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McMoRan Exploration Co. (NYSE:MMR)

Q3 2007 Earnings Call

October 19, 200710:00 am ET

Executives

Kathleen Quirk - SVP and Treasurer

Richard Adkerson - Co-Chairman

Jim Bob Moffett - Co-Chairman

Analysts

John Herrlin - Merrill Lynch

Brian Kuzma - JP Morgan

Philip Dodge - Stanford Group Company

Gary Nuschler - Jefferies & Company

George Froley - Froley Investments

Operator

Ladies and gentlemen, thank you for standing by. Welcome tothe McMoRan Exploration Third Quarter 2007 Conference Call. During thepresentation, all participants will be in a listen-only mode. Afterwards, wewill conduct a question-and-answer session. (Operator Instructions)

I would now like to turn the conference over to Ms. KathleenQuirk, Senior Vice President. Please go ahead, ma'am.

Kathleen Quirk

Thank you and good morning, everyone. Welcome to the McMoRanExploration third quarter 2007 conference call. This is an exciting time forMcMoRan as we report on our first quarter of results following the acquisitionof the Gulf of Mexico shelf properties from Newfieldduring the third quarter.

Our results were released earlier this morning and a copy ofthe press release is available on our website at mcmoran.com. Our conferencecall today is being broadcast live on the Internet, and anyone may listen tothe call by accessing our website homepage and clicking on the webcast link forthe conference call.

As usual, we have several slides to supplement our commentsthis morning. We will be referring to the slides during the call and you canaccess those slides by using the webcast link on mcmoran.com. In addition toanalysts and investors, the financial press has also been invited to listen totoday's call, and a replay of the webcast will be available on our website latertoday.

Before we begin today's comments, I'd like to remindeveryone that today's press release and certain of our comments on the callinclude forward-looking statements. Please refer to the cautionary languageincluded in our press release and presentation materials, and to the riskfactors described in our SEC filings.

On the call with me today are McMoRan's Co-Chairmen, Jim BobMoffett and Richard Ackerson. I'll make a brief summary of our results, andthen turn the call over to Richard, who will be reviewing the slide materialsposted on the website, and then we will open the call for questions.

Today, McMoRan reported a net loss of $52.2 million, $1.50per share for the third quarter 2007 compared with a net loss of $19 million,$0.67 per share for the third quarter of 2006.

Our third quarter 2007 financial and operating resultsinclude the acquired Newfield properties beginning on August 6th, 2007. The results of the acquiredproperties from the July 1st, 2007effective date through the closing date are reflected as purchase priceadjustments on McMoRan's balance sheet.

Our net loss from continuing operations for the thirdquarter of 2007 totaled $51 million. That included $37 million in explorationexpense, comprised of $12.5 million for the acquisition of seismic data relatedto the acquired Newfield acreage and $20.4 million for nonproductiveexploratory well costs, primarily associated with the Caswell at SouthTimbalier Block 98.

We also recorded an impairment charge of $13.6 million to write-offthe remaining book value of the Cane Ridge field, and a gain of $10.7 millionfor non-cash mark-to-market accounting adjustments associated with ourderivative contracts.

As we previously reported in connection with the acquisitionof the Newfield properties, we entered into derivative contracts to hedgeapproximately 80% of our estimated proved producing volumes for the period from2008 through 2010 through a combination of swaps and puts.

Our third quarter revenues include the acquired properties, asI said, beginning on the August 6th closing date. The oil and gas revenuestotaled $131 million compared to $57.8 million during the third quarter of2006. Since the August 6th closing date, the Newfield properties contributed $95.4million of oil and gas revenues to McMoRan, and for the full third quarter, sinceJuly 1st, the Newfield properties generated oil and gas revenues of $164.3million.

Our third quarter production, including results from theNewfield properties since August 6th, averaged 185 million a day net to McMoRancompared with 75 million a day in the third quarter of the year ago period.

On a pro forma basis, our production averaged 289 millioncubic feet equivalents per day, and that included just over 240 million cubicfeet equivalents natural gas per day from the Newfield properties since July1st, and 48 million a day from legacy McMoRan properties. This was slightlybelow the previous estimates that we reported of 300 million a day, primarilyas a result of the exercise of preferential rights associated with one of theacquired properties.

Our third quarter realizations for gas were $6.17 per Mcf in2007. This compared with $6.51 in the year ago quarter. And for oil, wereceived an average of $75.08 per barrel in the third quarter of '07 comparedwith $65.11 in the year ago period.

I would now like to turn the call over to Richard, who willbe providing additional details on the Newfield transaction, drilling program,including the recent Flatrock discovery, and also our outlook.

Richard Adkerson

Thanks, Kathleen. It's obviously a big, big quarter for ushaving completed the Newfield acquisition. As Kathleen said, we closed thattransaction on August the 6th. The effective date for transferring productionwas July 1st. Big expansion of scope of operations in the area of ouroperations, very attractive economics on the acquisition, and importantly, asignificant addition to our acreage.

Since we made the acquisition of Newfield, two importantevents we want to focus on in today's earnings call. The first we want to talkabout is the exploration drilling that we did at our Flatrock prospect in theSouth Marsh Island area as part of continued drilling on 150,000 acre positionthat we have in the area where the Tiger Shoal/Mound Point fields havetraditionally produced substantial volumes of over 6 trillion cubic feet of gasof production.

In Flatrock itself, we saw eight productive sands that had260 feet of indicated pay by wireline tests. There were five Rob L sands andthree Operc sands in the Miocene section. And this indicates production over asignificant area of a very large structure, and we're going to be veryaggressive in drilling follow-on development exploitation and exploration wellsin this area. I'll be talking more about that.

The second thing we want to focus on is something that wesaw in the acquisition of Newfield, and it was in addition to the attractiveeconomics of our acquiring the production. But the fact that we were acquiringsuch a significant acreage position that provided further exploitationopportunities in the traditional shelf production, but also the opportunitiesfor deep gas drilling that was consistent with our strategy that we've beenfollowing since 2000.

And the value of this was really illustrated andsubstantiated by the recent October 3rd lease sale, where we had significantlylarger amounts of capital exposed by a broader group of companies, some newplayers, which we believe validates our view that there are substantial amountsof potential production to be found, and adds what we consider to besignificant value to the acreage that we acquired from Newfield. And I'll betalking about that a little bit more. But our strategy continues to be from anexploration standpoint to pursue the deep gas exploration and developmentactivities, that's the drilling of wells from 15,000 to 25,000 feet.

With this program that we've been pursuing since 2004, we'vehad discoveries on 17 of the 32 prospect that we drilled and evaluated. We havea current well, the Cottonwood Point, which has indicated production thatcontinues to be in progress. We have replaced during the first half this yearfrom the properties that we had prior to the Newfield acquisition, reserves andrevisions that are 200% of our first half production. And we continue to behighly enthusiastic about the prospects of adding significant reserves in thefuture from our exploration opportunities.

As Kathleen mentioned, we had significant production duringthe quarter. Pro forma production averaged 278 million a day. That's net of 11million a day of gas that we produce that was used in operations. Includes 230million a day from the Newfield properties, and in the fourth quarter, we'reexpecting to average net of gas consumed in operations an average of 290million a day.

We are working and expect to get Flatrock and Hurricane Deepdiscoveries on production by the end of the fourth quarter. And we haveactivities that we believe has a great opportunity for us to add significantlyto our production as we go forward into 2008.

(Technical Difficulty) on the website summarizes theNewfield transaction. We acquired this for $1.1 billion. As Kathleen indicated,we had about $30 million of revenues between the effective date and the closingdate, which didn't go through our earnings in this quarter, but adjusted thepurchase price. The estimated proved reserves based on Ryder Scott engineeringstudies were 321 Bcf equivalents as of July 1st with significant amounts ofprobables and possibles, again, estimated by independent reservoir engineers.

Significantly, we acquired acreage of substantial size andscope on the shelf of the Gulf of Mexico, over 1.25million gross, 0.5 million acres net to our interest. And this adds significantvalue to this acquisition beyond just the production reserves. But the reservesthemselves provide good economics based on the outlook for oil and gas pricesand the established reserves.

The PV-10 of the proved reserves as of July 1st was over$1.5 billion, and indicated, based on strip pricing, additional upside, but avery attractive rate of return on the investment that we put into the reservesthemselves.

We end up with a company with McMoRan now having asignificantly expanded size and a significant expansion of scope, which will bebeneficial to us beyond just the rate of return on our investment, but in termsof our future exploration and operational focus on the Gulf of Mexico shelf.

It complements what we had been doing prior to theacquisition. It gives us high-quality producing assets, exploitation potential,the deep rights to these, and that's been the focus of our explorationphilosophy of following the structures that produce significant amounts of gas,at shallow horizons and finding the migration of those structures to greaterdepths, and then testing those through exploration drilling.

We continue to work with Newfield to pursue exploration onthe leases, the exploration leases they had that weren't held by production. (TechnicalDifficulty) to work on those together.

Slide 5 shows the roll-forward of our reserves, firstlooking at our proved reserves, which, of course, only included our legacyproperties as of yearend of roughly 76 Bcf. We produced 11, added throughexploration and revisions, 23. You end up a net with our legacy properties ofabout 88 B's equivalent at July 1st and acquiring the 321 to give us over 400Bcf of proved reserves. 3P reserves, our probable and possible reserves, again,using our independent engineer's assessment of those was over 700 Bcf ofequivalents.

(Technical Difficulty) growth and expansion of our businessis shown on the charts on page 6, where we show our reserve growth over theyears, our production growth, and the success that we've had with our deep gasexploration drilling in terms of the successful numbers of wells that we havecommercially completed and the ones that we've drilled and tested.

Page 7 shows the average production from our top fields forthe combined companies during the third quarter. This is pro forma for thequarter and it shows the concentration of the production in the central area ofthe Gulf of Mexico, which has been the focus of ourexploration program and exploration efforts that we've put together since welaunched this deep gas play back in 2000. And so, we just couldn't be morepleased about the opportunity to acquire quality properties, and explorationopportunities in the areas where we were operating.

Page 8 has some important information about how we're goingto be running the company. It shows our 400 Bcf equivalent reserves. Our proveddeveloped producing reserves are roughly a third. We have significant amountsof non-producing behind pipe reserves and undeveloped reserves. And we'll beworking very diligently to bring these reserves into the producing categories (TechnicalDifficulty) properties as Newfield has been operating on them, and we're reallyfocused into turning these into cash flow producing assets. Of the reserves,70% of gas, 30% of oil.

Page 9, again, is a chart that shows just how significantthe expansion was for us going from 75 to over 400 Bcf equivalents of reserves,with SEC PV-10 values of roughly $360 million to $2 billion.

Then, page 11 shows the acreage and where it's located. Ourexisting McMoRan acreage is in yellow, the Newfield acquisitions in red, andthen the ultradeep leases that we acquired from Newfield, which are shelfleases, drilling to sands that are deposited beyond the 25,000 foot area thatwe've been drilling in our deep gas play. But this has explorationcharacteristics that are similar to the deepwater plays that have been sosuccessful for the industry, and it's an important additional opportunity forus. But again, it demonstrates the concentration of these leases in the Central Gulf of Mexico.

Page 12 is a chart we put together. We call it: "FoodFor Thought." And this makes the point that I referred to earlier. At thetime we were looking at the possibility of acquiring properties in the Gulf of Mexico, and when we made the Newfield acquisition, there hadbeen an extended period of time of companies moving away from the shelf of the Gulf of Mexico, and from the Gulf of Mexicogenerally.

The movement of the larger companies to deepwaters toforeign areas, and of independent companies away from the Gulf to Mid-Continentareas was something that had been well established and had reflected the fastdepletion of properties in the Gulf and the challenges of maintainingproduction, given the extent of the exploration that had been done in the traditionalarea.

But we have been having a contrarian view about the Gulf of Mexico for some time. We believe and continue to believe thatthere is significant production to be established at depth, and we've hadsuccess. And with the very positive oil and gas prices that the industry hasnow available to it, we saw really an eye turning situation that occurred thefirst week of October this year with the OCS lease sale Number 205.

It was the second largest sale in MMS history. It is thebiggest sale in 24 years. And when you look at the amount of capital that wasexposed, the amount of the successful bids and these bids extended from shallowwater to deep gas plays and to deepwater plays, you saw something that was 6, 7times the level of interest that we'd seen on average over the past 10 years.

The average price per acre in this lease sale was $800. Andyou have to go back more than 20 years to see similar types of capital beingexposed in the Gulf of Mexico when, of course, there was only drilling done onthe shelf at that point.

The charts on right are used to illustrate that if you lookat the average economics of the bids that occurred in sale 205, and look at ourproperties, that there are potentially very significant amounts of value therethat are beyond the purchase of the proved producing assets.

And we saw this when we were evaluating Newfield. It was animportant factor that led us to act on this opportunity where we hadn't actedon previous opportunities. And this fits right into what we're doingphilosophically with our exploration program, and we believe demonstrates thevalue of the decision we made to move forward with this acquisition.

(Technical Difficulty) shows the Flatrock discovery. This isin the area where we have been drilling since 2002 initially in a joint venturewith El Paso. Excuse me, I've beenfighting a sinus problem. Let me get my voice back here. But we have been drillingin this area since 2002.

Through subsequent lease acquisitions, we have established150,000 acre position. We had had success drilling prospects on 217, inprospects that we called Hurricane prospects, where we had drilled four wellson Block 217, and including the Hurricane Deep prospect, which we've recentlytested and expect to bring on stream in the fourth quarter.

In this section, we see there are three sections of Miocenesands, the Rob L, Operc and Gyrodina. And in the Hurricane Deep prospect, wesaw a very thick 900 foot sands section that had production in it; asubstantial amount of it is wet. But the indication of very large sands in thisarea is what's characterizing what we're seeing in this area.

Now Flatrock is on 212. As I mentioned, it saw eight sandsin the Rob L and Operc sections with 260 feet of net pay. A characteristic ofthe exploration we're doing is because of the existing of historical productionfacilities we're able to bring these discoveries on stream very quickly, and weexpect the first Flatrock well to be producing during the fourth quarter.

We have permitted three additional wells. The Number 2 wellis now drilling at 5,000 feet. The third well will be spudded during the fourthquarter. And by the significant acreage in this, it gives us the ability tolook forward to a significant amount of exploitation, development, explorationareas.

The history of this area is shown on the slide on page 14.This was where the major Tiger Shoal fields and Mound Point fields, Lighthousepoint fields were developed historically, with multi-trillion cubic feetproduction at shallower areas above 15,000 feet. The rights to this acreagewere originally acquired by Texaco in the 1940s. It spans federal waters andstate waters, and so we have federal leases now as well as the state leases atthe Mound Point area. And it's looking for the deeper pool depositions ofproduction associated with these structures that were so prolific at shallowerdepths is what is the philosophy that drives us.

Page 15 shows our historical drilling there, our first wellwe drilled in the Mound Point area, and that was followed up with discoveriesin the JB Mountain area in OCS 310. And now we are continuing to use theinformation that we've learned through the extensive amount of wells that wehave drilled and our better understanding of geology to pursue furtheropportunities. And that's what led to the very significant Flatrock discoveryfor us.

On page 16, you see the extension of what we saw in theFlatrock Hurricane areas, where we saw in Flatrock the Rob L and Operc sandssituated against the big original fault system. And then, what we saw in theGyro area to the south, where we had six wells, and counted six pay sands. Understandingthese sands; understanding the geology that will give us the opportunity to goforward.

On page 17, we show the recent exploration well that wedrilled at Mound Point, the Mound Point South well, which was, at eight feet,had significant potential -- at the Mound Point South well and state lease 340.It was similar in some ways to the first well we drilled in this whole area, whichwas a Mound Point well, in that as we were drilling deeper we saw large well developedsands.

Sand development is the principal exploration risk for deepgas drilling. And our team was very excited about the quality of the sands thatwe saw. Again, in drilling this well, where we saw 15 feet of net pay, we werethen again saw well developed sands, which gives us the encouragement to goforward and find the areas in this deposition of where we can find significantproduction.

Page 18 shows the potential that we see in graphic form fromthis area. The traditional production fields are shown at Tiger Shoal and MoundPoint. You see with the cross lined areas, the productive areas that we've seento-date with our drilling. And the potential is shown in the shaded areas thatlie at depths below Mound Point and associated with the JB Mountain, BlueberryHill. Very large structures, very significant amounts of production potential,that we see in this area.

Just west of the Tiger Shoal field, we have an explorationwell drilling at Cottonwood Point. It's located at Vermilion 31, shallow water5,000 plus acre lease block, big potential. We've seen production as we weredrilling at a higher horizon, but with wells at 19,000 feet, targeting to go toa total depth of 21,000 feet.

On page 20, we've shown the blocks that we acquired in theNewfield transaction and the blocks that had cumulative historical productionof more than 100 Bcf of equivalents. The red blocks have had 100 to 250; kindof the Tennessee orange is from250 to 500; and the Texas Burnt Orange is over 500.

It shows just the number of productive fields that have seenproduction from the traditional shallow areas of the Gulf of Mexico.And with our acquisition, we now have the opportunity to evaluate thepotentially deeper production horizons as we follow the migration of thesestructures to depths below 15,000 feet.

You feel like other traditional Gulf explorers were notfocused on these, because of the absence of bright spots and the challenges indrilling them. But what we've acquired through this acquisition is now theopportunity to look for these deeper depositions. Our exploration team hadbegun that process, and we see a number of very interesting prospects thatwe're going to be pursuing, again, very consistent with our philosophy that we'vebeen following prior to the acquisition of Newfield.

The chart on page 21 brings together the explorationopportunities that have existed in the Gulf. The traditional drilling below15,000 feet in the Pliocene section of the Gulf has, one, it's been sosuccessful using bright spot exploration drilling. Our focus has been drillingbelow that from 15,000 to 25,000 feet for the Miocene sands where prospectscan't be qualified by bright spots, but where you can use modern 3-D seismic toidentify structures. And with an understanding of sand deposition and thehistory of what we're doing, we can find very attractive, potentially prolificprospects to drill in that area.

Then, lying below that, in the middle Miocene and lowerMiocene and older aged sands is the exploration that has been done in thedeepwater, and which we now have the opportunity to pursue on the shelf throughthe ultradeep plays that we have acquired from Newfield, which came in there [EAEX]acquisition earlier.

Blackbeard prospect is the initial prospect that Newfieldand its partners were testing. They drilled a well which did not reach itsobjectives, but went below 30,000 feet, which they temporarily abandoned foroperational reasons.

The slide on page 22 illustrates the exploration objectiveof this, and shows that in terms of its test, it's similar geologically to thesuccessful drilling that has been done at the major fields that have beendrilled in the deepwater. These are similar geological settings, testingsimilar types of prospects.

It's simply that this is on the shelf, and the otherprospects were off the shelf, where they have to be drilled using the kinds ofexploration processes and face the completion issues of dealing in the deepwater.They are similar type targets, and we are very excited about this. We believeit's a great opportunity for our company to put together the drillingarrangements and pursue itself.

The first one we're focusing on is the Blackbeard ultradeepproject, page 23. The details are shown. It's in South Timbalier Block 168 in70 feet of water. As I mentioned, the original operator and partners drilledbelow 30,000 feet. They did encounter sands that were gas bearing, but theyfailed to reach the primary target, and they abandoned the well in 2006.

But the drilling results that they saw confirmed thegeological model and thesis that was led to the prospect being tested. Jim Boband our team has been reviewing this, and it's our intention to deepen this wellto develop the drilling arrangements to allow us to test this primary target,and we believe this is a great potential opportunity for us.

The change that's occurred with respect to these types ofprospects can be seen on page 24, when we looked at the historical amounts thatwere paid in the deepwater for these type of prospects compared with what'srecently been paid in lease sales. Where at one point leases could be acquiredfor $1 million a block or less, today, lease blocks are going for substantiallyhigher amounts, $20 million, $50 million, $70 million. And again, it justillustrates that with the success that's occurred in testing the similar typesof prospects that we have with our ultradeep play, that the values the industrysees in these has grown significantly.

Page 25 shows where the Blackbeard property is located.Geologically, it's tied into the Miocene plays in the deepwater that we see in Mississippi Canyon. We also have substantiallease blocks in the Western Gulf,the Roberts 95,000 gross acreage and East Breaks, which is a continuation ofthe Wilcox type sand deposition that was seen in the Jack deepwater well.

Industry is drilling wells in this region to depths of below20,000 feet. It's going to provide us with important regional geologicalinformation to help us as we continue to assess the opportunities for drillingin the Western ultradeep plays for us.

I'll close with financing and the outlook. Page 26, we'veborrowed approximately now $400 million under a $700 million bank creditfacility to fund the Newfield acquisition. The remaining amount of theacquisition was funded under bridge facilities that our banks, JP Morgan andMerrill Lynch, provided to us. We repaid a term loan in connection with the newfinancing that we arranged. At 9/30 we have $313 million of borrowings underour credit facility.

We expect to refinance the bridge facility through acombination of debt instruments, equity instruments, equity link instruments.In that connection we have an effective SEC shelf filing that we completed inOctober 2007, and we're assessing the right time to go to the markets torefinance the bridge financing that we have in place.

Our fourth quarter outlook, as I mentioned earlier, andKathleen mentioned, provides an outlook for our 290 million a day of averageproduction volumes, including 230 million from acquisitions from Newfield. Itdoes not include the potential of getting our Flatrock discovery on stream,which we're targeting to do as quickly as possible, we hope to do by the end ofthe fourth quarter.

2007 capital expenditures are estimated to be $190 million,which includes $150 million for our McMoRan deep gas exploration program. Andour outlook for 2008 capital budget is approximately $200 million. But, asalways, our spending is going to be driven by the opportunities that we have.

Our set of properties now provide us very substantialamounts of cash flow, as shown on the chart on page 28. Looking at currentforward pricing in the financial futures markets, the commodities futuremarkets show that we would have earnings before taxes and depreciation, CapExof $700 million.

You can see the sensitivity to prices. That's substantiallyhigher than our capital spending. And then we will be using that cash flow inexcess of our capital spending to delever. And with the market that we have forcommodity prices, we should be able to de-lever very quickly as we show on page29.

By the end of '08, assuming we raise $300 million of newequity, we should be able to reduce our debt basically at $7.50 gas and $65 oilto onetime annual cash flows, or EBITDAX. And then, by 2009 make furthersubstantial reductions in debt. So we have the ability to delever very quicklyas we pursue our exploration program.

What we're in this for is exploration. That's what McMoRanis about before, and that's what we will continue to be about. On page 30, we'vetried to demonstrate just what is the leveraged exploration that we haveavailable to us with the kind of projects that we're pursuing. And we're usingFlatrock here as an example.

Inherently, in drilling, we're going to have dry holes as wehave had, and the reason we drill dry holes is to have the chance to drillprospects like Flatrock, where, with by spending $40 million for an initialwell, we have the PV potential, which is based right now on our Ryder Scott 3Preserves of $2 billion for growth. When you look at what we had based on thefact that we had drilling arrangements and had to farm-in this prospect, wecould see a $20 million well creating values approaching $0.5 billion net toour interest based on our front end economics.

Now, when we have the Newfield prospects, we won't have tofarm those in since we have the HBP leases. And with that kind of opportunity,the economics basically are twice as attractive. We have to farm prospects in,because we're drilling these deeper pool theories associated with traditionalproduction, and many of these leases have been held for years by lease owners.And the only way to get access to them in that situation is to do farm-ins. Butwhat we have now with Newfield is a very substantial amount of acreage withtraditional amounts of production and the ability to pursue themselves withoutfarming it.

In today's world we see others paying very significantamounts, of course, with the recent lease sales to acquire leases, to pursuethese types of things. And again, we want to make a point that we believe we'vegotten additional value in the Newfield deal beyond what we paid for it, justfor the reserves.

We continue to pursue our commercial arrangements for ourMain Pass Energy Hub. We have the permits in place now to develop a major LNGreceiving facility to build a pipeline into north into the Alabamaarea to connect into the USgas market. We have the onsite natural gas storage caverns, which make this anattractive project. The location of the Eastern Gulf of Mexicoalso makes it attractive. And our issue now is to find in a competitive worldsupply for this project.

This is something we're going to work on. We believe it hasgreat potential value for our company. We're not spending a lot of money on itat this point. We believe we will be, but when we are successful in findingsupply that with off-take arrangements will allow us to finance this project ona project type basis.

For our company, we have significant now reserves, growingproduction. Our exploration will continue to characterize what we're about. Wehave one of the largest acreage holdings on the Gulf of Mexicoshelf, and those shelf acres are becoming increasingly more valuable.

Strong cash flow: We have the Main Pass opportunity, and we have amanagement team that's had a track record of success for decades. So, wecouldn't be more excited about where our company stands today.

With that, I'd like to turn the call over for questions. JimBob is here to respond to questions.

Question-and-AnswerSession

Operator

(Operator Instructions)

And our first question comes from the line of John Herrlinof Merrill Lynch. Please go ahead.

John Herrlin -Merrill Lynch

Yeah. Good morning. I have a bunch of well related typequestions. With Flatrock, Richard, you said end of the quarter in terms ofhooking in for timing, how about potential initial flow rates for Flatrock?

Richard Adkerson

Well, I should have mentioned that we are, as we speak,preparing the initial productive zone for testing, John. And we had hoped tohave that before our earnings call. But just in terms of getting the equipmentand so forth in place, we will have that well tested, and we will be disclosingresults of that test in a matter of days.

Jim Bob Moffett

John, this is Jim Bob. What we're doing is completing theOperc sand at 17.2 in that well. It's the second biggest sand in the well. Thethickest sand, as we've reported, is up to 15,000 feet, which is the 260-footsand, about 370 feet gross. The reason we did that was since the Operc was thedeepest and second biggest there, we can twin the well to get the shallow115,000 feet cheaper than we could have trying to twin the Operc.

Based on the Operc sand thickness and the surrounding wellsand the production flow test that we've seen and the wells to the South, forinstance, the Hurricane well to the South, it was a Rob L sand, with slightlyless pressure, but similar reservoir characteristics, flowed 50 million a dayand a couple thousand barrels of condensate. Now the Operc, based on the flowrates we've had at Mound Point, should be a similar flow rate well with leanercondensate rates, somewhere around 20 barrels a million.

But our estimate would be that this Operc sand, based on thelog characteristics, should flow something between 40 million and 70 million aday. We have 3.5 inch tubing in the well. And as Richard said, that well oughtto be on a test this weekend. We're just in the middle of finishing theperforations.

So the bigger sand in the Rob L, which is the 15,000 footsand, we're drilling the northern well, the Number 2 well below 5,000 feetright now. And then the southern well will move from the Flatrock well we'retesting now, and it will spud probably in about two weeks. So we have those twowells going. And their principal objective will be this Rob L section, as wellas the southern well testing some deeper Operc.

The thicker Rob L sand, the 260 foot zone, we believe willflow somewhere between 75 million and 125 million a day based on similar flowsin the area and have a condensate ratio of 30 to 40 barrels a million. So thoseare some of the reasons why we feel so confident about this Flatrock discovery.Not only will the sands stick, but we have wells in the area and on trend thathave exhibited high flow rates from similar sands.

John Herrlin -Merrill Lynch

Great! Some more questions. With Mound Point South you saidyou had tubular issues. Is this a sand control situation or what's the dealthere?

Jim Bob Moffett

Say that again, John?

John Herrlin -Merrill Lynch

With Mound Point South, there was something in the releaseabout you needed special tubulars. Could you explain why?

Jim Bob Moffett

Well, in the Gyrodina, unfortunately we have CO2 and H2S.And the tieback string that we have to run has to be a special alloy so wedon't have any corrosion from the H2S, CO2. We had to do the same thing for theHurricane Deep well, which we just moved back on and completed in the Gyrodinasands. So that's the reason for the special tubular goods.

In the South Mound Point well, John, it's very similar tothe Hurricane Deep well. Hurricane Deep well is part of the Flatrock, Hurricanestructure, which is the deeper pool of Tiger Shoal. Mound Point South is partof the deeper pool of Mound Point, which is the next structure to the east. Andin that well, the reason why I compared it to the Hurricane Deep, we weredrilling the well, started in the middle of our grid that we drilled in thisarea, and we had over 2,000 feet of sand in the Operc, Gyrodina as potentialreservoir. We just had one of the sands that was hydrocarbon bearing. It lookslike we just need to move a bit, similar to what we found at the Hurricane Deepsituation, when we moved to the north on Flatrock.

But we think that because of the fact that we got Opercproduction just to the north of the Mound Point South well in the El Paso Number1 well that's been on production for four years. And our first well that wedrilled, that mechanically couldn't be completed, but had pay in the Gyrodinato the north of the Mound Point South, that this big core deeper pool of the2.5 Bcf Mound Point field. We got to get the sweet spot, and that's what themap showed, cross-hatched acreage shows that we've gotten another entry incubic foot potential.

And the reason we feel that there can be a Flatrock of MoundPoint is these are twin structure shallow, they ought to be twin structuresdeep. And we've now seen Operc and Gyrodina pays on the flank of it. So theMound Point South well also gives us a lot of confidence in this Blueberry Hillprospect to the South, where we drilled and have the multiple pays that werevery thin, and we couldn't get a commercial flow rate out of them. We're goingto back off, as we said, and go down deep at Blueberry Hill.

With Mound Point South, that's just to the north, and it's aclear indication that the big Blueberry Hill structure must have had so muchvertical relief that it kept these big sands from getting all the way on top ofthe structure. But you have this strong north and northwest dip that we'veshown before, and the sands that we see in Mound Point South should make itdown to the flank. Obviously, we're going to have to drill to prove it.

But what really is compelling about this whole situation isthe thickness of the sands and the quality of the sands that we see in thesezones. That we know we will have high flow rates. JB Mountain just to the Southof Mound Point South and east of the Hurricane Deep prospect has just 400 feetof Gyrodina zones, two of them, and they've been producing over five years.

I think those two wells have produced just under 100 Bcfalready. So, as you can see, we're starting to get the area here, sanddevelopment defined. And as we finally zeroed in and pinned the tail on thedonkey at Flatrock, we believe we've got that opportunity to do it on theseother major structures in this mini basin that represents the deep core ofTiger Shoal Mound Point.

John Herrlin -Merrill Lynch

Okay, great. One other for me. On Hurricane Deep, Jim Bob:can we open up the choke anymore? It seemed like it was kind of a small chokein that well.

Jim Bob Moffett

Well, it was a limited test because we had the rig onlocation. The 15 million a day rate, we had almost no drawdown. It flowed12,000 pounds of pressure. And you could open it up to 15 million, and the flowat 11.8, which is almost no drawdown.

I think if we do that, as you know, in that zone we had that900 foot sand with about 100 feet gross above water, 50, 60 feet net. So we'llbe somewhat cautious about going to a rate to cone that water in. We feel basedon the Flatrock well that we will be able to get it higher to the West and theSouth on this zone, and pick it up another 100, 200 feet out of water. In thosewells, we can flow a little bit more aggressively.

But, to answer your question, we will expand that. That wellshould come on like our Flatrock well in the fourth quarter. We will expandthat with us when we get it on production. What we generally try to do is tonot go more than a 20% drawdown. But these rocks are so porous and permeable,even with these high pressures you see almost no drawdown.

For instance, over to the east, at Laphroaig, you saw thatwe produced net wells, 44 million a day with 11,800 pounds of pressure andabout 1,000 barrels of distillate. The shut-in pressure on that well is only1,000 pounds higher. So we're flowing 44 million a day out of the zone at19,000 feet Miocene zone with just almost less than 10% drawdown.

The qualities of these rocks, John, with these pressures, ispretty damn impressive as far as getting the high flow rates. Long Point to thenorthwest of Tiger Shoal/Mound Point and slightly older rock in the Planulina,we have two wells there that have been on production almost two years. They'reflowing at a combined rate of just under 60 million a day.

So, I think we've convinced ourselves and everybody must begetting convinced about the characters of the rock. As you know, when we firststarted this deepwater shallow deep gas play, a lot of people were concernedabout the quality of the rock. We've said based on the onshore production inthe Hollywood sand and some of the stuff at Lake Sands and Pecan Island to the north, that we didn'thave any concern about regarding 3-D type deep Miocene sands, because they hadproven production characteristics. I think that's been pretty much confirmed bythe drilling that we've done along this trend right on the edge of coast andinto the water.

John Herrlin -Merrill Lynch

Great! Last one for me is on Blackbeard: Any issues with theMMS in terms of extending the leases? And: have you had other companies talk toyou about perhaps getting involved with that play?

Jim Bob Moffett

Well, John, the MMS is anxious for us to get back to work.Obviously, the leases are held by a SOP with MMS. Our requirement is we have tocontinue each year to be drilling another well or shooting significant seismicto continue to outline the play.

On that situation, as the map showed, the Blackbeard wellwas drilled just about to the top of the Miocene. It's got 9 and 5 H casing at28,700 feet. It's been D&E. We've seen it flow and we're going to move backon it, and we'll clean out the cement plugs and go in. And we believe we canmake about 1500 feet a hole on 3-D seismic guys to the 90 head of Mad DogTahiti complex.

The Miocene sands are exactly equivalent in terms of biostratigraphicposition in the section. And this foldout goes right from the shelf to the deepwater.It doesn't know that the hinge line currently sits halfway between it. And to thewest, on the Robert and [Private Deer] play, where we have the 95,000 acres, BPhas got a location staked 10 miles west of us. I think it's called: “the El Dorado play”. It's going to be drilled at 28,000 feet.

And into the west of that and the east breaks, we have asubstantial acre position, over 40,000 acres. And south and west of that in North Padre Island, Petrobras is currently drilling a well that they'retrying to go to 25,000 feet; I think there's about 19,000 feet right now. Boththe El Dorado and the Scorpio well, which is the Petrobras well drilling inNorth Padre Island, their objectives are the Eocene or Yegua and Wilcox, whichis the same objective as has been publicized in the Jack Field, in the Chevron,Devon's announcement six months ago.

So, what you have on the shelf, if you look at the deepwaterfoldbelt play, you have an eastern region deep Miocene play and the sands getolder into the Wilcox, Yegua. As you move to the west into deepwater, you havea mirror image of that on the shelf. So, in those plays that we have in termsof Blackbeard, Robert Private Deer and the East Lakes acreage, these are hugestructures. They cover more than 20,000 acres of closure, and have thepotential of 3 to 5 Tcf for prospect.

And, of course, as we've seen in the deepwater, in theMiocene and the Jack, they're finding oil. So either 300 million to 500 millionbarrel potential of oil, or a 3 to 5 Tcf potential of gas gives us some bigexposure on that foldbelt play, as it has been called, in theMiocene/Yegua/Wilcox, huge opportunity for us.

John Herrlin -Merrill Lynch

Great! Thanks very much. That's it for me.

Operator

Our next question comes from the line of Brian Kuzma of JPMorgan.

Brian Kuzma - JP Morgan

Good morning, guys.

Jim Bob Moffett

Jim Bob Moffett

Good morning, Brian.

Brian Kuzma - JPMorgan

First question is just on production. Could you guys clarifywhat the pref rights issue was? And: how much that impacted your productionestimates?

Jim Bob Moffett

Well, I mean: it was an Exxon pref right that was exercised andI think it was about 15 million a day.

Brian Kuzma - JPMorgan

Net?

Jim Bob Moffett

We paid, I don't remember, $27 million for that property.And they stepped up and exercised their pref rights.

Brian Kuzma - JPMorgan

Okay.

Kathleen Quirk

Jim Bob, it was $24 million, roughly, was the exerciseprice. And it was 3.6 Bcfe of reserves.

Jim Bob Moffett

And that's the only expansion, Brian, as we had suspected.We were really kind of surprised at that one. As we said when we announced thesale, we historically not many people had exercised their pref rights, but inthis case this one did.

Brian Kuzma - JPMorgan

And then, looking forward, on those Newfield properties, youguys are basically forecasting production to be flat quarter-over-quarter. Howrealistic is that?

Jim Bob Moffett

Well, for 2008 that's realistic based on the amount of behindpipe reserves we have. And then, the decline curve starts after 2008. Brian, aswe said, our objective is to pay off these Newfield properties with the [Nightmare]legacy properties in areas like Flatrock and Hurricane, Laphroaig that we justdiscussed.

The interesting part about marrying these two plays up is ifwe're successful as we hope to be in the deep play, because of the high flowrates we're talking about, one of these deep Miocene wells can replace theproduction from 5 of the 12 pricing wells, because they generally have anaverage for the flow rate of 5 million a day, some as low as 3. Every once in awhile you get lucky and have one that's 10 or 12 million a day.

But, the Miocene wells that we're going to be marrying upnow, as we put these two portfolios together, one of these Flatrock wells thatflow at 40 million to 100 million a day, you can see we replace a lot of dailyproduction. And so that's why Flatrock and Hurricane and Mound Point South andLaphroaig have been so important to us since the Newfield deal was closed thatwe believe with the deep Miocene wells and the high flow rates that we'reexperiencing and have confirmed, we can replace a lot of those wells andflatten out the decline curve. If we do that, then we've hit the home run.

Brian Kuzma - JPMorgan

And so in that regard, when you guys look at Flatrock, forexample: can you talk a little bit about the spare capacity that theinfrastructure in the area has? How long…

Jim Bob Moffett

Well, of course, there's a huge infrastructure there. Theoilfield had two big production facilities, one at Tiger Shoal, one at MoundPoint. It's produced 6 Tcf. They are upgrading it every day. And, of course, thisis an important prospect, not only to us, but to Chevron, who inherited thisproperty in the Texaco sale. And so, the structures are in place. The bigconcrete structures, if you've ever been out there, it looks like two hugeislands. What has to happen is we continue to upgrade the production facilities,because of wells that were produced in the facility were all above 12,000 feet.They were shallow wells and basically dry gas.

The high pressure wells that we're making have substantialhydrocarbon, heavy hydrocarbon dip condensate in it. So,you have to put processing. You have to keep increasing the processing size soyou can basically get that gas, temperature and pressure down so you can getthe condensate to fall out. And so, they've already started, the Chevronpeople, on those facility improvements. And by the middle of 2008, we'reshooting for being able to take 500 million a day, and that's just the start.

There're a couple of pipelines that has to be looped, andthat's all been the process so that we can get the gas out of the field. But interms of capabilities, as I say, these structures that you set these facilitieson are huge. And the pipeline systems that exist immediately north and south ofus, the big pipelines that go in onshore, we have no problem finding home for500 to 1 Bcf a day. And those are the kind of numbers that, you know, assumingthese offsets are as good as we think, they can be with these multiple sandsthat's the kind of numbers we're looking for.

Brian Kuzma - JPMorgan

You know you're going to kill our gas market here bringingon a B a day.

Jim Bob Moffett

Well, as they said when we were talking about the copperdiscovery over in Indonesia,let's hope they put on our tombstone that we found so much hydrocarbons that weaffected the price of the hydrocarbon.

Brian Kuzma - JPMorgan

Let me ask you something else. At Flatrock, I guess twoother questions at Flatrock. One would be, when you start thinking aboutreserve bookings, if you have two wells down by yearend, start thinking aboutbooking PUD locations between those wells: how realistic is that? And then thesecond thing would be: is Chevron paying their own way now on the future…?

Jim Bob Moffett

That's correct.

Brian Kuzma - JPMorgan

Development wells, okay, they are.

Jim Bob Moffett

At Hurricane and Flatrock, on that 11,000 acres, everybodyis paying their share of drilling and completion.

Brian Kuzma - JPMorgan

Okay.

Jim Bob Moffett

So, they will be paying their 45%, we will be paying our 25,and planning to be paying their 30%. So going forward, that's where we willhead.

Brian Kuzma - JPMorgan

Okay.

Jim Bob Moffett

And as far as the reserves are concerned, Brian, as we'veshown everybody and said, this is a very flat structure, albeit the Flatrockname. And on geophysics, it appears that these locations that we're drillingshould have, at Rob L at least, almost the same elevation as the first well.The confirmation that we're looking for is that these Rob L sands have lateralcontinuity.

We know that the Rob L sands are in all the other wells, butthe Rob L has a big history of having the stratigraphic changes as you golateral. And sometimes that works out really great, because the sands we havein the well could even get thicker. They could get thinner. But, just lookingat the number of wells that we've drilled in this area, remember that there werealmost no Rob L tests in this mini basin itself.

But, if the confirmation wells confirm the lateral extent ofthese eight sands, and in the southern location we expect to see more Opercsands, because in the damped Laphroaig rock logger, in other words, we'll cut defaultlater in the wells to the south as we move south. And, if we're correct aboutthat, we actually hope to add a couple of more Operc sands.

But, if we have three wells, and obviously some of theprobable and possible reserves that are reported by Ryder Scott, we'll moveinto proven category. So, we hope to have substantial opportunities to move150, 200 Bcf of gas in the proven category that's currently considered to beprobable undeveloped. But, we've got to get these sands drilled and see if theyhave the lateral extent. With eight of them, we feel confident that this is amajor trapping structure. So, you've got flat structure and thick sands, andthat's where you get your volumes.

Brian Kuzma - JP Morgan

Got it. One last one for me is: when you think aboutHurricane Deep and Mound Point South, when you guys have found some pay andthere's some potential up-dip exposure, when do you guys see yourselves, maybe,testing those development wells that you kind of just pull out of the water?

Jim Bob Moffett

That's all we're going to be doing for the next year. Let'stalk about Hurricane Deep for just a minute. If you look at the slides, wherewe talk about Flatrock, we've shown there that the Hurricane Deep and Flatrockprospect really become one development plan.

With the wells to the North being the Rob L and shallowOperc, and then you get in the middle, you get Rob L and deep shallow and deepOperc. And then, by the time you get to the south, you're into the deep Opercand Gyrodina. The deep Hurricane well has a play in the Gyrodina that wecompleted the John (inaudible) well we were just talking about. But it also, at18,300 feet, has an Operc pay.

Now what we hope this well we're going to the south gives usenough information to see is that it shows us how the Operc pay at 18.3 tiesinto the 18.3 Operc pay we had at Flatrock. But the wells are three milesapart, and so we have to wait and see just how that middle well is going tolook. So to answer your question at Hurricane Deep, we're going to be drillingdevelopment wells there for the Operc Gyrodina on a continuous basis.

Brian Kuzma - JPMorgan

Throughout '08, yes.

Jim Bob Moffett

And: what does that mean? That means: we could have four orfive rigs in here in 2008. If you look at page 13 on your slides that we had,if you can roll back to 13, you'll see the Flatrock well in 212 and you'll seeHurricane Deep in 217. Remember, these blocks are three miles wide. So, there'sabout three miles of area between the two wells. And you have the 18.3 Opercsands in both wells.

Now: how's that well to the south going to look? Is it goingto confirm that those things are connected on that three-mile area? And ofcourse, the Hurricane Deep has the Gyrodina, which is faulted out of theFlatrock well. It may be faulted out of the well to the south. But as you movejust to the south, we think you could have Gyro and 217 and North Ave to the west of the Hurricane Deep well.

So I hope that's clear. Flatrock Hurricane Deep is all onestructure if we've got it figured correctly, and it will all be part of thesame big development program to develop these multiple sands.

Brian Kuzma - JPMorgan

Okay. And then with Mound Point South, the big takeaway hereshould be the implications for Blueberry Hill then. Do you have thick Gyro pay?Or: are there implications directly at Mound Point South that you could goup-dip and, maybe, there's more pay there?

Jim Bob Moffett

The answer is: “both”. On page 17, you see what happens is,like Hurricane Deep, we weren't sure, because this well was five miles east ofHurricane Deep, and about five miles north of Blueberry, three miles south ofthe closest well at Mound Point.

If you go to page 18, you'll see the Mound Point South welland you see Blueberry Hill, which is, as I say, about five miles to thesoutheast. The point is, though the Mound Point South well has 2,000 feet ofsand in it, high reservoir quality.

So, if you go up-dip to the Mound Point South well to theeast, directly offsetting it, we believe that you can pull more of those sandsout of water. And those sands are so thick that if you have 500 acres of one ofthese 300 or 400 foot sands, and it fills up, you're talking a half a Tcf.

And you go down to the Blueberry Hill well, and what we'resaying is, that if you look to the west of Blueberry Hill, the JB Mountainwell, which has been on production for about four years, it had 2,000 feet ofsands in the Gyrodina.

So, you take the 900-foot sand in Hurricane Deep to thewest, 2,000 feet of sand in the JB Mountain, 2,000 feet of sand at Mound PointSouth, that tells us that those sand grains in this basin were coming that farsouth, and that the Blueberry Hill well is the anomaly.

And that that structure was so big, which is why we drilledthe doggone thing that the sands didn't get up on the very top of thatstructure. And what it appears is there we will be a donut of sands around theflank of that.

So I tried to draw that pink area on slide 18 to show whatthe potential area was if it follows the contour of the structure and shoot,that's over 2,000 acres. So you get a couple hundred feet of pay there, downdip that way you've got another half a Tcf.

And the point here is: you've got to have these big, thicksands in order to have this kind of potential. And this little mini basin,200,000 acre mini basin has now, appears, that the normal section. If you don'thave a fault, or some big structure that impacts it, then you're going to havethese big Gyrodina sands, and Operc, for that matter.

Brian Kuzma - JPMorgan

Okay. That's it for me, guys. Thanks.

Richard Ackerson

Thanks, Brian.

Operator

Our next question comes from the line of Philip Dodge.Please go ahead with your question.

Philip Dodge -Stanford Group Company

Good morning, everybody. Thanks for the comments.

Richard Ackerson

Good morning, Philip.

Philip Dodge -Stanford Group Company

Most of my questions are answered, but why don't I just, JimBob, let me ask you about: the timing for the Blueberry Hill sidetrack, andwhether Chevron is signing on for their portion?

Jim Bob Moffett

Philip, since we just really basically have completed theMound Point South well, we moved that rig off location less than three weeksago. I don't know what their understanding is. I met with them a couple oftimes.

I think they agree in general with what I have said abouthow the area is affected by the information on sand distribution, but I can'ttell you what they will do when we propose the operation and we will be lookingat budgeting that.

As I said, we're going to focus our money for the next yearon the Flatrock development, south Mound Point development, Blueberry Hill, andJB Mountain deep. We need to find, as you see on page 18, our power slide 18,we've got a big stipple area on Flatrock, we think we need to find the flatrock at Blueberry Hill, and JB Mountain deep, if it exists.

And at Mound Point, as big as that structure is, it's a twinstructure to Tiger Shoal, which is the Flatrock deeper pool. And so some timeduring the next four quarters, we hope to be able to get a definition onBlueberry Hill, Mound Point, and get the development done at Flatrock. So, Ihope that answers your question.

Philip Dodge -Stanford Group Company

Yes. It does, sir. Thanks very much.

Operator

Thank you. Our next question comes from the line of GaryNuschler, Jefferies & Company. Please go ahead with your question.

Gary Nuschler -Jefferies & Company

Thanks, good morning. Got a couple of non-technicalquestions: First off, you gave us 1P reserves and 3P reserves from your reservereport: can you give us what 2P reserves are?

Jim Bob Moffett

Kathleen, have you got that list in front of you?

Kathleen Quirk

Yes. Just one second and I'll pull that up.

Gary Nuschler -Jefferies & Company

Okay. The second question was also related to the reservereport. Can you tell us what CapEx was associated with the proved reserves?

Jim Bob Moffett

You're talking about: the CapEx to develop the rest of theproved reserves?

Gary Nuschler -Jefferies & Company

Yes.

Jim Bob Moffett

Just one second. Let's not come off the top of our heads.

Gary Nuschler -Jefferies & Company

You want me to go ahead and ask the third question?

Jim Bob Moffett

We'll get the development cost associated with the provedreserves and RS, and the 2P number, we'll get it for you. Go ahead with yourthird question.

Gary Nuschler -Jefferies & Company

Third question: you've got $200 million listed for CapExnext year. Can you give me some kind of breakdown between exploration anddevelopment? And in particular, I'm trying to figure out: how much you guysplan to spend to develop the conventional production from the Newfield assets,develop and maintain that production?

Jim Bob Moffett

Right. There is probably $50 million or $60 million at leastthat will be required. We're reviewing all of the expenditures on Newfield'sproperty. All those leases are held by production, and because of thecombination of the Newfield and McMoRan properties, especially some of thesedevelopment things that have popped up with this Flatrock and Hurricane Deepand Mound Point South well, we have to look at our hold card and see where wecan get the biggest bang for the buck.

In other words, if we only had the Newfield properties tolook at, we have one budget, but as we start to see these other opportunities,we may be able to delay some of the expenditures on the Newfield propertiesthat we can spend at Flatrock, Mound Point, et, cetera, where we have a chanceto drill a well that might flow 30 million to 100 million a day versus drillinga well that might flow 3 million to 10 million a day, if you follow what I amsaying.

Gary Nuschler -Jefferies & Company

Absolutely, absolutely.

Jim Bob Moffett

So, we will be hydrating our opportunities and trying to seeif we can get the biggest bang for buck that would add the most reserves andthe most daily production, and that's where we will spend the money.

Gary Nuschler -Jefferies & Company

Okay. And my last question, you said, I believe, Petrobraswas drilling the Scorpio well. Who is drilling El Dorado?

Jim Bob Moffett

BP is going to drill. It's an announced location, have notspudded the well yet.

Gary Nuschler - Jefferies& Company

Okay.

Jim Bob Moffett

That's in High Island,about midways in High's track, and you see it on the map. Let's see, we got iton a slide here. Just have to thumb through it.

Gary Nuschler - Jefferies& Company

On slide 25?

Jim Bob Moffett

On slide 25. So that location has been announced, and Ithink BP is getting their act together now to spud that sometime in the fourthquarter.

Petrobras, as I said, last scout report I saw, they werebelow 19,000 feet and having some mechanical problems fishing, but they are ontheir way to 25,000; the El Dorado well will be drilled at 28,000.

Gary Nuschler - Jefferies& Company

Good deal. Those were all the questions I had.

Richard Adkerson

Hey, Gary, this is Richard. That CapEx number, what we havein there right now for exploration for next year is $65 million. But as I saidand Jim Bob, indicated that that's a number that will change as a result of theopportunities that we have. But to be precise, in the number right now thatyou're seeing: is $65 million exploration.

Kathleen Quirk

And on the…

Gary Nuschler -Jefferies & Company

Okay.

Kathleen Quirk

The question about the 2P reserves, we had 409 of 1Preserves. And in addition to that, we have probables and it's listed on page 4,the slides just under 80 Bcf on the Newfield properties, and a similar amounton the McMoRan property. So you could add roughly 160 to the 409 to get to 2P.

Gary Nuschler -Jefferies & Company

Okay.

Kathleen Quirk

In terms of the capital expenditure details that are in theproved reserves estimates, I do not have those, right in front of me. But wecan follow up on that.

Gary Nuschler -Jefferies & Company

Yes.

Kathleen Quirk

The PV numbers obviously are reflected, we reflect(Technical Difficulty) capital on there.

Gary Nuschler -Jefferies & Company

Okay, I'll give you guys, a call offline. Thanks a lot.

Richard Adkerson

And we'll include it in our 10-Q so everybody has access toit.

Jim Bob Moffett

Let me just expand the question that was just asked aboutthe Petrobras and the El Doradowell and the reentry of the Blackbeard well by us. All three of thoseprospects, because of the size of the prospects, compare in service area, ifyou look at slide 24, to the big prospects that are being developed like theTahiti Tonga complex and the Mad Dog/Puma complex; even the K2. And just to theeast of the slide we needed the map, tried to not make it too busy, is the bigAtlantis field that's being developed by BP and BHP. And if you look at thosefields, as Richard was pointing out to you, you'll see in black on that slide,the Tahiti leases were bought for less than $1 millionin the 1996 and 1998 bidding.

And the K2, which was a huge field,in 1989 they bought it for a $150,000. And if you look at the bids that tookplace in the October sale, they ranged from $22 million to $90 million for $5an acre. These tracts that they're bidding on by nature are the smaller tracts,still big structures, but generation two bidding and that's why they weren'tbought in the first lease sale.

So, the fact that these things have now become productive atTahiti and Knotty Head and Mad Dog and people know thatthey're oil and thick sands, these are the kind of dollars they're fetching.When you go to the Blackbeard up in that inset, just to the upper left, it'sthe same size as the bigger complexes out there, as is the Robert Private Deer andEast Breaks prospect that we can show. Who knows what those properties wouldbring in a bid, if you went into a bid?

And they were available today, because all of the deepwater foldbelthave the economics of deepwater infrastructure developments. And the threeplays we have, even East Breaks is in shallower water than the 4,000 to 6,000foot depths. And so you've got some tremendous opportunities here as a resultof people's perception of these foldbelt plays.

Gary Nuschler -Jefferies & Company

Okay.

Operator

Thank you. Our next question comes from the line of GeorgeFroley of Froley Investments. Please go ahead.

George Froley -Froley Investments

Hi, boys. What a morning?

Jim Bob Moffett

Good morning.

George Froley -Froley Investments

How are you guys?

Jim Bob Moffett

Great!

George Froley -Froley Investments

A couple quick questions: Can Chevron or Plains drill inFlatrock for themselves? Or: is it like one unit? Or: how is it organized?

Jim Bob Moffett

We have an operating agreement, George, and in an operatingagreement if one of us proposes a well, you have to have 51% the people toapprove the well. And if you don't participate, you're out on what they call anonconsent clause, which I think in this area is about 800% penalty in the OCS,and on 340 about a 600% penalty.

But, to answer your question, the three of us as operator,three of us as working interest owners, and in some instances, Palace who wasour original partner here in El Paso, who also drilled some wells with us inhere. Any of the parties that are subject to the operating agreement on this200,000 acre of master agreement with Chevron, can propose a well at any time,and the other partners have to either participate or nonconsent.

George Froley -Froley Investments

Okay. Have any of the other partners wanted to drill a well?

Jim Bob Moffett

Excuse me?

George Froley -Froley Investments

Has Chevron or Plains wanted to drill a well?

Jim Bob Moffett

Have they wanted to drill a well?

George Froley -Froley Investments

Yeah.

Jim Bob Moffett

Only the ones that you've seen proposed here.

George Froley -Froley Investments

And those were all together with the same three partners andthe same mix?

Jim Bob Moffett

Yeah. And they have not proposed any other operations otherthan the ones we've talked about it. By the way, just talking about Mound Point340 and OCS 310, there was also a state lease sale in October. And offset tosome of the leases in the state tract 340, where Texaco/Chevron didn't hold theacreage, they were some of the few tracks that were put up for bid. We bid andwe got a couple of them.

But on our data, at least, they're off structure on MoundPoint, and on Lighthouse Point south, which is to the north of the Flatrock.And just as another indication of what people are willing to pay for leases inthis area, in 10 feet of water, the bonuses that were bid, that were the highbid were $2500 an acre, and a quarter royalty to the state. So just anotherindication, George, and group on the phone, that the Dead Seahas become the Gulf of Mexico again overnight!

George Froley -Froley Investments

Wow, that is super! My last question is: is it reasonable toexpect to drill on Blackbeard in the first quarter? And, if you do, what kindof rig will you use? Will you change what was going on there before?

Jim Bob Moffett

No. The rig that was on location, one of the Gorillas, wascapable of going deeper. One of issues that they had was they needed a 20,000pounds treat, 20 plus 1,000 pound treat, and [blow up] better situation. Theyweren't happy with what they had. And that was one of the considerations or thereason why the well was mechanically abandoned and D&E. And what all theother things that went on in the operator's head, they're the only ones thatknow.

But our analysis, based on the other wells that are beingdrilled that we've been talking about, I mean: they're drilling wells in the foldbelt,Miocene deepwater foldbelt to below 34,000 feet. So we'll see, George. We'regoing to beef up the surface blowout preventer stacks and et cetera, and we'regoing to go in here. This well we think can be drilled with 18.5, 18.6 mud. Butyes, if we can get everybody together and get the rig situation, we hope to bestarted by the first quarter of 2008.

George Froley -Froley Investments

Okay. Thanks a lot, you guys.

Jim Bob Moffett

Thanks, George.

Operator

Thank you. There are no further questions at this time.

Kathleen Quirk

Thanks, everyone, for your participation. We're availablewith any follow-up questions, and we look forward to reporting to you as we goforward.

Jim Bob Moffett

Thanks, everybody.

Richard Adkerson

Thanks a lot.

Operator

Ladies and gentlemen, that does conclude the conference callfor today. We thank you for your participation and ask that you pleasedisconnect your line.

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Source: McMoRan Exploration Q3 2007 Earnings Call Transcript

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