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McMoRan Exploration Co. (NYSE:MMR)

Q3 2007 Earnings Call

October 19, 2007 10:00 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 to the McMoRan Exploration Third Quarter 2007 Conference Call. During the presentation, all participants will be in a listen-only mode. Afterwards, 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. Please go ahead, ma'am.

Kathleen Quirk

Thank you and good morning, everyone. Welcome to the McMoRan Exploration third quarter 2007 conference call. This is an exciting time for McMoRan as we report on our first quarter of results following the acquisition of the Gulf of Mexico shelf properties from Newfield during the third quarter.

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

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

Before we begin today's comments, I'd like to remind everyone that today's press release and certain of our comments on the 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 with me today are McMoRan's Co-Chairmen, Jim Bob Moffett and Richard Ackerson. I'll make a brief summary of our results, and then turn the call over to Richard, who will be reviewing the slide materials posted on the website, and then we will open the call for questions.

Today, McMoRan reported a net loss of $52.2 million, $1.50 per 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 results include the acquired Newfield properties beginning on August 6th, 2007. The results of the acquired properties from the July 1st, 2007 effective date through the closing date are reflected as purchase price adjustments on McMoRan's balance sheet.

Our net loss from continuing operations for the third quarter of 2007 totaled $51 million. That included $37 million in exploration expense, comprised of $12.5 million for the acquisition of seismic data related to the acquired Newfield acreage and $20.4 million for nonproductive exploratory well costs, primarily associated with the Caswell at South Timbalier Block 98.

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

As we previously reported in connection with the acquisition of the Newfield properties, we entered into derivative contracts to hedge approximately 80% of our estimated proved producing volumes for the period from 2008 through 2010 through a combination of swaps and puts.

Our third quarter revenues include the acquired properties, as I said, beginning on the August 6th closing date. The oil and gas revenues totaled $131 million compared to $57.8 million during the third quarter of 2006. Since the August 6th closing date, the Newfield properties contributed $95.4 million of oil and gas revenues to McMoRan, and for the full third quarter, since July 1st, the Newfield properties generated oil and gas revenues of $164.3 million.

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

On a pro forma basis, our production averaged 289 million cubic feet equivalents per day, and that included just over 240 million cubic feet equivalents natural gas per day from the Newfield properties since July 1st, and 48 million a day from legacy McMoRan properties. This was slightly below the previous estimates that we reported of 300 million a day, primarily as a result of the exercise of preferential rights associated with one of the acquired properties.

Our third quarter realizations for gas were $6.17 per Mcf in 2007. This compared with $6.51 in the year ago quarter. And for oil, we received an average of $75.08 per barrel in the third quarter of '07 compared with $65.11 in the year ago period.

I would now like to turn the call over to Richard, who will be 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 us having completed the Newfield acquisition. As Kathleen said, we closed that transaction on August the 6th. The effective date for transferring production was July 1st. Big expansion of scope of operations in the area of our operations, very attractive economics on the acquisition, and importantly, a significant addition to our acreage.

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

In Flatrock itself, we saw eight productive sands that had 260 feet of indicated pay by wireline tests. There were five Rob L sands and three Operc sands in the Miocene section. And this indicates production over a significant area of a very large structure, and we're going to be very aggressive in drilling follow-on development exploitation and exploration wells in this area. I'll be talking more about that.

The second thing we want to focus on is something that we saw in the acquisition of Newfield, and it was in addition to the attractive economics of our acquiring the production. But the fact that we were acquiring such a significant acreage position that provided further exploitation opportunities in the traditional shelf production, but also the opportunities for deep gas drilling that was consistent with our strategy that we've been following since 2000.

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

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

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

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

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

Significantly, we acquired acreage of substantial size and scope on the shelf of the Gulf of Mexico, over 1.25 million gross, 0.5 million acres net to our interest. And this adds significant value to this acquisition beyond just the production reserves. But the reserves themselves provide good economics based on the outlook for oil and gas prices and 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 a very attractive rate of return on the investment that we put into the reserves themselves.

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

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

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

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

(Technical Difficulty) growth and expansion of our business is shown on the charts on page 6, where we show our reserve growth over the years, our production growth, and the success that we've had with our deep gas exploration drilling in terms of the successful numbers of wells that we have commercially completed and the ones that we've drilled and tested.

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

Page 8 has some important information about how we're going to be running the company. It shows our 400 Bcf equivalent reserves. Our proved developed producing reserves are roughly a third. We have significant amounts of non-producing behind pipe reserves and undeveloped reserves. And we'll be working very diligently to bring these reserves into the producing categories (Technical Difficulty) properties as Newfield has been operating on them, and we're really focused 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 significant the 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. Our existing McMoRan acreage is in yellow, the Newfield acquisitions in red, and then the ultradeep leases that we acquired from Newfield, which are shelf leases, drilling to sands that are deposited beyond the 25,000 foot area that we've been drilling in our deep gas play. But this has exploration characteristics that are similar to the deepwater plays that have been so successful for the industry, and it's an important additional opportunity for us. 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: "Food For Thought." And this makes the point that I referred to earlier. At the time we were looking at the possibility of acquiring properties in the Gulf of Mexico, and when we made the Newfield acquisition, there had been an extended period of time of companies moving away from the shelf of the Gulf of Mexico, and from the Gulf of Mexico generally.

The movement of the larger companies to deepwaters to foreign areas, and of independent companies away from the Gulf to Mid-Continent areas was something that had been well established and had reflected the fast depletion of properties in the Gulf and the challenges of maintaining production, given the extent of the exploration that had been done in the traditional area.

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

It was the second largest sale in MMS history. It is the biggest sale in 24 years. And when you look at the amount of capital that was exposed, the amount of the successful bids and these bids extended from shallow water to deep gas plays and to deepwater plays, you saw something that was 6, 7 times 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. And you have to go back more than 20 years to see similar types of capital being exposed in the Gulf of Mexico when, of course, there was only drilling done on the shelf at that point.

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

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

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

Through subsequent lease acquisitions, we have established 150,000 acre position. We had had success drilling prospects on 217, in prospects that we called Hurricane prospects, where we had drilled four wells on Block 217, and including the Hurricane Deep prospect, which we've recently tested and expect to bring on stream in the fourth quarter.

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

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

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

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, Lighthouse point fields were developed historically, with multi-trillion cubic feet production at shallower areas above 15,000 feet. The rights to this acreage were originally acquired by Texaco in the 1940s. It spans federal waters and state waters, and so we have federal leases now as well as the state leases at the Mound Point area. And it's looking for the deeper pool depositions of production associated with these structures that were so prolific at shallower depths is what is the philosophy that drives us.

Page 15 shows our historical drilling there, our first well we drilled in the Mound Point area, and that was followed up with discoveries in the JB Mountain area in OCS 310. And now we are continuing to use the information that we've learned through the extensive amount of wells that we have drilled and our better understanding of geology to pursue further opportunities. And that's what led to the very significant Flatrock discovery for us.

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

On page 17, we show the recent exploration well that we drilled 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, which was a Mound Point well, in that as we were drilling deeper we saw large well developed sands.

Sand development is the principal exploration risk for deep gas drilling. And our team was very excited about the quality of the sands that we saw. Again, in drilling this well, where we saw 15 feet of net pay, we were then again saw well developed sands, which gives us the encouragement to go forward and find the areas in this deposition of where we can find significant production.

Page 18 shows the potential that we see in graphic form from this area. The traditional production fields are shown at Tiger Shoal and Mound Point. You see with the cross lined areas, the productive areas that we've seen to-date with our drilling. And the potential is shown in the shaded areas that lie at depths below Mound Point and associated with the JB Mountain, Blueberry Hill. 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 exploration well drilling at Cottonwood Point. It's located at Vermilion 31, shallow water 5,000 plus acre lease block, big potential. We've seen production as we were drilling at a higher horizon, but with wells at 19,000 feet, targeting to go to a total depth of 21,000 feet.

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

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

You feel like other traditional Gulf explorers were not focused on these, because of the absence of bright spots and the challenges in drilling them. But what we've acquired through this acquisition is now the opportunity to look for these deeper depositions. Our exploration team had begun that process, and we see a number of very interesting prospects that we're going to be pursuing, again, very consistent with our philosophy that we've been following prior to the acquisition of Newfield.

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

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

Blackbeard prospect is the initial prospect that Newfield and its partners were testing. They drilled a well which did not reach its objectives, but went below 30,000 feet, which they temporarily abandoned for operational reasons.

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

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

The first one we're focusing on is the Blackbeard ultradeep project, page 23. The details are shown. It's in South Timbalier Block 168 in 70 feet of water. As I mentioned, the original operator and partners drilled below 30,000 feet. They did encounter sands that were gas bearing, but they failed to reach the primary target, and they abandoned the well in 2006.

But the drilling results that they saw confirmed the geological model and thesis that was led to the prospect being tested. Jim Bob and our team has been reviewing this, and it's our intention to deepen this well to 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 of prospects can be seen on page 24, when we looked at the historical amounts that were paid in the deepwater for these type of prospects compared with what's recently been paid in lease sales. Where at one point leases could be acquired for $1 million a block or less, today, lease blocks are going for substantially higher amounts, $20 million, $50 million, $70 million. And again, it just illustrates that with the success that's occurred in testing the similar types of prospects that we have with our ultradeep play, that the values the industry sees 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 substantial lease blocks in the Western Gulf, the Roberts 95,000 gross acreage and East Breaks, which is a continuation of the Wilcox type sand deposition that was seen in the Jack deepwater well.

Industry is drilling wells in this region to depths of below 20,000 feet. It's going to provide us with important regional geological information to help us as we continue to assess the opportunities for drilling in the Western ultradeep plays for us.

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

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

Our fourth quarter outlook, as I mentioned earlier, and Kathleen mentioned, provides an outlook for our 290 million a day of average production volumes, including 230 million from acquisitions from Newfield. It does 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 of the fourth quarter.

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

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

You can see the sensitivity to prices. That's substantially higher than our capital spending. And then we will be using that cash flow in excess of our capital spending to delever. And with the market that we have for commodity prices, we should be able to de-lever very quickly as we show on page 29.

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

What we're in this for is exploration. That's what McMoRan is about before, and that's what we will continue to be about. On page 30, we've tried to demonstrate just what is the leveraged exploration that we have available to us with the kind of projects that we're pursuing. And we're using Flatrock here as an example.

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

Now, when we have the Newfield prospects, we won't have to farm 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 traditional production, 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. But what we have now with Newfield is a very substantial amount of acreage with traditional amounts of production and the ability to pursue themselves without farming it.

In today's world we see others paying very significant amounts, of course, with the recent lease sales to acquire leases, to pursue these types of things. And again, we want to make a point that we believe we've gotten additional value in the Newfield deal beyond what we paid for it, just for the reserves.

We continue to pursue our commercial arrangements for our Main Pass Energy Hub. We have the permits in place now to develop a major LNG receiving facility to build a pipeline into north into the Alabama area to connect into the US gas market. We have the onsite natural gas storage caverns, which make this an attractive project. The location of the Eastern Gulf of Mexico also makes it attractive. And our issue now is to find in a competitive world supply for this project.

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

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

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

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

Question-and-Answer Session

Operator

(Operator Instructions)

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

John Herrlin - Merrill Lynch

Yeah. Good morning. I have a bunch of well related type questions. With Flatrock, Richard, you said end of the quarter in terms of hooking 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 to have that before our earnings call. But just in terms of getting the equipment and so forth in place, we will have that well tested, and we will be disclosing results of that test in a matter of days.

Jim Bob Moffett

John, this is Jim Bob. What we're doing is completing the Operc sand at 17.2 in that well. It's the second biggest sand in the well. The thickest sand, as we've reported, is up to 15,000 feet, which is the 260-foot sand, about 370 feet gross. The reason we did that was since the Operc was the deepest and second biggest there, we can twin the well to get the shallow 115,000 feet cheaper than we could have trying to twin the Operc.

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

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

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

The thicker Rob L sand, the 260 foot zone, we believe will flow somewhere between 75 million and 125 million a day based on similar flows in the area and have a condensate ratio of 30 to 40 barrels a million. So those are 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 that have exhibited high flow rates from similar sands.

John Herrlin - Merrill Lynch

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

Jim Bob Moffett

Say that again, John?

John Herrlin - Merrill Lynch

With Mound Point South, there was something in the release about 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 we don't have any corrosion from the H2S, CO2. We had to do the same thing for the Hurricane Deep well, which we just moved back on and completed in the Gyrodina sands. So that's the reason for the special tubular goods.

In the South Mound Point well, John, it's very similar to the Hurricane Deep well. Hurricane Deep well is part of the Flatrock, Hurricane structure, which is the deeper pool of Tiger Shoal. Mound Point South is part of the deeper pool of Mound Point, which is the next structure to the east. And in that well, the reason why I compared it to the Hurricane Deep, we were drilling the well, started in the middle of our grid that we drilled in this area, and we had over 2,000 feet of sand in the Operc, Gyrodina as potential reservoir. We just had one of the sands that was hydrocarbon bearing. It looks like we just need to move a bit, similar to what we found at the Hurricane Deep situation, when we moved to the north on Flatrock.

But we think that because of the fact that we got Operc production just to the north of the Mound Point South well in the El Paso Number 1 well that's been on production for four years. And our first well that we drilled, that mechanically couldn't be completed, but had pay in the Gyrodina to the north of the Mound Point South, that this big core deeper pool of the 2.5 Bcf Mound Point field. We got to get the sweet spot, and that's what the map showed, cross-hatched acreage shows that we've gotten another entry in cubic foot potential.

And the reason we feel that there can be a Flatrock of Mound Point is these are twin structure shallow, they ought to be twin structures deep. And we've now seen Operc and Gyrodina pays on the flank of it. So the Mound Point South well also gives us a lot of confidence in this Blueberry Hill prospect to the South, where we drilled and have the multiple pays that were very thin, and we couldn't get a commercial flow rate out of them. We're going to 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 a clear indication that the big Blueberry Hill structure must have had so much vertical relief that it kept these big sands from getting all the way on top of the structure. But you have this strong north and northwest dip that we've shown before, and the sands that we see in Mound Point South should make it down to the flank. Obviously, we're going to have to drill to prove it.

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

I think those two wells have produced just under 100 Bcf already. So, as you can see, we're starting to get the area here, sand development defined. And as we finally zeroed in and pinned the tail on the donkey at Flatrock, we believe we've got that opportunity to do it on these other major structures in this mini basin that represents the deep core of Tiger 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 choke in that well.

Jim Bob Moffett

Well, it was a limited test because we had the rig on location. The 15 million a day rate, we had almost no drawdown. It flowed 12,000 pounds of pressure. And you could open it up to 15 million, and the flow at 11.8, which is almost no drawdown.

I think if we do that, as you know, in that zone we had that 900 foot sand with about 100 feet gross above water, 50, 60 feet net. So we'll be somewhat cautious about going to a rate to cone that water in. We feel based on the Flatrock well that we will be able to get it higher to the West and the South on this zone, and pick it up another 100, 200 feet out of water. In those wells, we can flow a little bit more aggressively.

But, to answer your question, we will expand that. That well should come on like our Flatrock well in the fourth quarter. We will expand that with us when we get it on production. What we generally try to do is to not 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 that we produced net wells, 44 million a day with 11,800 pounds of pressure and about 1,000 barrels of distillate. The shut-in pressure on that well is only 1,000 pounds higher. So we're flowing 44 million a day out of the zone at 19,000 feet Miocene zone with just almost less than 10% drawdown.

The qualities of these rocks, John, with these pressures, is pretty damn impressive as far as getting the high flow rates. Long Point to the northwest 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're flowing at a combined rate of just under 60 million a day.

So, I think we've convinced ourselves and everybody must be getting convinced about the characters of the rock. As you know, when we first started this deepwater shallow deep gas play, a lot of people were concerned about the quality of the rock. We've said based on the onshore production in the Hollywood sand and some of the stuff at Lake Sands and Pecan Island to the north, that we didn't have any concern about regarding 3-D type deep Miocene sands, because they had proven production characteristics. I think that's been pretty much confirmed by the drilling that we've done along this trend right on the edge of coast and into the water.

John Herrlin - Merrill Lynch

Great! Last one for me is on Blackbeard: Any issues with the MMS in terms of extending the leases? And: have you had other companies talk to you 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 to continue each year to be drilling another well or shooting significant seismic to continue to outline the play.

On that situation, as the map showed, the Blackbeard well was drilled just about to the top of the Miocene. It's got 9 and 5 H casing at 28,700 feet. It's been D&E. We've seen it flow and we're going to move back on it, and we'll clean out the cement plugs and go in. And we believe we can make about 1500 feet a hole on 3-D seismic guys to the 90 head of Mad Dog Tahiti complex.

The Miocene sands are exactly equivalent in terms of biostratigraphic position 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 the west, on the Robert and [Private Deer] play, where we have the 95,000 acres, BP has 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 a substantial acre position, over 40,000 acres. And south and west of that in North Padre Island, Petrobras is currently drilling a well that they're trying to go to 25,000 feet; I think there's about 19,000 feet right now. Both the El Dorado and the Scorpio well, which is the Petrobras well drilling in North Padre Island, their objectives are the Eocene or Yegua and Wilcox, which is 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 deepwater foldbelt play, you have an eastern region deep Miocene play and the sands get older into the Wilcox, Yegua. As you move to the west into deepwater, you have a mirror image of that on the shelf. So, in those plays that we have in terms of Blackbeard, Robert Private Deer and the East Lakes acreage, these are huge structures. They cover more than 20,000 acres of closure, and have the potential of 3 to 5 Tcf for prospect.

And, of course, as we've seen in the deepwater, in the Miocene and the Jack, they're finding oil. So either 300 million to 500 million barrel potential of oil, or a 3 to 5 Tcf potential of gas gives us some big exposure on that foldbelt play, as it has been called, in the Miocene/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 JP Morgan.

Brian Kuzma - JP Morgan

Good morning, guys.

Jim Bob Moffett

Jim Bob Moffett

Good morning, Brian.

Brian Kuzma - JP Morgan

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

Jim Bob Moffett

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

Brian Kuzma - JP Morgan

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 - JP Morgan

Okay.

Kathleen Quirk

Jim Bob, it was $24 million, roughly, was the exercise price. 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 the sale, we historically not many people had exercised their pref rights, but in this case this one did.

Brian Kuzma - JP Morgan

And then, looking forward, on those Newfield properties, you guys are basically forecasting production to be flat quarter-over-quarter. How realistic is that?

Jim Bob Moffett

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

The interesting part about marrying these two plays up is if we're successful as we hope to be in the deep play, because of the high flow rates we're talking about, one of these deep Miocene wells can replace the production from 5 of the 12 pricing wells, because they generally have an average for the flow rate of 5 million a day, some as low as 3. Every once in a while 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 up now, as we put these two portfolios together, one of these Flatrock wells that flow at 40 million to 100 million a day, you can see we replace a lot of daily production. And so that's why Flatrock and Hurricane and Mound Point South and Laphroaig have been so important to us since the Newfield deal was closed that we believe with the deep Miocene wells and the high flow rates that we're experiencing and have confirmed, we can replace a lot of those wells and flatten out the decline curve. If we do that, then we've hit the home run.

Brian Kuzma - JP Morgan

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

Jim Bob Moffett

Well, of course, there's a huge infrastructure there. The oilfield had two big production facilities, one at Tiger Shoal, one at Mound Point. It's produced 6 Tcf. They are upgrading it every day. And, of course, this is an important prospect, not only to us, but to Chevron, who inherited this property in the Texaco sale. And so, the structures are in place. The big concrete structures, if you've ever been out there, it looks like two huge islands. 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 substantial hydrocarbon, heavy hydrocarbon dip condensate in it. So, you have to put processing. You have to keep increasing the processing size so you can basically get that gas, temperature and pressure down so you can get the condensate to fall out. And so, they've already started, the Chevron people, on those facility improvements. And by the middle of 2008, we're shooting 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, and that's all been the process so that we can get the gas out of the field. But in terms of capabilities, as I say, these structures that you set these facilities on are huge. And the pipeline systems that exist immediately north and south of us, the big pipelines that go in onshore, we have no problem finding home for 500 to 1 Bcf a day. And those are the kind of numbers that, you know, assuming these offsets are as good as we think, they can be with these multiple sands that's the kind of numbers we're looking for.

Brian Kuzma - JP Morgan

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

Jim Bob Moffett

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

Brian Kuzma - JP Morgan

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

Jim Bob Moffett

That's correct.

Brian Kuzma - JP Morgan

Development wells, okay, they are.

Jim Bob Moffett

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

Brian Kuzma - JP Morgan

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 will head.

Brian Kuzma - JP Morgan

Okay.

Jim Bob Moffett

And as far as the reserves are concerned, Brian, as we've shown everybody and said, this is a very flat structure, albeit the Flatrock name. And on geophysics, it appears that these locations that we're drilling should 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 lateral continuity.

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

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

But, if we have three wells, and obviously some of the probable and possible reserves that are reported by Ryder Scott, we'll move into proven category. So, we hope to have substantial opportunities to move 150, 200 Bcf of gas in the proven category that's currently considered to be probable undeveloped. But, we've got to get these sands drilled and see if they have the lateral extent. With eight of them, we feel confident that this is a major trapping structure. So, you've got flat structure and thick sands, and that's where you get your volumes.

Brian Kuzma - JP Morgan

Got it. One last one for me is: when you think about Hurricane Deep and Mound Point South, when you guys have found some pay and there'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's talk about Hurricane Deep for just a minute. If you look at the slides, where we talk about Flatrock, we've shown there that the Hurricane Deep and Flatrock prospect really become one development plan.

With the wells to the North being the Rob L and shallow Operc, and then you get in the middle, you get Rob L and deep shallow and deep Operc. And then, by the time you get to the south, you're into the deep Operc and Gyrodina. The deep Hurricane well has a play in the Gyrodina that we completed the John (inaudible) well we were just talking about. But it also, at 18,300 feet, has an Operc pay.

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

Brian Kuzma - JP Morgan

Throughout '08, yes.

Jim Bob Moffett

And: what does that mean? That means: we could have four or five 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 see Hurricane Deep in 217. Remember, these blocks are three miles wide. So, there's about three miles of area between the two wells. And you have the 18.3 Operc sands in both wells.

Now: how's that well to the south going to look? Is it going to confirm that those things are connected on that three-mile area? And of course, the Hurricane Deep has the Gyrodina, which is faulted out of the Flatrock well. It may be faulted out of the well to the south. But as you move just 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 one structure if we've got it figured correctly, and it will all be part of the same big development program to develop these multiple sands.

Brian Kuzma - JP Morgan

Okay. And then with Mound Point South, the big takeaway here should 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 go up-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 of Hurricane Deep, and about five miles north of Blueberry, three miles south of the closest well at Mound Point.

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

So, if you go up-dip to the Mound Point South well to the east, directly offsetting it, we believe that you can pull more of those sands out of water. And those sands are so thick that if you have 500 acres of one of these 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're saying is, that if you look to the west of Blueberry Hill, the JB Mountain well, which has been on production for about four years, it had 2,000 feet of sands in the Gyrodina.

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

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

So I tried to draw that pink area on slide 18 to show what the 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, down dip that way you've got another half a Tcf.

And the point here is: you've got to have these big, thick sands 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't have a fault, or some big structure that impacts it, then you're going to have these big Gyrodina sands, and Operc, for that matter.

Brian Kuzma - JP Morgan

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, Jim Bob, let me ask you about: the timing for the Blueberry Hill sidetrack, and whether Chevron is signing on for their portion?

Jim Bob Moffett

Philip, since we just really basically have completed the Mound Point South well, we moved that rig off location less than three weeks ago. I don't know what their understanding is. I met with them a couple of times.

I think they agree in general with what I have said about how the area is affected by the information on sand distribution, but I can't tell you what they will do when we propose the operation and we will be looking at budgeting that.

As I said, we're going to focus our money for the next year on the Flatrock development, south Mound Point development, Blueberry Hill, and JB 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 flat rock at Blueberry Hill, and JB Mountain deep, if it exists.

And at Mound Point, as big as that structure is, it's a twin structure to Tiger Shoal, which is the Flatrock deeper pool. And so some time during the next four quarters, we hope to be able to get a definition on Blueberry Hill, Mound Point, and get the development done at Flatrock. So, I hope 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 Gary Nuschler, Jefferies & Company. Please go ahead with your question.

Gary Nuschler - Jefferies & Company

Thanks, good morning. Got a couple of non-technical questions: First off, you gave us 1P reserves and 3P reserves from your reserve report: 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 reserve report. 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 the proved 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 proved reserves and RS, and the 2P number, we'll get it for you. Go ahead with your third question.

Gary Nuschler - Jefferies & Company

Third question: you've got $200 million listed for CapEx next year. Can you give me some kind of breakdown between exploration and development? And in particular, I'm trying to figure out: how much you guys plan 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 least that will be required. We're reviewing all of the expenditures on Newfield's property. All those leases are held by production, and because of the combination of the Newfield and McMoRan properties, especially some of these development things that have popped up with this Flatrock and Hurricane Deep and Mound Point South well, we have to look at our hold card and see where we can get the biggest bang for the buck.

In other words, if we only had the Newfield properties to look 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 properties that we can spend at Flatrock, Mound Point, et, cetera, where we have a chance to drill a well that might flow 30 million to 100 million a day versus drilling a well that might flow 3 million to 10 million a day, if you follow what I am saying.

Gary Nuschler - Jefferies & Company

Absolutely, absolutely.

Jim Bob Moffett

So, we will be hydrating our opportunities and trying to see if we can get the biggest bang for buck that would add the most reserves and the 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, Petrobras was drilling the Scorpio well. Who is drilling El Dorado?

Jim Bob Moffett

BP is going to drill. It's an announced location, have not spudded 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 it on 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 I think BP is getting their act together now to spud that sometime in the fourth quarter.

Petrobras, as I said, last scout report I saw, they were below 19,000 feet and having some mechanical problems fishing, but they are on their 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 have in there right now for exploration for next year is $65 million. But as I said and Jim Bob, indicated that that's a number that will change as a result of the opportunities that we have. But to be precise, in the number right now that you'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 1P reserves. 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 amount on 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 the proved reserves estimates, I do not have those, right in front of me. But we can 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 to it.

Jim Bob Moffett

Let me just expand the question that was just asked about the Petrobras and the El Dorado well and the reentry of the Blackbeard well by us. All three of those prospects, because of the size of the prospects, compare in service area, if you look at slide 24, to the big prospects that are being developed like the Tahiti Tonga complex and the Mad Dog/Puma complex; even the K2. And just to the east of the slide we needed the map, tried to not make it too busy, is the big Atlantis field that's being developed by BP and BHP. And if you look at those fields, as Richard was pointing out to you, you'll see in black on that slide, the Tahiti leases were bought for less than $1 million in 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 took place in the October sale, they ranged from $22 million to $90 million for $5 an 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't bought in the first lease sale.

So, the fact that these things have now become productive at Tahiti and Knotty Head and Mad Dog and people know that they'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's the same size as the bigger complexes out there, as is the Robert Private Deer and East Breaks prospect that we can show. Who knows what those properties would bring in a bid, if you went into a bid?

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

Gary Nuschler - Jefferies & Company

Okay.

Operator

Thank you. Our next question comes from the line of George Froley 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 in Flatrock 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 operating agreement if one of us proposes a well, you have to have 51% the people to approve the well. And if you don't participate, you're out on what they call a nonconsent 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 was our original partner here in El Paso, who also drilled some wells with us in here. Any of the parties that are subject to the operating agreement on this 200,000 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 and the same mix?

Jim Bob Moffett

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

But on our data, at least, they're off structure on Mound Point, 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 in this area, in 10 feet of water, the bonuses that were bid, that were the high bid were $2500 an acre, and a quarter royalty to the state. So just another indication, George, and group on the phone, that the Dead Sea has become the Gulf of Mexico again overnight!

George Froley - Froley Investments

Wow, that is super! My last question is: is it reasonable to expect to drill on Blackbeard in the first quarter? And, if you do, what kind of 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, was capable of going deeper. One of issues that they had was they needed a 20,000 pounds treat, 20 plus 1,000 pound treat, and [blow up] better situation. They weren't happy with what they had. And that was one of the considerations or the reason why the well was mechanically abandoned and D&E. And what all the other things that went on in the operator's head, they're the only ones that know.

But our analysis, based on the other wells that are being drilled 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're going to beef up the surface blowout preventer stacks and et cetera, and we're going to go in here. This well we think can be drilled with 18.5, 18.6 mud. But yes, if we can get everybody together and get the rig situation, we hope to be started 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 available with any follow-up questions, and we look forward to reporting to you as we go forward.

Jim Bob Moffett

Thanks, everybody.

Richard Adkerson

Thanks a lot.

Operator

Ladies and gentlemen, that does conclude the conference call for today. We thank you for your participation and ask that you please disconnect your line.

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