You’ll notice how big those three structures are and we are using the correlation from those wells to put this big sand section on the west line of Blueberry Hill.

So we just have to stay tuned. It is frustrating that we can’t, with these deep wells, drill them quicker or see better seismically some of the big features like the shale mass and these big faults that set up these big traps. It is also important to note that – We mentioned the Boudin play. You’ll notice just at the southeast that it’s on this map.

So any of this area that is proven up, we can go on production quickly with it. It is in 10 to 20 feet of water. You have seen the flow rates that we can get out of the wells like there was at Flatrock. They flow as high as 100 million a day and 2,000 or 3,000 barrels of, usually. So still, a major growth opportunities for us and we control the entire acreage position, along with Chevron and Plains our partner.

And so Blueberry Hill success, if we can improve that the sands are as extensive as they appear to be starting out, just confirm why we need to follow and be sure all of these prospects in this Mini Basin as we call it. Remember each of those sections that you are looking at are these MMS 5,000 acre blocks. So, big broad structures that cover 3,000 to 5,000 acres at depths of 20,000 to 25,000 feet that can immediately be put on production. Big rates and the thick sands can add some big reserves.

So, with that, I know there’s a lot of things we could say about all of the things that have been going on after the BP spill. But you’ve heard so much about that, I am not going to comment on it other than to add to what Richard has said and that is that we have been saying for the last five years that on the shelf where we have the jack-up rigs and the platforms that are attached to the ocean, the Gulf of Mexico floor and we operate in 10 to 150 feet of water.

We are seeking to find the differences in what the rewards can be if we can continue to prove that the deep water type prospects are on the shelf and this play is just starting to bloom as we drill the offsets and the wildcats and the Blackbeard East and Davy Jones area. We would be happy to answer any questions you have about any of those implications.

Deep water versus shallow waters 500 feet or less where once again, you have seen so much of it. I’d rather just answer questions about it. Richard and I can field those as opposed to telling you something that you probably already know. So Richard, with that we can open it up for questions and answer questions about our prospects or any of the other overall implications of what’s going on in the Gulf of Mexico right now.

Richard Adkerson

Thanks, Jim Bob. Operator, let’s go to questions and we look forward to your questions.

Question-and-Answer Session

Operator

(Operator Instructions) Our first question comes from the line of Nicholas Pope with Dahlman Rose.

Nicholas Pope – Dahlman Rose

Good morning guys.

Richard Adkerson

Good morning.

Jim Bob Moffett

Good morning.

Nicholas Pope – Dahlman Rose

I had a couple of quick questions about Blueberry Hill. I guess as you’re drilling this thing, in the success case, what are we looking at in terms of timing for production and also, as we are looking at this cross-section, it seems like the actual pay zones are a little more -- I don’t know if it is compartmentalized than it seemed originally. But what do you think about the potential where we stand right now versus I guess where we were when we started drilling this sidetrack?

Jim Bob Moffett

Well, after finding this fault that separates us from the first two wells, I’ve been cautious, as you know, since we spudded this well. Cautious because as you saw on slide 23, this structure is as big as JB Mountain and almost as big as Flatrock and having found this big shale mass was a complication which set up the play. And so, now that we see that the big shale mass area is a north-south striking entity, it actually is a dam that literally blocks off the west flank of this structure.

I have to be really cautious right now because if we are just in the top of this Gyro section, which is what paleo suggest and if we just really longed, it will go down -- go down deeper. We still got a significant west flank here that hasn’t been defined. Even though, Eugene 25 blocks, if the sand signatures are there and you say, well, Jim what are you talking about, we’ve seen in this Gyro section 2,000 to 3,000 feet of sand at JB Mountain and at Davy Jones and the one 900 foot sand at Flatrock. We have gotten to those based on what we now can understand about the paleo.

We haven’t even seen the Gyroidina bug yet in this sidetrack. So, it’s unfortunate that we don’t have the deeper part of the well there so that I can answer your question more specifically. What I am trying to do is say it’s a huge structure in this Mini Basin. And we know, based on the paleo, that we are sitting right on top of this whole fleet of Gyro sandwich we tried to show you. And you say, well what are we talking about? 2,000 to 3,000 feet of sands, how much of it could fill up with this big shale mass, that was the reason why we got excited about it when we saw the first three wells.

Our job is to find anomalies and actually use anomaly which we seen from our first entry into this area. We are just now starting to understand the sand distribution. So if you can imagine the whole west flank of this structure, it’s over four miles north-south long. You can stack a lot of sand area in there and to answer your questions, it’s 10 feet of water and all of these production facilities exist around here. This stuff that come on production in six months -- six to eight months and so I wish we had the well down and this call was two weeks away.

But that’s -- the timing of these things are that they are. So we will be keeping you up to date on the sands below us. They should be. Could we get any, could we drill off any of the shale mass? That’s what this whole thing is all about. If the big sands are stacked up against us, shale mass with all this west dip we have back into the hole between JB Mountain and Blueberry Hill. As you can see, on slide 23 then all bets are off. The sands could be anywhere from a couple hundred feet to 1,000 feet of sand, stacked up one on the other.

And then, of course if that happens, we only saw the first three sands and the top of Gyroidina on it in the wells to the north. That whole fall blocks to the northwest, we could then go in and deepen it and that’s how we show the additional Gyro Sands below that. So I’m trying to answer your question so that you -- that we call this thing what it is. It is still potentially a very significant deep Miocene structure that’s got the opportunity to stack six, eight plays on top of each other like we did at Flatrock and because of the depth and the pressure of these things and the porosity, we’ve seen what the reservoir performance can be.

Nicholas Pope – Dahlman Rose

Okay. That’s…

Jim Bob Moffett

I hope that lets you see where we are.

Nicholas Pope – Dahlman Rose

Yeah, I know. That’s very helpful. I had one more question just more on the financials. With the reclamation costs they are forecasting with P&A expenditures, I’m trying to figure out how that is going to flow through the financials going forward?

Kathleen Quirk

Nick, this is Kathleen. It’s shown it’s already accrued and so it’s shown on our cash flow statement, you’ll see a line item for it. And then we also expect to receive insurance proceeds for some of that. We’ve got $10 million that we are collecting now and we expect to collect an additional $30 million on top of that, related to our second-half spending.

Nicholas Pope – Dahlman Rose

Okay. That’s all I had. Thanks a lot.

Operator

Our next question comes from the line of Joe Allman with JPMorgan.

Joe Allman – JPMorgan

Great. Thank you. Good morning, everybody.

Richard Adkerson

Good morning, Joe.

Joe Allman – JPMorgan

So, Jim Bob, back to Blueberry Hill. So I mean, the fact that you did find this fairly big fault, does it make this whole structure more compartmentalized and, therefore, it probably is smaller than what you originally thought, but it could still be big? Is that fair to say?

Jim Bob Moffett

When you say compartmentalized, you are exactly right, that is what we tried to show in the cross-section. When we first drilled it, we said that the sands could wrap around the whole west flank. Now what you have is you have two fall blocks at least as opposed to one, but that’s just two compartments as opposed to the whole flank being open and being the same reservoir. The reason why I’m trying to differentiate between compartmentalized and size here, though, is because the thicknesses of that Gyro sand.

In other words, as we have shown on slide 23, if you look at the outline of Blueberry Hill, it covers the better part of the four of those MMS blocks just like Flatrock did. And the reason why we originally thought this thing had the 300 Bcf to 500 Bcf potential was because when we started seeing the Gyro sands production in those first two wells, one of which was over 100 feet thick. We knew that we had this thing trapped up against the big shelled mass and what we’re doing now is apparently fixing to see how much of this section will fill up and what’s important is, essentially, the shale mass is so big it appears to be a shale high that it stands across the whole central part of the structure.

That big dam sitting there along with the west dip down into this sand cline between JB Mountain and Blueberry Hill could give you a significant section, column of hydrocarbons and that is because of the amount of dip you’ve got. And so, as I’ve said before, you have to be so doggone careful when you look at these sands that it would be 200 to 800 feet thick when they are trapped up against something as substantial as this big shale mass. You can load one of those doggone things up.

What I don’t want to do is to sit here today like we were last year and to not tell you that that’s the kind of potential this son of a gun has. And yet we can’t count our chickens before they hatch. So in the shallow trial processing, everybody got used to the bright spots. Unfortunately, these doggone deep plays don’t have bright spots. They have good structural definition, but we can’t see the plays till we get to them.

So I don’t want to repeat myself again but the significance of this sidetrack that we drill. We can see sands now that weren’t in the original nine. And now we see that we -- even though we are 1,000 feet low to the three wells to the north, that we potentially are getting into hydrocarbons. So that means that big default that separates us is traffic and even though it will be two full blocks instead of one, if we get one of these doggone sands strung out against the shale mass, I don’t want to leave the impression that we don’t still have a chance to have a major reserve.

I hope that differentiates the situation that you talk about when you say compartmentalized means smaller than the original potential because the reserves can be put in a 300 to 500 acre area if these dadgum sands turn out to be over 200, 300 feet thick.

Joe Allman – JPMorgan

So Jim Bob, you started seeing high resistivity sands here below 23,000 or longer feet. You are now at 23,500 feet. So has most of that 400 feet -- has most of that shown high resistivity or…?

Jim Bob Moffett

We started seeing the first zone was fairly thin. The next zone was a little thicker and then we are into the bottom of the zone that looks like it is trying to make into a pretty good-size sand, Joe. But I talk all the time about building a Christmas tree where we drill these doggone reservoirs and these sand packages from the top down, but the doggone things are deposits from the bottom up. So it looks like the telltale signs that we always talk about when we think we are getting into some substantial traffic or capacity, the shale’s re-distributes between the sands that we have seen are running an ohm and a half, just almost 2 ohms as opposed to the half ohms material that we saw in this big shale mass, which is telling us that we have lower pressured stands up against the high-pressure shale.

That’s our -- that’s our perfect traffic we keep looking for. So that is what important about what I’ve seen so far in this 400 feet of section that I mentioned. And you just referred to in the press release is the Gyroidina shale we are telling you they share a pressure aggression and generally you can’t get that kind of 23,000, 24,000 feet as we’ve seen at Blackbeard and Davy Jones and Flatrock. You just can’t get those higher utility lower pressured packages unless it’s a big package of sand. That’s what creates -- that’s what gives you the ventilation to keep the pressure from being as high as you would expect to have it if you were just off in a deep water shell.

So that’s what has got our antenna up is the lithic signature of the regression of pressure and it came by high resistivity sales. And then in the sands, we have seen so far they seem to be resistive -- could the darned things be tight? Is there (inaudible)? They could be but the Miocene section, it was saying in the Operc and Gyrodata have been very portion and probably we’re seeing those sands up an ohm. But now we are up there less than half ohms reach maturity.

So I don’t think these darned things are tight. And the only other thing that would give you, used to be recent evasion from your oil-based mud and when you drill at these depths, you always got to have an antenna up to that. So as usual what we are trying to do is keep you informed and as soon as we get this next 400 feet or 500 feet of the section made, we’ll see whether or not the lithic indicators that I talked about, they indicate that we have a substantial sand package.

And unless we cut some sort of a fault or the shale mass that jumps underneath this, everything would tell me that from the -- since we are drilling the stuff from the top down that we are sitting on top of a thicker sand package and it could be another 400 feet thick. It could be another 1,000 feet thick. And it just depends on how much of it is going to be sand versus shale.

Joe Allman – JPMorgan

So Jim Bob, once you get out of this hydrocarbon zone, then you stop and then you run the wireline log. And then at what point do you decide, okay, that’s enough? We are going to develop this? And then how do you develop this thing? Would you just develop this one fault block or would you also develop the other fault block?

Jim Bob Moffett

All of the above, Joe. Remember 10 feet of water and once you know where the darned things are we can drill a straight hole. To get -- if we stack these things, we had three levels in the first three wells. We’ve got eight levels at Flatrock if you remember. And if we start stacking these doggone things on top of each other, then we could pinpoint a couple of wells and drill straight holes to develop those reservoirs.

But it is all going to depend on thickness of the sand and the amount of column that you have that will decide the earliest extent of these sands if they hang in there against your straight material mass.

So every 100 acres of 100 foot sand as you know, would be pressured as 20 Bcf and as we have seen at Flatrock, a couple of Flatrock wells have already produced 50 Bcf each. So can’t see the water, you view a lot of latitude as to how you can develop these fields.

Joe Allman – JPMorgan

And just lastly, Jim Bob, let’s just say this is not successful what you’ve found so far in this small block, let’s just say it’s tight. Do you have enough in the other fall block to actually do a development even though it would be smaller?

Jim Bob Moffett

Well, depending on what we see in this well is we tried to show on slide 22 those orange zones you see are indicative of the fact that we knew on the first three wells that we hadn’t seen the lower part of the Gyroidina cycle, which we can call it the JB Mountain to the west and to the Tom Sauk well to the north. But we -- on our first attempt to get to drill an offset we figured we would go to the south and get high not realizing this big, big wells. As we define these two segments as you referred to compartments that we would go back in and drill deeper in the North Flatrock to do up the sands that were already there and see how many sands would fill up below the three sands that we had seen.

In other words, on the on the presalt frac drilling in the fault blocks they’ve shown on the left side of this deal, we will pay when we stopped the wells in all three cases. Because when we started drilling those wells as you remember, we weren’t sure just exactly what depth of sands were going to be at because the original wells drilled here in 2005 as shown on the far right of the cross section defined the original big shale mass. Then as we drill these other wells at Flatrock and JB Mountain, we knew that these big sands had to be deposited off the flank of this big structure because it was just how the thing is unfolding.

So, I know, that the time -- a year’s time seems like a long time to that we ought to know more about this field. But as I reminded myself and you guys the last time we talked about this, it took us five wells to finally hit the sweet spot at Flatrock. Because you have not only structure which is always in math beside me, which gives you these big, big buried highs, but you’ve got the stratigraphic implications, which were clearly the reason why it took us a few wells to get the sweet spot to find at Flatrock and that’s where we are going through right now, is it’s almost like to find the flank of a (inaudible) because this serial mass is so big.

But the awards if the sand package continues and has these big, thick high-pressured sands that had the kind of porosity and permeability we had at JB Mountain and Flatrock, which we expect them to be, as we said the flow rates of 50 to 100 million a day in 10 feet of water. So we are more opportunistic and with all the existing infrastructure we can get them on production quickly, same old story. We just had to decide exactly what the whole scenario is going to be.

Joe Allman – JPMorgan

That’s very helpful, Jim. I’ve got some more but I’ll get back in the queue. Thank you, Jim.

Operator

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

Noel Parks – Ladenburg Thalmann

Good morning.

Jim Bob Moffett

Good morning, Noel.

Kathleen Quirk

Good morning, Noel.

Noel Parks – Ladenburg Thalmann

A couple of things. Looking at the slide 22 and the current sidetrack that you’re drilling and compared to the three other wells from last year, is there the possibility of still more complexity, another fault between the current well and the wells from the past? And just trying to get a sense of how many twist and turns there still might be before you have the whole area defined?

Jim Bob Moffett

Good question and so I’m very, very glad to (inaudible) those, but let me just say again. Complexity, meaning could there be another fault to the south of here that would define how far south this ongoing position is there east west cross section? It sort of twist and turns back to the north of that to the original three wells. It’s not going to be as complex as the salt dome, no because the salt dome on geophysics, you can see clearly, as you get this real, highly productive beds and you get what we called radio fault.

They come off in plenty of type dome. This shale mass doesn’t appear to have been placement type structure. It appears to be a big mound receding on the sea floor when these big gyro sands stream enter this mini basin and they’ve been deposited almost like the sand around sand dune, as the water deposits them much like wind would do on a big sand dune in earlier deposits.

So that’s why you’re not going to have the so called radio faults that almost looks like a spider’s leg after some of these big salt domes that have so prolific in Louisiana. This place appears to be the faults that were now identified, appear to be part of a big regional setoff the east, west side that we talk about Blue instead of Flatrock.

So I don’t expect this thing to be spread as you get away from the shale. We try to show that the first offset that we drilled which was unfortunate and then we got as close to the shale last time to go up dip of the first three wells, but right along the phase of that shale zone, will you have these big sands dune lapped around the big shale, how you get some funny looking disturb zone, but as you get down into the (inaudible) and get away from the shale mass the thing that doesn’t look busted up, that’s why we couldn’t even see the first big fault. But now you have to math between the first two wells and this was just because of the depth that you see in equivalent (inaudible) of the outer section. So is it more complex than just a big sweeping one reservoir around the whole flank of this 3 to 5 mile deep here? Yes. Is this best way? I don’t know, don’t think so.

Noel Parks – Ladenburg Thalmann

Okay. Great. And just looking back over the drilling of the new Davy Jones offset and also of Blackbeard East, how have those sort of gone according to your expectations of how quickly you get those down? And could you just catch us up on any new complications, the cancellations, et cetera, that might have happened since the last quarter?

Jim Bob Moffett

Are you talking about on the drilling these wells specifically?

Noel Parks – Ladenburg Thalmann

Yes.

Jim Bob Moffett

It all that as we said before. You have to be patient when you’re drilling the zone above the salt weld because you have set these multiple things in a pipe in order to have a big enough whole size once you get below the salt weld. But and so that’s painful to have the patience to drill that first 15,000 to 20,000 feet a section, but you have to set these concentric things, which is what we’ve done. That compared to some of the deep wells that would be drilled in the deepwater, for instance, they have to do the same thing out there. So, we haven’t really run into any surprises. It just takes, that’s why we got these big rigs – these 2 million sand head blows. So, we can set that big 20-inch, which in this case are trying to get it to salt weld and have big enough forward to get to the wireline logs and things that we would hope to get and run big enough casing to take care of these high flow rate wells we are expecting.

So, once we get a couple of these all the things down and completed and can consolidate as we hope to the flow rates, et cetera, then the other wells will start and it also like we have such a long period of time between the time that we drill the first well and drill the offset. So, what we’re really hoping to find out on this Davy Jones 2 for instance, which we in those 30 to 45 days, we should start to make a lot of progress. Once we get those big pipe set, it takes a lot of load in drill, sort of, of sediments when you drill at 24-inch only it does drill a 10-inch hole, just a matter of finish.

So, we’ve gotten past. We’ve got the big pipe set at Davy Jones. We got the big pipe set at Lafitte. So, we ought to start to make some good progress now and does do this salt weld, hopefully you will see some of these goodies that we’ve set up to find. And as I’ve said on numerous occasions, we hope to give some for us the information that would give us a more handle on what kind of flow rates we can extract from Davy Jones, but really painfully is aware, these deeper zones that have got these pressures, we see what the flow rates of the BP well are and of course the people are starting to understand the dynamics of these reservoirs. It’s unfortunate this one got away from, but if you take the sand and put into these depths you have this pressure. It gives you this tremendous velocity and it should be a precursor for what we can expect to find because they are flowing oil at that rate, natural gas is going to flow at a much higher rate just because of the difference in the costing of the hydrocarbon.

We’ve been talking about that from the inception and I think everybody now has seen further all of the public data there has been then probably if you look at the gamma ray and resistivity on that log that they’ve published on the BP well, you look at our logs at Davy Jones as we say, Davy Jones things look like Miocene, they don’t look like Wilcox, we said that from the beginning and they’re going to flow like the Miocene well and that’s what we are all trying to find out. But remember these log entries don’t know what the age of the formations are. All they do is to indicate what the rock quality is.

So the implications of people finding out the velocity of some of these deep pressure reservoirs, which is if they’re properly completed and produced like 99.9% of them are. This is just a reminder of the velocities you can get on each of these structures. So we got all the indicators. We got big structures covering over 20,000 acres. We got big columns possibly because of the amount of structure relief and the dynamics of the pressured section, for of course first big column is what we’re all economically looking for.

Noel Parks – Ladenburg Thalmann

Okay. And just real quick the Davy Jones engineering studies that you’ve completed. I know you’ve commented in the past that while some people may be skeptical about your ability to actually produce that at such a great depth. You’ve pointed to some other real deep wells elsewhere in the Gulf. So the engineering studies have they increased your confidence as far as just the mechanical feasibility of actually getting Davy Jones to produce?

Jim Bob Moffett

We are really completely confident that this -- that the equipment we needed – we had thought that we might try to float this time as we said to you by giving -- trying to get permitted some 20,000 ton equipment and see if we get to float this and after the new regulations have been issued because of this BP situation, we just come to the conclusion that we’ll just go ahead and bundle the thing up and at the same time, we are bundling it up. We’ll have this new information from the Davy Jones #2.

Hopefully, we will know that the sands are in this #2 well, which is one of the things we are trying to prove 2.5 miles away, prove that the sheet sands cover the whole structure, which gives you the confidence about the early stand of these sands and of course, we hope to get some additional porosity information on sands. If we can call the things like as we hope to do, whatever porosity information we can get out of this bigger hole that we are drilling and then the #2 well will give us a lot more confidence about predicting the flow rates in the first sand.

So that’s the kind of stuff we are going to learn. As I said repeatedly, you got one Wilcox well in the shelf, we have to call it 200 miles to the south. It will be a tremendous advantage for us to have another well into that Wilcox on the same structure 2.5 miles away to give us the additional information that we need to get that predictability. But, and I’m just trying to, hopefully, (inaudible) describe the dynamics of these deep reservoirs, which has been hopefully exhibited by the flow rates you see from now is BP oil – these deep sands should have tremendous producibility.

Noel Parks – Ladenburg Thalmann

Okay. Thanks a lot.

Operator

Our next question comes from the line of Jason Wangler with Wunderlich Securities.

Jason Wangler – Wunderlich Securities

Good morning, guys. I just had two quick questions. One, on -- for the rigs that are going to be drilling out in the Gulf for these wells coming up. I had noticed that a couple of them are coming up contract pretty soon. Are you starting to talk to the operator or should be the rig owners and seeing if you can read those contracts?

Jim Bob Moffett

Well, the rigs we currently have a location are two drilling rigs are under contractors and we have a third one that’s going to be coming to us. So to answer your question, as we’ve said, we’ve got the jack-up rigs that have this big [load] tied up and there is two more coming out of the shipyard that will be available.

Obviously, this whole shelf play on the, obviously, the play is going to be significant to the utilization of those jack-up rigs. That’s why we’ve said that we want to tie them up, make sure we have the equipment to drill really deep wells. So the more drilling got lot of publicity for the floaters, read those in prior for the jack-up rig. I hope that, is that…

Jason Wangler – Wunderlich Securities

Okay. And then, just for the couple of wells that you’re going to drill too later this year, have you gotten permits for any of those yet or do you still have to go through that process?

Jim Bob Moffett

The wells we’re drilling, of course, at Blackbeard East and Davy Jones are permitted, Lafitte we expect to get a permit on based on the regulation we see them, we don’t see any issues that the MMS or whatever, the new ocean energy supervisory group, whatever we’re going to call it. There is no indication that the drilling jack-ups in shallow than 500 feet of water are not going to be permitted. So, we expect all that to continue to flow on our operations.

Jason Wangler – Wunderlich Securities

Great. Thanks, guys.

Operator

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

Duane Grubert – Susquehanna Financial Group

Yeah, Jim Bob, when we look at the Davy Jones well and the Blackbeard East, I wonder if you would just comment a little bit about the difference in risks between the two, because from your materials and I think from the way most people in Wall Street look at it, it looks to us like Davy Jones will be the higher probability of success. It’s not going to be easy but it looks like an offset well of something that’s pretty simply mapped, whereas the Blackbeard well looks a little more complex. Am I right in thinking that?

Jim Bob Moffett

Absolutely, you’re right on target, Duane. The Davy Jones is a direct offset to our first well and is on the same big structure that you’ve seen the different cross-sections on, so we’ve already proved that the structure at Davy Jones is a trapping structure. What’s does that mean?

Well, these structures are as big as they are, as you heard me say, if you go back and look onshore and the structure that we’re drilling at 30s, 40s, 50s and 60s, all these big 20,000, 30,000 acre structures in Texas and Louisiana we’re drilling, very dam few of them didn’t trap on multiple layers. Most of them, 10 to 15 or 20 sands just because of the vertical columns, which you have on the darn thing and of course, we’ve seen the same thing on deepwater, those new discoveries out there, so they may have 3,000, 4,000 feet of column.

So, since we’re going up deep on seismic at least to the Davy Jones well, you’re right on target, it’s a development well. In oilfield lingo, we always call the first well on every prospect a wildcat. We generally call the second well a confirmation well. And of course, depending on what kind of area you’re drilling in and if it’s new frontier, even though we’re underneath a group of wells, 15,000 wells have been drilled in the shallow formations. This is a frontier because there’s no well within 100 miles of this.

So, the confirmation well you’re talking about at Davy Jones is called that because it is on the same structure that has now got indications of hydrocarbons and porosity. In other words, if the first Davy Jones well had been drilled and seen no sands in this big mound, 20,000 or 30,000 acres would have been barren of sands and just a big shale plug then we wouldn’t have had a discovery. We’d just have found a big mountain of shale which says we got layered sands which look like sheet sands. We believe that they will cover all of this structure.

But, that’s what the confirmation well is trying to prove. So, we’ve proved the age of the structure by drilling and that’s why the thing got so much publicity. We didn’t know what depth the Wilcox was going to be found on these shelves. 10 years ago, we would have thought 50,000 feet, but with the new data we had from the deepwater and time the seismic all the way back on to the shelf, we predicted within 200 feet to top of the Wilcox, which we found, as you remember at 26,000 feet.

So we proved that the section was the wonder of opportunity was at least 28,000 feet shallower than it had been originally thought of by geologists, including me, 10 years ago, that’s why we say we’ll redefine the terrain. So, the second well on Davy Jones, we don’t have to worry about whether the Wilcox is it 26,000 feet or 40,000 feet, we’ve already proven that and we’ve already got indication of hydrocarbons. the Blackbeard East – Blackbeard East is an offset to Blackbeard West, nine miles away on a separate structure.

So, as you have correctly said, it’s got a higher risk because we have to prove two things. Like to prove number one that what appears to be a big full way closure at Blackbeard, even though it looks just like Blackbeard West and the other sources we’ve had does it trap hydrocarbons.

In other words, it should be a big high and be better? We don’t think so, because of the Miocene sands in the deepwater and the sands we’ve seen in Blackbeard West, where there is additional section to see because of the higher elevation of the salt weld where we start to get in the Miocene 22,000 feet. We think we’ve got a great window of opportunity, but could we see a whole series of Miocene sands that are developed in weld on this full enclosure? That’s always possible, but that’s why there is more risk in the Blackbeard East because it’s a new structure on the same trend as opposed to the direct outset that we just described with Davy Jones.

So, I’ve kind of said in more words than you did how you risk the size, but that’s the comparable analysis of risk that I would give you. And of course, remember, every well we drilled out on the shale, since it’s only been two penetrations on this 200 square mile area, we’ll make the next structures that are quite less risky for us and the thickness of the sands will be better defined in each one of these structures. We’ve got about 15 of these big structures now identified and controlled. So the risk on each of these wild cats – We have drilled one wild cat at Blackbeard West and one at Davy Jones, 70 miles apart.

Every structure out in the deepwater, all of these big structures, I don’t think there’s more than maybe one out of 40 that haven’t had multiple hydrocarbons, just like the big features that we talked about that had been re-launch over in the 30s and 40s and 50s and 60s. That’s what we’re comparing this new trend to that we basically have on earth by the drilling of the Blackbeard West and the Davy Jones well.

So, each of these prospects, each of the wild cats we’re getting less risky, if we have three – In fact when he says hydrocarbons and then Lafitte has hydrocarbons along with Blackbeard West and Davy Jones, they will start to see that the risk of these new structures been hydrocarbon bearing will go down significantly. So, that’s why the risk profile of the whole shale play is going to continue to go down swiftly as we approve that. In fact, it is a direct analogue to the deep play that’s being going on since the discovery of Thunder Horse 10 years ago.

Duane Grubert – Susquehanna Financial Group

That’s a perfect answer. Now, kind of related to that, one of your partners, Energy XXI has a June 30 fiscal year end, has to do a – end of fiscal year reserves support. We assume they are going to use a third party. Given that the risk on Davy Jones, in particular, seems to be modest. What do you think the probability is that of third party would assign some proved reservoirs prior to having a flow test on Davy Jones?

Jim Bob Moffett

If a big hole we’re drilling, remember in the Davy Jones well where we entered, we deepened a well just to save 50 million bucks, which was above what we saved. By doing that, we drilled out of smaller casing than we would have liked to have to get to this salt weld and because of that we ended up with a road with a small borehole, six and a quarter inch borehole.

So if you could imagine, six-inch play sitting in front of you on your table, imagine trying to operate in that dam thing, the hole 20,000 feet deep to get these wireline tools and drill pipe assisted tools, where you’ve got the possibility of formation test and MDTs and then I’ll called or some rotary cores, et cetera, to let you see the reservoir data.

What we need on this diagram, these new wells is we need a flow test and some more information to verify the right quality. This was like you say that we have already made three discoveries out here and this was our fourth big structure we were drilling and we’d already tested the offset structures.

The third party engineers will already give you reserves at Davy Jones, but because we don’t have a direct analog, it’s closer than 100 miles by SEC definition, these guys needed – The third party engineers need an analog, which essentially don’t have flow capacity data on the direct offsets. We can’t use even though the flow test at jack, which is the big well and the deepwater that was tested by Chevron, that’s a world-class well because it’s the only thing 200 miles away.

So all we’re lacking, low characters as you say we’re seeing so far would indicate that we have sands with higher gas saturation. As I hopefully described a while ago, when I was comparing this to the flow rates for sand, at the BP well these deep wells have already going to have some real dynamics to have lasting flow rates.

That’s what we’re waiting for, Energy XXI and Plains and our self and Moncrief, the MPEH were all, we just need to get that one additional bit of information on what the rock probably is and in the early strength of the reserves will be assigned. And that’s how we’ve could come up with our original estimates about the Tcfs, because assuming that the Davy Jones’s offset proves that the sands do have some lateral continuity and with the size of the structure all we have to do is do some simple acre, foot calculations.

If you take 200 feet and put them over 20,000 acres, you come up with your acre feet and then the recovery factor you can start by sand of 1 million per acre foot, which should be the conservative side because of the pressures. But if you just use 1 million per acre foot, that’s where we’ve come up with these original estimates. So we’re just saying is multi-Tcf, if the sands cover the whole structure. So I don’t want to go on and on and on, but I hope that gives you an answer to what is going to take to have a third party verify the potential of these structures.

Duane Grubert – Susquehanna Financial Group

Yeah. That is very helpful. And then finally, in terms of the timing of the Davy Jones number 2 completion, in order for you and your partners to capture the cycle time advantage that you talk about having in the shallow water well.

Do you think we’re going to see the partnership be in favor of procuring completion equipment on a well before you get it down? So the best thing I’m saying, do you have a standardized well design that you think would work in the next few wells that you would go ahead and order equipment on early to avoid this equipment procurement away?

Jim Bob Moffett

You got it. You got it figured out. I completely agree with you that all of the research and information has been done since the inception of the original well that was drilled at Blackbeard West. Before that well was drilled, as you might imagine, that consortium of people that drilled it went through the whole design on how they would have completed that well had they been successful in drilling it.

We took over the Newfield position and all of that information that was owned by Newfield as a result of the consortium’s work. We took that and took it to another level once we got the Blackbeard well and now that Davy Jones well is drilled in time, the Metallurgy on the production, tieback string is in the tubing and the well hit blowout preventer and the tubing to run.

All of that’s now gone through ad nauseam, the scrutiny of all the metallurgical engineers and other people that did involve in these completions. And fortunately, if you go to Mobile Bay, the big Exxon field, some of the same pressures and temperatures were similar when those wells were float -- completed, excuse me.

And of course, they had all floated, some of them 75 to 125 million a day. So you’ve got an analog, although it’s different age. The reservoir parameters and the pressures and temperatures were similar. So the metallurgy that we used over there had been used as a server and analog to enhance the ability to design this stuff. And of course, the people that drilled the original Lafitte well actually were the operators of the Mobile Bay field that had all these high pressure, high flow, high temperature flow wells.

I think that’s about almost 20-year old field. So, although we’re having to go a long way in this Gulf of Mexico to live for analogs, the depths of the well is no issue because the wells have been completed at Thunder Horse and Knotty Head and all of this stuff to the south have all been below 30,000 feet. The pressures are different out there and the temperature is different because of the water and salt canopy out there.

But as far as the depth and the integrity of the pipe, as far as temperature, strength, et cetera, that’s all been defined. So, when we get to the point of having cookie cutter type of things on the shelf to complete these wells, absolutely, because if we’re right about these structures just as you’ve seen when you talk about in the analogs that the old structures that have been drilled to the north, you take right into vicinity of Davy Jones, the so-called Tiger Shoal for you which is producing from 8,600 feet down to 12,000 feet had 200 wells drilled in it.

200 wells on one structure, Mound Point had 200 well drilled on it and that’s because of the fact that you had 16 different productive layers that over the last 40 years have produced about 6 Tcf combined from those two fields that are completed between, let’s say, 8,000 and 12,000 feet. And they said just down there on top of us. So all we’ve done is to just find -- compare to the archaeology to find the old town under a historic new town and you wonder why they were built on top of each other is always location, location, location.

As we’ve said, first you drill the shallow structures in the 30s, 40s, 50s and 60s, then we run deeper, got below pressure in the Gulf Coast and then found the deepwater and now we’ve got this subsalt play. So, this is like peeling an onion and find that the onion layers have similar characteristics in terms of the shape and symmetry of these big trends in the Miocene, in the Wilcox and Tuscaloosa.

So we’ve got a lot of analogs in this basin. It’s not like we’re drilling in the middle of a new continent that doesn’t have any history. So all of these tricky cutter type of thinking that you’re talking about, so that when we get enough information to know what the offsets are like, we’ll rollout and that’s going to be the play there.

And of course, as you do that, we will start to cut our cost. Some of the things we learned from drilling these initial wells, et cetera, et cetera, that’s the big opportunity here because these structures are so big and have set up -- basically identified a whole trend that’s 100 miles wide.

Duane Grubert – Susquehanna Financial Group

Very good. Thank you, Jim Bob.

Operator

Our next question comes from Eric Anderson with Hartford Financial.

Eric Anderson – Hartford Financial

Good morning. I’d like to follow-up just a little bit on Duane’s last question. Does that therefore suggest that you may see the actual production of Davy Jones 1 and 2 at very similar timeframes?

Jim Bob Moffett

Absolutely. That’s exactly where we’re headed and once again it’s because we are in 20 feet of water. So the facility that exist in the area that’s the first place we’ll go, with the first step for wells and depending on what we find out about the second well. It will open up the next four or five development wells. And we’ll start going toward our facility of our own because to build a facility that’s going to be in 20 feet of water and attached to the Gulf of Mexico floor, we’ve got 50 years expansion there. And all we talk about is just production facility that handles the pressured section. And this is out of those things that’s well known because whether you design a separator for a well, it’s got 12,000 pounds of flowing pressure, like some of the wells that Flatrock has, whether you’re going to have 20,000 pounds of flowing pressure, it’s all incremental just like going from wells that we drilled early on in the normal pressured section had flowing pressures of 2,000 to 5,000 pound.

So, all you do is you just increase the thickness use of steel and but the production facility themselves will just be similar to the stuff that’s been used out there ever since we’ve found the first geo-pressured production in the Gulf of Mexico. And of course, you got to look at the history, Old Ocean field for instance, the field that made the [Colin] family, was one of the first wells drilled under pressure and that’s something going back in the 30s -- 30s and 40s.

And there was a revelation then because nobody had ever seen high pressure completion. And at that point, pressure started around 8,000 feet and it opened up the whole geo-pressured play that took place all across Texas and Louisiana, Hollywood Sands, the Gyroidina sands, that covered the whole west side of Louisiana and Hollywood to the Central Park of Louisiana. They were big new opportunities because all of a sudden you had wells with 12,000 to 15,000 flowing pressure.

So, as I said, the big deal is always a moment away is the best analog in the Gulf of Mexico. So, no question, the cookie-cutter idea will unfold and that’s why the first two wells of Davy Jones and hopefully, the wells that we complete to the south in the Miocene trend, Blackbeard East and West through there will all have the same timelines.

Eric Anderson – Hartford Financial

When you get into the sort of the low 20s over Blackbeard East, what’s the likelihood that you may find some condensate as opposed to just dry gas?

Jim Bob Moffett

Well, anything below 20,000 feet is going to be more or less dry gas now. The Gyrodata and JB Mountain flowed at 100 barrels a million for instance and that was at 19,000 feet. So between 20,000 and 25,000, you can have 20 to 50 barrels a million and of course, that’s significant and Flatrock, if you recall, which was between 15,000 and 18,000, at Flatrock, some of the wells there tested 100 million in May with 300,000 barrels of condensate, which had like a lot of oil, but that was 30 barrels a million.

So, we -- just based on the chemistry of the gas, at those temperatures and pressures below 20,000 feet, we would expect that maybe at 20 barrel of condensate per million might be an average down to 25,000 feet. And as you go below 25,000 feet, the gas is going to get dry and so it will be almost 100% high pressure gas.

Eric Anderson – Hartford Financial

Okay. And lastly after Lafitte, have you decided which of your other 15 prospects would sort of be next in line for wild cutting?

Jim Bob Moffett

Well, I’ll tell you it’s kind of like -- the rest of the prospects, because the first big ones are identified and there is first swamp of place that we controlled, look alike they’re all big -- they’ve got big closures. So Captain Blood, St. Paul Jones, Barataria, Drake, any of these prospects that you see listed on our list, we didn’t buy any thing that wasn’t a primary structure.

So if we’re lucky enough to prove that the deep big structures as they are in the deepwater and the shallow features are onshore are all going to trap in multiple horizons, then you can just start to pick and choose which one you want to go to. Like I say Captain Blood, which is sitting on trend with Blackbeard East and Blackbeard West and Calico Jack on the east side, if you see these structures, they are all big mountains. And there is no 1,000 acre closures, these are all 15,000 to 20,000 acres closures.

So we’ve only identified the mountain well in [paid in impression] to the hills and the hills are probably very productive just like they’ve been in other trends when you get to the secondary structures. So since you got a group of primary structures, they will all start to be right about the same way. So my -- the biggest and most important part of that is that they don’t find the window of opportunity as to where it’s going to be Miocene or Wilcox and/or Tuscaloosa.

So as I’ve said repeatedly, you look at the Wilcox sand all across Texas and Louisiana and the Tuscaloosa wood mine across Texas. And in the big Miocene production from Texas and Louisiana, you’re talking about three usually petroliferous zones and a proven basin, pretty interesting opportunity.

Eric Anderson – Hartford Financial

Are there any lease considerations that we plan to deciding where it could go versus one place versus the other in terms of length of time left on the lease?

Jim Bob Moffett

Most of the leases that we just bought, of course, were all brand new. So those aren’t going to be complicated. We do have some SOOs, where we’ve had leases that had been extended because of the geophysical and drilling that we are doing. So, that would have some impact on it.

But Frankly, since all the structures, as I say, are primary structures, we would go to those but we’ve been focusing on those, Blackbeard East, for instance and Lafitte were two that needed to be drilled because of the lease situation. But most of the rest of the stuff, frankly, we got -- we are in the primary term of the leases.

Eric Anderson – Hartford Financial

Thanks very much for taking the call.

Jim Bob Moffett

Yes, sir.

Operator

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

Richard Tullis – Capital One Southcoast

Hey, good morning.

Richard Adkerson

Good morning, Richard.

Richard Tullis – Capital One Southcoast

Just looking at the second half year production real quick. What do you -- how do you see the split-out between delays related to pipeline facility issues versus the development delays?

Jim Bob Moffett

Well, the biggest thing is recompletion of a couple of these big wells at Flatrock, for instance, the #29 well in the big sand because of the 100 million a day flow rates we’ve already produced 50 Bcf from it and the water moved up and hit the bottom of those spuds. So we are coming up to the next level of sand, which is a big sand that we don’t even have a completion in. So, that well will go from zero back up to 75 or 100 million a day and we’ve got the 230 well, which also has produced, I guess, about 30 or 35 Bcf out of the Operc. We’ve got another Operc sand to come up to and then it’s got the big sand in it above the Operc.

So, that’s the kind of things you are going to see happening in the second half. Those two wells alone will have a big impact on getting us back over 200 million a day at Flatrock. The rest of the things are just simply delays because of third parties. Some of the pipeline issues that we suffered back in the hurricane. Some years ago those issues are just didn’t worked out. So, as you can see from the number of properties that we have producing, there is lot of situations. Main pass we just shut in, makes a couple of thousand barrels oil a day for over a month because one of the wells that we were using to as the gas, these some of the wells were shut in because of the rough weather the Chevron was drilling offset.

So just stuff like that is frustrating and of course when you have a tropical storm, the hurricane both are just lead to and just delays and of course all of the new regulations that you continue to hear about, which don’t impact us other than just the paperwork of verifying that all the things we asked for, we’ve been doing for the last 25 years anyway.

Richard Tullis – Capital One Southcoast

Sure.

Jim Bob Moffett

But, other than that, it’s just typical pipeline, third-party delays that we hope we can work to.

Richard Tullis – Capital One Southcoast

Okay.

Jim Bob Moffett

And of course, hopefully we spent so much time on our expanding, hopefully we start to get some of these cookies that are -- wells with these deep wells that we’re drilling coming on, whether it would be, finally getting this Blueberry Field sorted out and get ourselves a couple of three completions there, that can quickly come on line. And then hopefully, start to see some of the fields that should come out of deep sub-salt play and in the next year we’ll start to get some development plans that will show you a build up of productions from all this money we spent, trying to tie up the deep play.

Richard Tullis – Capital One Southcoast

Okay. What’s Flatrock producing currently?

Jim Bob Moffett

It’s good question. It’s about a 187 million a day, just under 200 million a day.

Richard Tullis – Capital One Southcoast

Okay. So when you get the, say the number, I guess, it was the 29, the first well you…

Jim Bob Moffett

I’m wrong. Maybe about 170 with the writing on the deep reservoir, excuse me over there.

Richard Tullis – Capital One Southcoast

So when you get these two wells recompleted, you had mentioned the production back up to 200 a day or so. You’re probably looking at – it could be higher than that, I’m guessing?

Jim Bob Moffett

Say that last word again.

Richard Tullis – Capital One Southcoast

What do you expect Flatrock to get up to with the recompletions at those two wells you referenced?

Jim Bob Moffett

Well, both those wells, what I’m basically characterized (inaudible) 70 to 75 million a day, which will be the 29 recompletion and the 230 well depending on they’ll probably go to the Operc sand as an Operc sand. It’s between us and the big sand, that Operc sand may produce 10 to 20 million a day and then as I say, the big sand in the 230 well is up above that. So that will be on a recompletion.

And then, of course, we’ve got the 228 well that’s got an Operc sand that we’ve still got on production at about 20 million a day that’s making water, that’s in the Operc. The big sand, the 100 million -- 75 to 100 million sand is in that well in a high position and it will come up in it.

Richard Tullis – Capital One Southcoast

Okay.

Jim Bob Moffett

So…

Richard Tullis – Capital One Southcoast

And then…

Jim Bob Moffett

… it’s sort of a stair step when you have these multiple plays, you can’t shut them off until you have below their economic level because you can’t get back to them so you just have to sort of go from the bottom up. So you see a wobble in the production ratios of these things. So because it flows so with these high rates, like I say, the 229 that we recompleted and produced 50 Bcf in about a year and a half. So pretty damn prolific well.

Richard Tullis – Capital One Southcoast

And then.

Kathleen Quirk

Rich, this is Kathleen. Just to clarify, we average 187 million a day in the second quarter and the current rates are in the 160 million range.

Richard Tullis – Capital One Southcoast

Okay. And of that…

Kathleen Quirk

And we ramp back up to the 200 plus range.

Jim Bob Moffett

By the end of Q.

Richard Tullis – Capital One Southcoast

The -- of the 160, the number 29 wells producing zero, is that correct?

Jim Bob Moffett

That’s correct. It got watered out.

Richard Tullis – Capital One Southcoast

Okay. Okay. Very good. And then, I guess, just kind of big picture, Jim Bob, just drawing on your experience in the Gulf over these years, I mean, how do you see the drilling moratorium playing out? Just the new regulations and the impact on insurance costs and just the whole landscape?

Jim Bob Moffett

Well, okay, let me see if I can summarize that. First of all, there has been so much information on the BP thing. We’ve had the testimony of CEOs, it’s clear that there is some issues as to how the well was drilled and operated. I’m not going to spend a lot of time on that other than to say, clearly, I’m sure everybody, including BP would go back and do things differently than they did.

I’ve seen this thing compared to all kinds of deals. Some people are calling it the Chernobyl of the oil and gas business and of course, that’s an interesting comparison because once Chernobyl took place, you haven’t had an accident in the nuclear basin similar to that in 34 years. So with the regulatory issues that are being dealt with and you’ve seen on the shelf, we’ve been operating that there for 40 years.

And the containment of a spill and whether that would be because of production facility damaged in a hurricane or some a well out of control, we do five drills around here all the time that the MMS basically conduct on the shelf where you get a phone call and people say this is war games and your Platform A has got a spill and you have to take all this equipment and deploy it. And we can contain a spill around these wells on the shelf immediately because all the equipment is there.

The blowout preventers that everybody talks about -- they are going through some additional scrutiny and we’ve actually had to do some additional actual tests and prove that these rams, these break up series of rams you have can sever the pipe. We’ve had to recently go back to the lab and even on these new rigs demonstrate that you can actually sever a 5-inch drill pipe a 6 and 5-inch drill pipe, all of which has been done.

So there’s so much of that that’s going to take place. But the fact is the cap that’s now on the well, if you say what should have happened, since you’ve had 5,000 wells drilled out there, probably that cap should have been sitting on the shelf or you can use a computer and design what you would do to a damaged tree subsea. But that’s spilt milk, I can assure you, at least in my opinion, that those caps will be designed because all those subsea completions, it’s not like every one of them is unique. The stacks may have some different dimensions but since we are not deepwater experts, I won’t try to be a deepwater expert.

But I can tell you that what’s been learned from this incident is that the equipment that’s been experimented with over the last 87 days, three months that won’t ever happen again because they’re going to have the stuff on the shelf before everybody goes back to work. So that if you’ve got a problem you go out there and put the right cap on the first time instead of experimenting.

But, the revenues from the deepwater or from the royalties period in the Gulf of Mexico, I don’t know if it’s $10 or $12 billion a year, but it’s a revenue source for the government, the second only to probably the IRS collections. And you’ve got future bonus proves that come in and depending on the activity and the new exploration, just since deepwater has been discovered. I don’t know how many billions of dollars have flowed in to the government from these bonuses. And what will happen with this new trend that we’re talking about today on the shelf because you’ve got all kinds of new interests. You have people coming back in to the last lease sale, spending $40, $50 billion -- million on new leases.

So the answer is that will get sorted out and as far as insurance is concerned enough, there will have to be a risk pool, everybody thought they had it figured out with the proves that were in place. But first we have to really sort of get out of this emotional period whether this well is going to cost $200 billion or $2 billion, I mean, the numbers I’m saying to land because of the enormous amount of pain that’s been felt.

So to answer your question, I think it’s, until we get some of the emotion of getting this well killed, it’s not going to be as easy to define as it will be once people start to ration. But at least in my opinion, there will be an insurance pool, a high risk pool. If this was an earthquake or a hurricane, we’ve seen insurance groups for both. You could say, well, that’s going to happen again. There is going to be another hurricane. There’s going to be another earthquake. But this isn’t going to happen again. This wake-up call for this subsea intervention from a mechanical failure will all be on the shelf and computerized as to how you deal with it. There won’t be the experimental stuff as things have gone on the last three months, at least in my opinion.

And you’re going to have to have that because nobody is going to operate in an environment where you have to throw into your goal factor as to whether or not to bid on a lease or drill a prospect if you’ve got a liability that’s totally unlimited. There’s not a prospect out there in the Gulf of Mexico deepwater that’s good enough for people to say, well, the prospect is a wildcat and you’ve got to bid on it and drill it to find out if it’s productive. Nobody is going to bid on a lease or drill an exploratory well that’s got in the formula for your rate of return a possible loss because of the kind of losses that are being thrown out right now. The answer is, nobody is going to do that.

So between the government and the industry, there will have to be a risk pool type concept whether you, again, whether you buy into the comparison of Chernobyl to this situation, everybody’s got their own opinion about that. But again, I don’t want to take become a (inaudible) here but those are kind of my impressions of what’s going to flow as people start to become rational and deal with the real economics and realities of how you keep the Gulf of Mexico as a resource for the U.S.

Richard Tullis – Capital One Southcoast

Thank you, Jim Bob. I appreciate that insight.

Kathleen Quirk

Operator, we have time for one more question.

Operator

Our final question comes from the line of Gregg Brody with JPMorgan.

Gregg Brody – JPMorgan

Thanks for the last question. I’ll just keep it short. Just on the borrowing base re-determination, when is your next one and what’s your expectation for maintaining the front size?

Kathleen Quirk

The next, we completed our re-determination in April and the borrowing base was maintained at the same level at $175 million. Our next re-determination is in the fall, in October. And we have no comments at this point in terms of what it will depend on our results and prices used by the bank. So we don’t have any comment as to what the borrowing base will be at that point.

Gregg Brody – JPMorgan

Thank you very much.

Richard Adkerson

Thanks, everybody, we appreciate your participation in the call and I look forward to reporting to you on an ongoing basis.

Operator

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

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Source: McMoRan Exploration Co. Q2 2010 Earnings Call Transcript
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