McMoRan Exploration Company Q3 2008 Earnings Call Transcript

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McMoRan Exploration Company

Q3 2008 Earnings Call

October 20, 2008 10:00 am ET


Kathryn Quark – Senior Vice President, Treasurer

Richard Adkerson – Co-Chairman of the Board

James Moffatt – Co-Chairman of the Board


Nicholas Pope – J.P. Morgan

Noel Parks – Ladenburg Thalmann & Co.

Richard Tulis – Capital One

Brian Kuzma – George Weiss

Kent Green – Boston American Asset Management

Gregg Brody – J. P. Morgan

George Foley – Foley Investments


Welcome McMoRan Exploration third quarter conference call. (Operator Instructions) I would now like to turn the conference over to Kathryn Quirk, Senior Vice President and Treasurer.

Kathryn Quirk

Welcome to McMoRan Exploration's third quarter 2008 conference call. Our results were released earlier this morning and a copy of the press release is available on our website at The conference call today is being broadcast live on the internet and anyone may listen to the call by accessing our web site home page and clicking on the web cast link for the conference call.

We also have several slides to supplement our comments this morning, and will be referring to the slides during the call. They are also available using the web cast link on In addition to analysts and investors, the financial press has been invited to listen to today's call and a replay of the web cast will be available on our web site 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 this call include forward-looking statements. Please refer to the cautionary language included in our press release and presentation materials and to the risk factors described in our SEC filings.

On the call today are Matt Lawrence, Co-Chairman, Rob Moffat and Richard Atkinson. I'll briefly summarize the financial results and then Richard and Jim Bob will review our recent performance and outlook. As usual, after the formal presentation, we'll open up the call for questions.

Today McMoRan reported earnings before hurricane charges and unrealized market to market gains on derivative contracts of $61.9 million, $0.96 per share. After taking into account the hurricane charges unrealized market to market gains on derivative contracts, McMoRan's net loss for the third quarter was $6.1 million or $0.10. That compares with a net loss of $52.2 million or $1.50 per share in the third quarter of 2007.

Our third quarter results included charges of $152.6 million related to hurricane Ike. That included about $22 million to reduce the net book value of property damaged in the storm and approximately $124 million to adjust our future abandonment costs associated with the damaged structure and well abandonment. We also recorded $6 million toward costs for assessments.

We expect to realize a substantial recovery under our insurance program for our hurricane related costs. These are expected to be incurred over several years. Our insurance recovery will be included in our income and future results for claims for settlements with insurance. Our third quarter results also included a gain of $82.3 million, $1.28 per share for unrealized market to market charges on open oil and gas derivative contracts and a $7.4 million charge to preferred dividend in connection with early conversion transaction of $99 million of McMoRan's 6 3/4 mandatory convertible preferred stock.

Our third quarter 2008 production averaged 225 million cubic feet of natural gas equivalents per day, net to McMoRan. That compared with third quarter 2007 averages of 185 million. Our results were impacted by shut ins during September for hurricanes Gustaf and Ike which impacted Gulf of Mexico operations prior to making landfall on September 1 and September 13 respectively.

Prior to the storms, our production in July and August of 2008 averaged about 296 million cubic feet of equivalents per day. Revenues during the third quarter totaled $283 million. That compared with $131 million during the third quarter of 2007. Our gas prices realized in the third quarter of 2008 were $10.67 per Mcf. That was 70% higher than the year ago average of $6.17. Our realized prices for oil in condensate averaged $1.24 per barrel in the third quarter 2008 and that was about 65% higher than the year ago average of $0.75.

Our earnings before interest, tax, depreciation and exploration expenses for the quarter was $211 million and operating cash flows were $254 million. We funded capital expenditures of $76 million for the third quarter of 2008. Year to date the capital expenditures are $187 million.

Our total debt excluding $75 million of senior convertible notes approximated $300 million at the end of September. That was $274 million lower than at the start of the year and $894 million lower than at the time of the August 2007 oil and gas property acquisition. We ended the quarter with no bank debt and had $161 million in cash.

Our shares outstanding currently approximate 70.5 million and fully diluted shares including the conversion of the remaining 6 3/4 mandatory convertible preferred stock approximates $85.7 million.

Now I'll turn the call over to Richard who will be referring to the slide materials on the web site.

Richard Adkerson

If you will turn to the slides, Slide 3 has a summary of the financial information that Kathleen just spoke about. Slide 4 gives information about our hurricane damage and recovery activities. In Ike, we lost six platforms that have significant damage, only representing 2% of our reserves and 3% of our production.

The issue that we're working diligently on is restoring the production from our platforms as well as waiting for our downstream facilities to be restored. You can see the impact on production levels, the little chart on the right. We were having strong production in July and August, averaging 296 million a day. We're now at 140 million a day, working up to an average of 180 in the fourth quarter, and then with our new production from our wells coming on stream with restored production, being back to the 280, 290 level in the first half of 2009.

The cost that we incur to restore properties will be incurred over several years. We'll also be working with our insurance program to get recoveries. That's a complicated process with the way insurance is structured now in the Gulf in recent years, but we do have coverage that will give us a substantial recovery of the costs that we've incurred.

What's going on in the financial markets, Slide 5 is a good slide for us. We were able, since the acquisition of properties in Newfield in August of 2007 to significantly de-lever on the basis of the strong production volumes we had and the strong commodity prices so that we have reduced our debt from August '07 to September 30, '08 by over $1 billion.

We currently have a strong liquidity position that is shown on Slide 6 which shows our total debt including the convertible debt that has a maturity of 2011. You can see we have no maturity payments, no debt principal payments due for many years.

Slide 7 is an update of our major properties that we show at each earnings release. You can see that the properties that have been shut in since hurricane Ike and as I said, we'll be restoring that production just as quickly as we can. Substantial amount of production wasn't damaged including our important production at South Marsh Island 212. This is a summary of where we stand with our property.

Flatrock continues to be an important area for us. We have now three wells currently producing at 170 million a day gross, 32 million to our interest, and number two well is producing at roughly 100 million a day. The number four well is being completed in the primary Lapbroaig sand and it should be capable of producing at rates similar to the Flatrock number two well.

We spouted the number five well the first of July. It is now drilling below 15,800 feet with a planned depth of 18,400. We logged the Lapbroaig pay in October. We will be spreading the Flatrock number six well to test deeper sands at a proposed depth of 19,700 feet and as we've demonstrated, we have the ability to bring on production very quickly in the area because of the historical production facilities there.

Slide 9 summarizes the information that I gave you on the wells that we are drilling in the Flatrock area and obviously since we made our initial discovery there at approximately the same time last summer as we made the Newfield acquisition, this has unfolded just as we hoped it would. Sands with multiple pay intervals, prolific sands are able to produce at high rates.

You can see the location of these sands, these wells on Page 10. This located in the OCS 310 area, South Marsh Island 212 extending down to block to the south, number 217 where we had previously drilled our hurricane deeps discoveries in very shallow water, 10C and it shows the location of the successful wells, how the sand sections are prospective over this area, the Rob L and Operc and Gyro 9 as we continue to define this major discovery.

This is the most recent and the most significant success that we've had in this J. B. Mountain point tiger shoal area which includes OCS 310 and State Waters and State Lease 340 area. We drilled our initial well at Mound Point in the northeast section, then the discovery at J.B. Mountain in the southern part of the prospect and we've now seen over this significant area, roughly 150,000 acres, production in the multiple sand sections.

Of course Flatrock is the most significant but it's not the end of the story of our efforts to explore and delineate the possibilities in this area. That's illustrated on Page 12. The shallow production where approximately 6 trillion cubic feet were fused in the Tiger Shoal Mountain fields above 15,000 feet, shown in red. The areas that we've now proven in the deeper sands are shown with the lined areas and then the whiter color areas are the areas that we see are still prospective and those are significant and will be a focus of our exploration.

We're current drilling a new exploration well called Tom Sauk. Tom Sauk well is currently at 12,500 feet. It's located in the State Waters. Planned depth is 19,000 feet. It is testing sands that are up dip from the well we drilled in Mound Point area last year, number five well in Mount Point south which saw productive sands in the Operc section. This is about 8,000 feet away and testing these sands in an up dip position, a very significant potential reservoir.

You can see how the Tom Sauk well is positioned in relation to the regional geology that's illustrated in the cross section on Page 14. These sections are defined above a big fault system we call the Big Blue Fault which has above it sand sections in the Lapbroaig and the Operc and Gyro 9. You can see the location of this Tom Sauk well in relation to the well we drilled last year, the number 5 well and it is testing these sands which our geology indicates is a more favorable position.

We also have another prospect called Gladstone East. It is also in the State Water and State Lease 340. We're planning to flood this well for the quarter going down below 18,000 feet. Its located five miles east of Flatrock and our seismic analysis indicated to be a Flatrock type prospect located on the western flank of the Mound Point structure. It will target the Rob L sands that we saw to be so productive in Flatrock and also the lower Operc sands. Again, a very significant prospect and will be an important well for us.

The cross section on Page 16 positions this in terms of how this relates to the two big structures that we've been testing, the Tiger Shoal and Mound Point, shallow production. This is a Flatrock type potential feature that seismic indicates is set up by the deposition of the sands in these areas. We've got a really exciting new prospect that we will be drilling, Ammazzo, and I'm going to ask Jim Bob to step in here and talk with you about this prospect.

James Moffett

I thought I'd make a few comments about this Flatrock discovery and the J.B. Mountain discovery you've heard a lot about in this State Track 340 and OCS 310. Just outside of OCS 310 we have had another 5,000 that we farmed in from Chevron, so Chevron, ourselves, Plains and Energy 21 will be drilling this prospect.

The reason it's important is, as Slide 17 shows, there's a blue line with the arrows pointing at a major ridge that runs under the Ammazzo prospect that was responsible for the accumulation at Flatrock and J. B. Mountain. We will see the same raw Gyro 9 section that we've seen there, even possibly some pressured sands which would have been the shallow production above Flatrock.

As you can see on Page 18, the potential productive area covers the entire 5,000 acres. The next Slide 19, we've tried to take that big ridge that I just showed you on a plan view map and do a cross section so you can see how this is evolving since we began this exploration in the OCS 340 region.

The most important thing on the left side of the cross section is you see all of the Flatrock wells, and of course they're producing in both the green, the pink and the blue which is the well known Rob L, Operc, Gyro 9 stratographic equivalent, and then you come across to J. B. Mountain which has been in production for over five years, and it's in the Gyro 9.

You go south of there we have the J. B. Mountain Deep where we have a well that has not yet been completed where we encountered Gyro 9 sand. You move that and you go about nine miles to south of J. B. Mounted on this same ridge associated with the same major fault system which we affectionately refer to as Big Blue. Big Blue has sort of set the foundation for the discoveries that we've had and it appears to do the same thing for at Ammazzo.

If you look at the Ammazzo, we have two locations shown. We actually have staked about four locations. This features one of the largest undrilled features on the shelf and has a footprint that looks almost like some of the other deep prospects we've been drilling. That's one of the reasons we're calling it deep, because it occurs above the Big Blue Fault which is the reason the Fault that we refer to as [inaudible].

Unfortunately, it's still raw. I wish I could tell you how many sands or deposits is down here. It is south of the J. B. Mountain and Flatrock area. Not that we have to wait until we get in there and drill. So the good news is that we don't know how many sands we can expect to be in these various intervals, and the good news is because we don't know how many are there, you can put anywhere from half a trillion to a trillion or more on this prospect because the structure is so big.

So it's a lookalike Flatrock, but in terms of its size, the footprint is about two and a half times the size of the Flatrock footprint and it's at least two times the size of J. B. Mountain. We'll see whether we can extend our success that we've had in these multiple reservoirs.

Just one last point, the green, the pink and the yellow has been so prolific about this area is that the sand section that we have is a window of opportunity. It's over 6,000 feet thick. That's why we've been able to stack these sands. We just have to move around these structures and catch them in the exact right position at different intervals in the green, pink and the blue.

As usual, stay turned. It will be a very interesting prospect for us in this internal. Just briefly on Page 20, you have the N. E. Belle Isle prospect which is drilling below 15,000 feet. It is a prospect which is a lookalike to the Lapbroaig prospect which we completed. It has been on production over a year at 40 million a day. It's what we call a dry feature. We've got some prolific Rob L sands that may be trapped along this fault feature, so stay tuned on that one.

The acreage position that you see, we put in here because I wanted to talk about South Timbalier Block 168, our now infamous Blackbeard well which has been in the news. And of course the Flatrock area to the northwest of it, just to relate to you just how the shallow water shelf plate for the deep gas and the ultra deep plate have such an advantage for us.

If we are successful as we have been at Flatrock, the shallow water depths on the shelf let's you have the ability to complete wells at much less cost in the deep water and we're right in the middle of a pipeline system. We can go on production most of the time within six months or less.

If you turn to the next page, I want to talk a little bit about Blackbeard. I have to be somewhat guarded in my comments for confidentiality purposes with other people in the industry. This is a drilling well and is so significant. It will be the only penetration on the shelf with the exception of wells very deep and in Texas, 100 miles to the west.

This well as you may remember at Blackbeard, is just north of the prolific Green Canyon, Mississippi Canyon, Miocene trend that includes all the big name discoveries, Mad Dog, [Thunder Hart], K2. I could go on and on, new discoveries. 550 feet in depth, Miocene sand so we just get more and more confirmation that the prolific Miocene sands were production on shore, on the delta of Louisiana since the early '50's are all in the deep water.

We're half way between the deep water and the delta so our projections have been that we should have sand similar to the Miocene since it's all in the same embankment. To date, that's about what we've proven, is that we have a normal stratographic section and it's in the so-called Rob L stratographic interval which is identical to the Flatrock Rob L. It's just down depth at 30,000 feet versus 15,000 feet.

So we know this section. We've been in a normal expand shale sequence. We've seen several horizons. Once again, I'm going to be somewhat cautious because of the confidentiality with other operations participating in the well. I tried to show you that we think that we have found beneath the originally drilled depth of 30,000 feet by Exxon, we've drilled into a whole zone that has potential hydrocarbons.

An important part about this cartoon on Slide 23 is that as we've drilled our well, we continue to get information from the deep water Mississippi Canyon, Green Canyon wells, and it's so important because as we explained to you, we're in the same Miocene basin that the deep water wells are in. What we have seen in the sub Miocene, a phenomenon known as wedging or thickening where the sands that are deposited across this big basis tends to drape across the structure and because of the elevation at the top of the structure, you get more sand accumulating on the flank than you do on the top as a matter of gravity.

You've seen some of the cartoons before but this shows you how we envision the thicker flank of this structure, as having the possibility of a ratio of thickening either two or three to one and we know from our experience onshore in the Miocene, but recently after information has been coming in from the deep water, if you turn to the next slide, Page 24, there's been some significant information that's been reported by the operators of the K 2 field.

An important thing for me to point to you is the initial well, which is well number one that was drilled in K 2 literally, reported a potential discovery based on one zone which was less than 100 feet thick. As that prospect has progressed, as reported by the operators publicly, they've gone off the flank of this structure, so called wedging I just discussed, has been responsible for thickening almost three fold.

Not only did they get thicker sands in the zones, when it was penetrated by the first well, as you can see on the very left hand side of Slide 24, new zones weren't even developed up dip have come in on the left flank and they're what we call overlapping the structure. Of course as you add these thicknesses to the existing zones and then get these new wedges of sand that are coming in to the hydrocarbons, it just takes the amount of reserves that you have on the flank.

The other thing that's important is what the deep water fields have been proving, is that you have 4,000 to 5,000 feet of column on some of these reservoirs which gives you thick sands on the flank, thick columns. That's where the big reserves are coming from. For instance, when the K 2 field was originally reported by the discovery operator, the number of half a billion barrels was being thrown around.

Now publicly, with the thickening on the flank, we've got more drilling to do. They're now calling this a potential two to four billion barrel discovery. You can see we're dealing with some volatile numbers here. Because of these big structures it affects the area that accumulate hydrocarbons and gives you the opportunity to have sands that are draped across these features that cover a big service area and have big columns.

What does that mean for Blackbeard? Remember, this prospect was drilled originally by another operator. If you go back and look at Slide 22, the location that's shown there, you can see the rest of the contours which again for industry confidentiality basis, we're leaving off this cartoon, this initial well was drilled on what we call the very top of the structure.

In other words, bulls eye. Why did the original operator do that? Because they had no control and basically as their deep water results had shown, they had drilled the top of the big features out in deep water. Importantly, and I think this is significant because I've been asked about it a number of times, why did the original operators choose this spot? It was the first place on the shelf that they decided after their information from their deep water discoveries to come drill, which mean that based on all of their seismic ties and their geological information, this was an optimum place to test the deep water concept in the Miocene.

Because they were on the very top of this structure, I don't criticize that. That's where you drill structures when you have nothing else to go on, you bulls eye them, but as a result of what I've just shown you, exactly on the deep water, i.e. the thicker flank are indicating that the reservoirs could be much thicker, if you had drilled this and had to do it again, you may go somewhat down depth. I've got to suggest a location that would show how you could have tested the east flank of this as opposed to the very tip top.

Why am I saying this? Since we're now finding that some of these deep water fields have thousands of feet of column, in other words 2,000 to 5,000 feet of column, you can afford to get off the very top of this structure with your initial well and drill the off structure wells which will give you a better opportunity to see what these thicker flanks look like. In our case, we had no choice but to deepen the well that we drilled. That's been a big advantage for us because it saved us hundreds of millions of dollars, not having to drill the shallow part of the whole.

Where we stand today is literally as we speak, we're trying to decide. We're at 33,000 feet and have logged a well, and are looking at some of the technical velocity surveys, deciding how much deeper to drill the well or whether to go ahead and attempt a completion here. We'll have that information to you after we've had the chance to get the partner together and decide whether we go deeper or whether we attempt a completion.

Bottom line, in somewhat guarded comments, we said that we have a potential discovery here. Because this is the deepest that anybody's seen the Miocene below the mud line and because we are far enough away from the deep water, we need to get flow test on these zones. The zone that have typical low responsive, highly carbon reservoir, now what we have to find out is what kind of flow rate we've got.

Some people have asked us in other meetings, "What kind of flow rate can you expect?" Frankly, if you look at the existing Miocene wells up dip, and the so called deep Miocene, the pressures we deal with out at the bottom are between somewhere between 15,000 and 17,000 feet. Here we're dealing with over 25,000 tons of bottom hold pressure. That means that if you have the same reservoir and you have porosity you're going to be pushing more through that same pipe just like you would a high pressure water hose.

Secondly, the amount of gas we have, gas/oil in the reservoir is going to be significantly higher than we have even in our deep clay. And the reason for that is what I call the butane tank effect, where whatever you have in a reservoir with 15,000 to 17,000 bottom hold pressure, you take 25,000 pounds of bottom hold pressure more, you get up as high as 28,000 pounds, you can squeeze just that much more hydrocarbon into the same force base.

So the recovery factor, per acre foot is going to be increased because of the pressure, and the permeability and the velocity of the flow rate will be determined. But since there haven't been any wells tested with this kind of pressure, that's the information we need to try to be able to give you the information that all of need, and that is, exactly what we can expect from each of these zones.

So in summary, we have zones of hydrocarbon. This is a massive structure. We've got a lot of section below us. Whether we go to all depth at this location or whether we move off structure, you'll see some of this in more down dip structure, we will attempt to complete this well. We think the structure, on 22 you see that these 5,000 acre sections, three square miles, the structure actually covers over 10,000 acres.

So it's a massive structure. That's why the original operator chose it as the first location on the shelf to test this concept. We're going to continue. So stay tuned. It's a work in progress. It looks like we've got a potential major discovery here, and we'll try to keep you informed as we make our decisions going forward.

I hope that answers a lot of the questions that I've been getting. Again with the guarded information that we can release with the offset operators that don't participate in this well, I hope we've been able to give you some visionary as to why we're comparing this to the deep water and how we're seeing things that are so similar.

Richard, with that I'll turn it back over to you.

Richard Adkerson

I'll complete our presentation by looking at our outlook. For the year, we expect to average 250 million a day which reflects that our estimate that 180 million a day in the fourth quarter. All indications are that the wells that are currently curtailed by the hurricane can return to their normal production once we get facilities restored and by the first quarter, first half of 2009, with our new wells coming on stream, we should be back at levels that we were prior to the storms interrupting our production.

We have the cash resources to continue the drilling program that we just reviewed with you. Our activities in the OCS 310 State Least 340 area, the drilling at South Timbalier block 168 and our new prospect at Ammazzo and the well drilling in St. Mary's Parish, the north east. Our 2008 capital expenditures are estimated to be $279 million, $95 million in exploration, $175 million in development costs and our opportunities continue to come to us. So our actual spending will be driven by what opportunities we have.

Page 26 shows for the year, our EBITDAX, our sensitivities and our excess cash flows. We will be using cash that we have on hand during the fourth quarter. As we move back into 2009 even at the current lower prices for oil and gas, we expect to be generating sufficient cash flows to enable us to continue to fund our exploration activities and see no need based on our current set of opportunities to require financing.

Our financial policy is to run our business to maintain a strong balance sheet. That means we will be responsive to market conditions in terms of our level of spending activities. We will commit capital to our high potential opportunities while we maintain this capital discipline and we spread our capital around as you can see by our partnership arrangements to give us exposure that is impactive on our company and at the same time the opportunity to drill a number of properties.

The McMoRan story in the world that we live in today remains intact. We have significant reserves and production, high impact exploration prospects, large acreage position. We're generating strong cash flows that will be increasing as we restore our production after the hurricane interruption, and so we are continuing to pursue the same strategy unaltered that we've been set up on for the last several years.

We will open the line for questions.

Question-and-Answer Session


(Operator Instructions) Your first question comes from Nicholas Pope – J.P. Morgan.

Nicholas Pope – J.P. Morgan

A quick question about the platforms that were damaged during the hurricanes. Are there any plans, I know at least one is missing. Is that right? Are there any plans to reconstruct the platforms that have been significantly damaged at this point or is it that far along yet?

Richard Adkerson

The six platforms have minor reserves and production, and they will be dismantled. We're assessing exactly how to do that, working with MNS. The six that were severely damaged won't come back on stream.

Nicholas Pope – J.P. Morgan

With the South Timbalier wells, a lot of discussion there, but has there been any indication about the potential productivity of the sand at this point, or have you been able to make that determination yet?

James Moffett

I'm going to make some guarded comments because of the industry confidentiality. We're trying to continue to drill as much as we can and still tell you what's going on. Sands that we have logged, all the logged caches are highly carbon reservoirs, so that's why we call these zones potential hydrocarbon zones.

You have [inaudible], all of those things that indicated by logging houses that these are reservoirs that have sand, porosity and they've got hydrocarbons in them but they wouldn't have them highly distributed.


Your next question comes from Noel Parks – Ladenburg Thalmann & Co.

Noel Parks – Ladenburg Thalmann & Co.

It was very interesting to hear the discussion of the wedge model which if I understood it right is the flank for some of these structures are thicker than the center of the structure, and also an analogy that I can pick up from what's in the deep water. If you compare this to your idea of what the total company potential is after the merger from last year and apply this extra piece of the puzzle of what you've seen in the deep water, can you give us some sense of how many prospects or how many other sections of the Gulf that you think you might try to expand this thinking on to, above and beyond what you've had for a long time as far as the deeper pool concept.

James Moffett

We have numerous blocks, about ten, prospects that have been identified and may have been publicized in the Treasure Bay. This being the first well drilled in the middle of this ultra deep clay on the shelf, and remember the shelf you have to kind of spend a minute. The shelf as we refer to it today, is today's shelf. The Miocene shelf that was responsible for the deposition of the deep sands on the shelf was back up on the coast of Louisiana, actually north of [Avondale] and just south of Lafayette, coming in north of New Orleans.

We know that because we have Miocene sand deposited in the delta on shore. You have to start with the fact that we're dealing with one basin and the shelf today is a geographic feature. You just have to move a ways since it's a recent shelf. As you take that, what this well is doing is testing not just this prospect but the entire acreage that we inherited in the [NNewfieldield] transaction. We have eight or ten plays that are in this area, and whatever section we have drilled and now have defined as what we call the measured section, and calibrated, that same section will be available to us now underneath those different prospects.

Before this well was drilled the unknown, when they came in from the deep water and tried to compare to the on shore was just how the sands be deposited. But remember I've been through this before. The thick sands that we see on shore including the Flatrock and Gyro 9 that we've been talking about at Flatrock now flowing in Ammazzo, those sands all come from the north to the south. They come from the Mississippi River delta.

So the sands have made it across the shelf and all the way out to deep water. That's why we are confident that the sands will have similar characteristics as that are draped across these structures. That was the premise at the beginning and I'll just say one more time, the original operators who had made the deep water discovery, this is the location that they chose, deep block to come on shore – off the shelf and test this concept.

All we did was to deepen that well. They decided the coordinates. So it's a significant structure as documented by the fact that this is where they chose to drill. Whatever we find here, that same section will be available to us as potential targets on these other prospects that we control the acreage on. So it shows the entire area within that 50 mile radius of this well is going to have a huge impact if we are correct in our assessment of this prospect today.

Noel Parks – Ladenburg Thalmann & Co.

Can you give us any sense of, and I know it's so early and you were pretty clear about the data you still need to really get a handle of this. From what you've learned about the deep water, can you give us any sense of incrementally this de-risks what you have in the eight to ten or does it just generally give you better confidence?

James Moffett

There's two things it does. First off, you quit. You drill at 30,000 feet and we're through. The fact that there's deeper section wouldn't be a normal section. It would be high pressure that couldn't be drilled. And that was pretty well publicized because the well was abandoned for over a year and a half.

We looked at the information and based on our study of the well that had been drilled, what we call the shale region, we found that we were in an environment where we could deepen this well safely. We deepened the well from 30,000 feet to 33,000 feet. As predicted, it's a normal section in terms of deep drilling.

Obviously [inaudible] do you in the section, but other than one period of time of about three to three and a half weeks, we experienced some loss returns. This well has drilled as routine as you can drill a well at this depth. So we number one, removed the risk. Can you drill these wells deep enough to test the Miocene section? The answer is yes. We've proven that. Now we have the drilling confidence to drill the off set wells.

Secondly, we've seen a normal section. The environment of depth position here is in an area that cut into the logical zones that are broken into one, two, three, four and five. We think we're in the middle of that which means that we're in an area where we can expect to have the sands deposited. So therefore the sands that we've seen are just as we expected they would be, layer cake, just like they are in the deep water and into the north on shore.

Now it's a question of how many can we stack on top of each other, how much area these things cover and what is the thickness down dip. We see the seismic clearly showing the wedge. Does that mean the sands take a down dip? It doesn't mean it. Normally that's what you see happen. It's just a matter of gravity.

And of course the reason that we have to test these sands is because no one has ever tried a well at this depth and all we can do is tell you that the topography of the sand and the log response appear to be highly [inaudible] and we'll confirm just how good the reservoir is going to be and then find out if it's thicker down there to give you a real reserve.

What are we talking about? We're talking about comparing the structure which covers 10,000 acres. Some of these deep water discoveries, we're talking about half a billion to several billion barrels of oil in 70 feet of water. So when you talk about the impact on the company, if we're right, you guys are the mathematicians, you can do your multiplications and tell it. And at $50 oil, you can get some idea of why this is so important to not only us on this prospect, but on the surrounding prospects.

Noel Parks – Ladenburg Thalmann & Co.

About how long do you expect it will take to get the partners together and decide whether you want to try to complete the first well at its current depth or keep going?

James Moffett

The partners have already agreed that we would complete the well if we don't go deep. But the information that we were just looking at from the log that we ran over the weekend, will give us a good feed on whether we want to try to go deeper here or we try to take the completion and possibly deepen some later. We know we've got a significant section below before we get to what we call the basement. The basement here is below 35,000 feet. So we've got another 2,000 feet of section to drill. We'll make that decision here in the next couple of days.

Noel Parks – Ladenburg Thalmann & Co.

I just wanted to check, there was that item in the current liabilities for the current portion of accrued oil and gas reclamation costs, and it rolls pretty sharply sequentially, about $74 million to about $202 million in this quarter just completed. Is that hurricane related, that bump up there?

Richard Adkerson

It's a combination of the reclamation obligations that we stepped into when we bought the Newfield properties which we have been undertaking activities and we're continuing to make arrangements. We're actually dealing with the hurricanes from Rita and Katrina activity which has been on our plate since we acquired the Newfield properties, plus the new activities that we're having to deal with, with Ike.

All these things are items that we schedule on the basis of one, when we're required to do them, and two, when does it make sense on an economic basis to spend the money to do it in terms of what contractors are doing, what's the available equipment and how can we do it most efficiently.

Noel Parks – Ladenburg Thalmann & Co.

Will expect that amount will be flattened, gradually decreasing going forward or will it come down again after a quarter or two as you make progress on the things currently on your plate?

Richard Adkerson

We have work that we're doing right now and we're having work scheduled for the fourth quarter and early into next year. It will come down as we spend the money to get it down or else we actually contract for the services. We'll know what the costs will be. So we're trying to do this in the most economic way we can.


Your next question comes from Richard Tulis – Capital One.

Richard Tulis – Capital One

What's your early outlook for CapEx budgets for '09?

Richard Adkerson

At this point we are anticipating spending at roughly the same level we did in 2008, but as always, that will depend on the results of the wells we're drilling and other opportunities that come to us in this area that we're focused on. Right now we're looking at costs at roughly the same level we had in 2008.

Richard Tulis – Capital One

What about natural gas price would you start to pull back on your drilling activity? What would prices have to drop to see a significant pull back in your activity?

James Moffett

The kind of prospects we're doing, that's the unique part of them. Many of the unconventional gas prospects may have driven off price sensitive, but if we're right about these big structures, Ammazzo, Blackbeard, continuing development of the south part of Flatrock and the Gladstone, because we're in such shallow water, 10 feet to 70 feet of water, once you run on these big structures, your development costs is so much less expensive than it is in deep water.

We can make money as low a price as anybody in the business. That's why we take the risk. You talked about the hurricane damage. That's one of the things you take on when you go in the Gulf of Mexico shelf and in deep water, you take on the fact that you can have these properties. You buy insurance and you button down everything and ride these storms out.

The reason why we're in the Gulf shelf, people in the deep water, there's no place else on shore where you can find these reservoirs that are conventional reservoirs that are what we call soft rock. They don't have to be frac. They don't have to do any abnormal stimulation. And the recovery from those sands can be drawn from areas because you don't have to reach out with horizontal wells and track and do some of the things you have to do in a tight gas play.

So the soft rock on the Gulf of Mexico on the shelf, on shore, deep water has a much different economic profile because once you find this stuff, especially on the shelf and on shore where the development costs are so inexpensive, and you have such a big infrastructure of pipelines and processing facilities, you can make money at very low gas prices.

That's why we're not going to be as sensitive to the so called gas price that would determine whether your reserves are still commercial as will be the problem in the unconventional gas.

Richard Tulis – Capital One

What's your outlook for drilling rig rates going into 2009 given the credit situation? Do you think we'll see some softening there?

James Moffett

I think the budget which is reasonable now, there's very few operators in the deep trend. As you know we've been playing this thing on our own on the shelf. When people had abandoned the shelf we kind of kept going so the drilling rigs are going for anywhere from $32,000 to $45,000 a day may soften some in terms of prices just because there's so few operators like ourselves that are pursuing it.

The back up rig, especially the big back up rigs that we need for the shale deep play have a demand in the foreign arena and we just committed to keep one of the big rigs here that can go to 38,000 feet, 40,000 feet. It's got the rig capability to do that. Those contracts are probably set for at least another two years.

There's a big demand for what few back ups there are left in the Gulf. Most of them have been taken into the foreign arena at least the State owned companies and the other companies, some of those stories that you've reading about. So that's kind of the outlook for rigs. But fortunately, we've got our rigs tied up and have no problems with rigs or pipe.

Third party services at the soft prices, shut down some of the other operations that we discussed. Third party services, Slumber J, Mud Company, Pipe, those kind of prices will definitely come down as some of these other things have been using up the third party services start to abate. If these prices don't improve and the unconventional gas reservoirs are below commerciality, the rig count goes down. Those unconventional resources will have an impact on third party services.

Richard Tulis – Capital One

I know it's difficult to forecast when your total production will be back on given relying on third parties to get some of the production back, but how much production do you think will be back on line by year end '08? What the guess there?

James Moffett

We're going to close to 200 million plus. We may get lucky. As you said, since we're seven months out, the pipeline companies are busting to get on. I think the last figure I saw this week was they're still about 38% to 40% of the gas in the Gulf of Mexico, 2.7 bcf gas is still waiting on these pipelines to get put back together and the processing facilities on shore that got flooded.

Hopefully we'll be at 200 million plus or minus by the end of the year and quickly ramp up in the first quarter above 200.


Your next question comes from Brian Kuzma – George Weiss.

Brian Kuzma – George Weiss

Could you talk a little bit about at Blackbeard how long it would take to get a flow rate and the necessary infrastructure you would have to put out there to get a test rate?

James Moffett

The pipe is going to be the lead time. It probably will take us about 12 months to get the pipe. You have to wait until you can actually roll this train. We've had to wait on a couple of deep wells that were in shallower depths. Even there, the problem that you have is the non-corrosive pipe that you have to use. Once you know exactly what you're parameters are, what the environment that you're going to be setting the pipe in.

So just assume that within 12 months plus we'll be getting the pipe and the high pressure tree and the equipment to tubing to flow test this.

Brian Kuzma – George Weiss

Do you know what it will cost to do that completion?

James Moffett

Probably in the $50 million range based on the current prices.

Brian Kuzma – George Weiss

What do you think you could drill the flank test for at Blackbeard?

James Moffett

We've given a lot of thought to that. A lot of it depends on how much we change the shallow pipe configuration. The big money we spent on this first well was because this was the first well that was drilled to this depth on the shelf and the multiple strings of pipes we had before we got the operator got down to 25,000 feet.

We looked at this hard, and based on the drilling information we have now which we didn't have, we can eliminate some of those strings of pipe. So we think the well should be drilled for $125 million to $130 million as opposed to the big numbers that we've drilled on this first well.

Brian Kuzma – George Weiss

Have your partners decided whether they want the next ultra deep well at Blackbeard or are they pushing you to do it somewhere else?

James Moffett

Partners get together and instead of pushing they try to pull together. We're all looking at what the next best shot is and since we control eight or ten other projects, there's temptation to get out there and drill those and get the flag drill. As you can tell from the cartoon and the comparison to K 2, and some of the other fields that are sending these ledges off the structure, they both need to be done.

So it's going to be up to the partners to pull together and you may find that as we go into next year, we'll actually try to do both. I'll pose it again to you and to all of you, where can you go in 70 feet of water with existing pipeline and look for half a billion barrels to multi-billion barrel fields?

Anybody else who can find a place in soft rock to do that, please let us know.

Brian Kuzma – George Weiss

On the logs that you've seen thus far, what would be the minimum sand thickness that you need to find for it to be even noteworthy? What can you see on the logs that really will tell you the porosity is there?

James Moffett

We're there. We've looked at thing long and hard and we've convinced that with the pressures and the porosities and the [inaudible] gamma ray response that we've got enough sand in the well that it should be commercial. Again we're going to have to flow test it, and some of the parameters. We finally after we got some of the hole conditions, there was some question about whether we could load this well seven months ago.

We're now logging this well with wide line logs all the way to T.D. Gamma ray is working, density neutrons are working. We've come a long way as I said in one of my other responses to whether or not you can drill below 33,000 feet in here.

We're drilling this well using the conventional drilling techniques that we used down to 25,000 feet on the deep footprint that we've made and the third party service companies that worked with us and have got tools now that function all the way to 32,000 feet. So we've got conventional data to make these analogies with.

One thing we don't have is we don't have a calibration for sands at this depth and sands at this topography because there are no other wells that have tested because it's never been penetrated. That's why we have to cautiously say that based on what we see and with the data we have, we think we have sand quality and sand thickness which should give us a commercial flow rate.

The problem is that we control some of the acreage to offset this, we don't control it all. So we realize you need to know what's going on. We're making every effort to let you know what we're doing and still trying to honor the confidentiality that we need to keep so that other people can't take advantage of the information.

Brian Kuzma – George Weiss

At Ammazzo, are there any sands that you can correlate to the immediate shelf of your prospect that make you a little bit more confident that some of the thick sands that you were seeing in State Lease 340 area are going to be present down there? Do you have any seismic anomalies similar to the ones you saw at Flatrock?

James Moffett

All of the above, but instead of having to look to wells right to the south of us, we're better looking back to the north because remember this axis that I showed on the map shows that we're being structurally impacted by the same structural axis that gave us this Flatrock and J. B. Mountain and just continues right south to here.

And from the seismic, as best we can tell, correlate the seismic we're only going nine miles away. It appears that this same wedge of sediments is deposited over the top of the Ammazzo. It looks like so much like J. B. Mountain, it looks like Flatrock. That's why we put it on the same ridge. It's part of the same structural system. It's a brother or a sister to those other fields that we've talked about.

The Blue Fault, the grandparents and the other structures that have come off of this that are sitting on top of the Blue Sauk are all related. So we think the deposition should be similar. We think that the Rob L and the Operc and the Gyro 9 all ought to be objectives.

Brian Kuzma – George Weiss

But we shouldn't expect the necessarily the same pay? These are different pay sands.

James Moffett

Rob L, Operc, Gyro 9 will be identically the same age. They would have been deposited at the same time as the J. B. Mountain and Flatrock were. So it's there. It's the same age sands, the same quality sand. As you move down to Ammazzo, the only thing you can't predict is, did all of the sands get down there or did more of the sands get down there? You've got this big sediment dump in the Rob L, Operc and Gyro 9.

The other thing we keep talking about is these thousands of feet of sand. We've got 6,000 feet of [annorive] that's been suspected, and from the first day we got in here, we said we thought the Rob L, Operc, Gyro 9 would produce on trend, but all three produced. And sure enough they have.

This thing is still on trend with those same fields that we were referring to. If we knew exactly how many of those sands were here, there's just not a well close enough, and that's the good news because if there had been that much designation, the prospect wouldn't be available. This is one of the biggest structures that is undrilled on the shelf in the Gulf of Mexico and so the only thing we have to do now is get in here and see if we can pull the Flatrock, J. B. Mountain type sands down on the same ridge.

Seismic shows that we ought to be able to, but we're going to have 500 feet of sand, or 2,000 feet of sand. Both of them would make big targets on a structure this big. That's why we've given you a 500 bcf in excess of one trillion. It depends on how many sands you stack up.


Your next question comes from Kent Green – Boston American Asset Management.

Kent Green – Boston American Asset Management

The question pertains to Flatrock and reserves from Flatrock. You've done a lot of delineation and wells and you're now putting production wells on and you've completed them in various sands, but mostly the Operc and a couple at the Rob L have multiple sands there. Who is doing your reserve calculations and how will these wells produce out? Are you producing from multiple sands or are you just going to produce from lower sands and go up? Give us a little bit of production planning here.

James Moffett

The reserves are done by Robert Scott. The sands are stacked. That's why we call them stacked like a hay stack. We're starting in some cases in the thickest zone at the bottom of the well. In one case, the 228 where we passed up two zones that we thought we'd see and the 230 well in the south which we did see. So we took the thickest of those zones and completed the first Operc sand.

There were four sands in the well. We took one Operc sand. Of course then you had three Rob L sands above. They're just behind pipe. In the 229 well we took our first completion in the Rob L sand. We had other Rob L sands in the hole but they were thinner. We had Operc sands in the hole. This is a big sand, 250 feet thick.

We perforated it because we thought it had the highest flow rate and of course it flowed 100 million a day in 2000. Each of those zones that you see flowing are just one of the zones. The other zones are behind the pipe and as we produce those zones we will do wells as we're trying to figure out now to get some of the other sands or leave some of the sands to be perforated as it moves up the hole. That can be done without moving the rig back on.

What you do is, you have these stacked sands, you take the lower sand, and when you complete it, you go in with [inaudible] line and you crawl to it and you pop cement to it and you come up the hole and you perforate the sands. In some cases we may have three or four different zones come up the hole and you just produce that at the same hole as each of these sands deplete.

What we have to do now is get a delineation done to decide do you want to drill acceleration wells we call it, or do you want to take these behind the pipe completions. The well we're going to be drilling next which is number six is going to open up the whole south half of the field. What you've seen to date is the Rob L, the Operc and the northern part of what we consider the Flatrock structure.

You remember from my cartoon, as you move south you have the Operc section underlain by the Gyro and those sands are also thick. We have one giant Gyro 9 sands to the south that's 900 feet thick. It had about 60 feet of water, we're going to see how much we can pull up out of the water. So the south half of the Flatrock is what we're fixing to go to next and it has multiple [inaudible] sands. Depending on how many we find and how full they are, we can add anywhere from another 200 to 500 bcf's on the southern end of this thing.

The reason why those numbers keep popping up is because these sands are so thick. You get 500 acres of one of these sands at 200 feet to 300 feet it really puts some numbers to it. And of course, the sands are all very high quality. We've seen on the logs that the sands have 24% to 26 % porosity. That's why they flow at these 50 million to 100 million flow rates without any draw down.

Kent Green – Boston American Asset Management

The other question is how many more wells is a rough estimate and is your well cost coming down as you get used to drilling in this location?

James Moffett

All of the above. As we know where the pipe points are, we get the pipe points in the right place and we know exactly how deep to take each well, so you're right on target. The empirical data that we get from each of these wells, especially when we start drilling wells that are direct off sets, it gives us good go by wells and we don't make the same mistake twice.

Kent Green – Boston American Asset Management

It appears that you're drilling a lot of wells at the 17,000 feet, 18,000 feet level and you've talked about these deeper structures being down in the high 20's and low 30's, is there two big zones in here or is this just as you go further down on the shelf or where these faults are, or are they just different locations?

James Moffett

What happens is, if you just imagine the Gulf of Mexico as you go south the water gets deeper even on the shelf, it goes from zero to 600 feet. That's the way it was at the time the sediments were being formed. The Gulf of Mexico shelf was all the way back up, the Miocene type it was all the way back to Lafayette, into that area.

So the sands came out, and they basically flow out and are deposited across the whole shelf. Sometimes you get thicker channels and become feeders off the Mississippi River. But whole sand section that we're talking about as you go down dip, which is why at Flatrock you have the Rob L at 14,000 feet to 16,500 feet and the Blackbeard area and that area to where you're going to find the Rob L to 28,000 feet to 35,000 feet.

It's just the slope of the Gulf, but it's exactly the same age. The same sands that were being deposited to the north that we call Rob L were being deposited in the deeper water in the Gulf. That's how we identify these things. The Rob L in particular is the name of a stratographic marker. We can see these little micro fossils and that tells us that these are age equivalents and that the sand is being deposited in deeper water at the same time.

Of course is been buried by the fact that the Gulf of Mexico at the same time continues to warp downward and wherever you deposit these things, it keeps more Miocene that Pliocene. It just pushes them down. So it's down dip but it's the same age.

Kent Green – Boston American Asset Management

Is there any chance that you could buy back any of those expensive bonds that are out there particularly with the turmoil in the market or are they in safe hands?

Kathleen Quark

We do have restrictions in our credit agreement in terms of being able to buy back the unsecured debt, but it's something that we'll be looking at as we go forward.


Your next question comes from Gregg Brody – J. P. Morgan

Gregg Brody – J. P. Morgan

I was wondering if you could help me get a better picture of who are the main operators you're looking for to get your production ramped up again.

Richard Adkerson

It's mostly pipeline facilities as opposed to field operators. It's getting the pipeline systems back online and they're working to do that, and they'll be happening over the coming weeks.

Gregg Brody – J. P. Morgan

Is there anyone specific?

Richard Adkerson

It's a whole series of pipelines that are in that area. You can tell in the area of the Gulf where we had that chart of the fields that were curtailed. It's the pipelines in that system.


Your next question comes from George Foley – Foley Investments

George Foley – Foley Investments

How did the Chevron production platform ride out there in Flatrock? How did it do in the storms?

James Moffett

Like the rock of Gibraltar. The difference between it, most of the platforms that received damage, I think it was 60 or 70 in the Gulf, the ones that have been reported on. Most of the ones that got damaged are the ones in deeper water. This thing sitting there in 10 feet of water that's got a concrete island that they built back when they were producing that six tcf, you fly over those things, you think you're looking at a concrete island. At a ten foot water depth, you don't have some of the same dynamics as some of the things that cause these underwater currents that just suck these deeper water platforms. They're in the wrong place at the right time. Most of the damage that's done on these platforms is when you get almost an undertow rip tide, and these tides move in the sub sea.

Some of them have caused mud flows. Some of them have caused these real rip tide type of currents. We've been through I don't know how many storms. This is probably the most damage that we've ever experienced as a company. What you have to do is figure that your weak platforms went down, the rest of them have stood the test, but as you see us in the shallower water, especially with these big structures like the big Chevron facility, those things are like the rock of Gibraltar.

George Foley – Foley Investments

If you go between J. B. Mountain and Ammazzo there's a huge Rob L section that's about five or six miles there. Why wouldn't you try to drill that?

James Moffett

Those are prospects that are in the inventory. Once again, because of restrictions of recent information we just try to be as general as we can. You're right on target. All of those are being looked at. Those are main prospects and we've said over and over again, we started working on this track which used to be the Texaco State 340, I guess it was in 2000 when we got that contract, and all these wells that you've seen us drill are drilled on this one big holding which used to be known as 340, and it's included in that.

Those things aren't going anywhere. We're just trying to accumulate as much information as we can because every time we drill a well out here it gives us another calibration of our data so we can tie it together. Those are prospects that are in the queue. When we decide which one of them will go first, the Ammazzo prospect is the biggest one, there's one to the south that hasn't been drilled.

We'll see what kind of luck we have on it and the other things in between will be something that we'll continue to look at.

George Foley – Foley Investments

If wells have been so good for us since Flatrock why don't we go back up in J. B. Mountain and J. B. Mountain Deep and recomplete there? Is just not as good in those areas?

James Moffett

The J. B. Mountain and Flatrock structures have two different structural styles. The Flatrock structure is right underneath the shallow feature. It migrates south. The J. B. Mountain feature is one that pops up at about 18,000 feet, but you can't see it above 18,000 feet.

So it's a true buried structure as opposed to a structure which is buried in the sense that it's not completely simultaneous with the shallow feature. On Slide 11 you'll see that all the Flatrock wells drilled, but if you turn to the next page look at see the red outline that's got all the little tick marks in it, that's where the 3.2 tcf came from and you can see in the shaded area is not exactly simultaneous as if you were looking straight down.

The umbrella is tiled. So the hatched area is Flatrock. Move down to J. B. Mountain, you'll see that hatched area, you'll see how far away you are from the shallow production. That's because the fault lays down and it doesn't develop that until you're into 18,000 feet. So you don't have a prospect in the shallow.

Mound Point is more like Flatrock. J. B. Mountain is a buried structure. Ammazzo is more like Flatrock. Mount Point as we can see is as high as 15,000 feet.

George Foley – Foley Investments

If it costs so much for the shallow part of the drilling in the Blackbeard, could we go back up hole and side track and drill into the wedge from our existing low bore?

James Moffett

Because the pipe is shut down 27,000 ton feet, the amount of structure that we need to get down depth, you'd have to start off a lot shallower and so by the time you get down to these depths it's difficult enough to drill these deep wells in a straight hole. There are some side track drills out in the deep water off the shelf because they have no other choice.

We will find that we need to move far enough down dip. If you'll measure on that slide that shows the eastern location, we need to back off and prove how much column we have, how much sand we have down dip, if they're high carbon bearing sands that we see are in fact draped over this feature. I said two things. The deep water expanse has happened and has been proved out even since we started drilling this well.

People are proving two things; the wedge and the amount of column. And they're seeing 4,000 foot to 5,000 foot columns out there and that huge. When you do down and define that, you get one of those kinds of columns it just makes the extent of the acreage just that much bigger. Get somebody to do the numbers for you. Put 100 feet of sand over 10,000 acres and you put a lot of oil and gas in there.

George Foley – Foley Investments

Do you think the wedge will have oil instead of gas with where we are now?

James Moffett

It's too soon to tell that. At this depth and these pressures, we're not sure whether we're going to have oil or whether we'll have gas. Remember the gas could be a well that would make 100 million a day, 50 million a day. You do the ratio. And it can make a hundred barrels a million. If it makes a hundred barrels a million, you produce 50 million barrels a day, 5,000 barrels of oil at 100 million a day.

So some of the stuff in the deeper pool play, the Gyro 9 main location produces 100 barrels to 200 barrels of condensate whereas the Rob L might produce 20 barrels to 50 barrels. So these reservoirs at depth with this kind of pressure may be gas in the reservoir. By the time you get them to the surface, they may be gas and dissolute. Those are all the kind of things we have to prove by testing these sands; the flow rate, the gas content, the btu of the gas, whether its going to be rich condensate, lean condensate.


There are no further questions at this time. Are there any closing remarks?

Richard Adkerson

I want to thank everyone for being on the call and we look forward to reporting our year end results at our next call. If you have any questions, contact us.

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