McMoRan Exploration Co. Q4 2009 Earnings Call Transcript

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McMoRan Exploration Co. (NYSE:MMR) Q4 2009 Earnings Call January 19, 2010 10:00 AM ET


Kathleen L. Quirk – Senior Vice President and Treasurer

James R. Moffatt – Co-Chairman

Richard C. Adkerson – Co-Chairman


Nicholas Pope - Dahlman Rose & Co.

[Brian Hoosma] – Weiss Multi Strategy

Anne Cameron - J.P. Morgan

Neal Dingmann - Wunderlich Securities, Inc.

Eric Anderson - Hartford Financial Management Inc.

Joan Lapin - Gramercy Capital Management


Ladies and gentlemen, thank you for standing by. Welcome to the McMoRan Exploration fourth quarter conference call. (Operator Instructions)

I would now like to turn the conference over to Miss Kathleen Quirk, Senior Vice President and Treasurer. Please go ahead ma’am.

Kathleen L. Quirk

Thank you. Good morning everyone. Welcome to the McMoRan Exploration fourth quarter 2009 conference call.

Our results were released earlier this morning and a copy of the press release is available on our website at Our 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. We also have several slides to supplement our comments this morning and will be referring to the slides during the call. They are also accessible using the webcast link at

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

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

On the call today are McMoRan’s Co-Chairmen, Jim Bob Moffatt and Richard Adkerson. I’ll start by briefly summarizing our financial results and then turn the call over to Richard and Jim Bob, who will review our recent performance and exploration update. As usual, after our remarks we’ll open the call for questions.

Today McMoRan reported a net loss applicable to common stock of $9.5 million or $0.11 per share for the fourth quarter of 2009. This compares with a net loss applicable to common stock of $314.6 million or $4.46 per share in the fourth quarter of 2008. Our fourth quarter results from continuing operations totaled a loss of $4.7 million including $10.5 million in impairment charges to reduce certain fields to their net carrying value to fair value and $5.9 million in gains for insurance proceeds related to the 2008 hurricane events.

Our fourth quarter 2009 production averaged 209 million cubic feet of natural gas equivalents per day net to McMoRan. That compared to 162 million cubic feet of natural gas equivalents per day in the fourth quarter of 2008. Our production in the fourth quarter of 2009 was slightly below our publicly reported estimates of 215 million a day because of delays in the timing of re-completions originally planned in the fourth quarter that are now expected to be completed in 2010. Our full year 2009 average daily production averaged 202 million a day net to McMoRan.

Our oil and gas revenues for the fourth quarter totaled $128 million as compared to $111.8 million during the fourth quarter of 2008. Our realized gas prices in the fourth quarter of 2009 of $4.70 per Mcf were lower than the year ago period’s average of $6.77 per Mcf. Our realized prices for oil and condensate averaged $75.15 per barrel in the fourth quarter 2009. These were higher than the year ago average of $53.84 per barrel. Our realizations do not take into account gains or loss on derivative contracts. During the fourth quarter of 2009 we financially settled our swap positions of 1.1 bcf of natural gas maturing in the quarter and 45,000 barrels of oil at average prices of $8.97 per Mcf and $71.16 per barrel respectively. We received $4.9 million in cash for these positions and paid just under $200,000 for the oil positions. We also financially settled 0.7 bcf of natural gas put options with a strike price of $6 per Mcf and received $1.5 million in cash for these positions.

Our earnings before interest, taxes, depreciation, depletion and exploration expense totaled $83 million in the fourth quarter and $267 million for the year, and our operating cash flows for the 12 months totaled $131 million, including $45.7 million in the fourth quarter. Our capital expenditures for 2009 totaled $138 million, including just under $25 million in the fourth quarter, and we ended the quarter with cash and cash equivalents of $241 million and no borrowings under our bank credit facility. Our debt at the end of the year totaled $375 million and that includes $75 million in convertible senior notes.

Shares outstanding at the end of the quarter approximated 86 million. Assuming conversion of our remaining 6.75 mandatory convertible preferred stock, our 8% senior convertible preferred stock and our convertible senior debt, we would have approximately 116 million shares outstanding. We also updated our reserves, which Richard will talk more about. And now I’d like to turn the call over to Richard who will provide additional details on our results.

Richard C. Adkerson

Good morning everyone. As we typically do in these calls, I’m going to give a brief overview of the highlights of our results and Jim Bob will be on the call to talk more about the details of our exploration program and our outlook and to answer questions.

Of course this earnings release is highlighted by our significant discovery at Davy Jones which is an ultra-deep project that took some time to get logged but finally got the resistivity logged in January and indicated that this is a major discovery really validates the ultra-deep geological philosophy that we’ve been pursuing, and is a real highlight for our company now and for the future. We’ve also in our deep gas exploration program where we’ve been following this deeper pool concept of drilling wells between 15,000 to 25,000 feet above salt, we’ve had positive drilling results at Blueberry Hill which we will review. Our most significant discovery in that program has been the Flatrock discovery and now we’ve successfully ramped up production from the six productive wells there and they’re producing at a gross rate of over 300 million cubic feet a day.

We’ve also successfully managed the other part of our business and that is our production from our traditional properties as well as the properties we acquired from Newfield in 2007. We’ve managed those operations and our spending to be responsive to the lower natural gas prices during 2008. We enhanced our liquidity position by our June equity offerings. We’ve also collected $25 million in insurance proceeds from the storms which have, over recent years, been delaying our production and we’ll continue to collect additional insurance proceeds as we incur costs for our damaged equipment.

Slide 4 points to Davy Jones, which is a major discovery. It has 135 feet of net pay indicated on logs in four zones in the Wilcox section of the Eocene and Paleocene. This is the sand structure that we were targeting, of course, which has been prolific onshore as well as in the deepwater, and this ties it in to having the ability to access productive sands from the shallow waters of the Gulf of Mexico. Very high quality sands which were of exceptional quality and really encouraging in terms of what this shows for this prospects and our future exploration activities. We will have to flow test this well to confirm that ultimate flow rates from these zones and that will require some time to get the equipment in and have the well completed to flow tests, but this is very encouraging news for our objective in our exploration program and for what we can do in the future.

It’s located as shown on Page 5 in 20 feet of water. We have a 32.7% working interest. You’ll recall that we accessed this well by re-entering a previous well bore, [spudded] in mid-year 2009, have drilled it to just over 28,600 feet now and we have an indicated targeted depth of 29,000 feet to test for the potential of additional Wilcox sands below those already identified by the log. And that will determine where we go in the future.

Page 6 has the financial summary that Kathleen just reviewed for you, so I won’t go back over that, but this shows the results of managing our costs and achieving the production that we achieved during 2009. That is shown on Page 7 which shows our quarterly production. We have essentially got all of the production on stream that was delayed by the hurricane situation. We have some re-completions to do in 2010 that will further enhance production.

Page 8 is our standard Slide that we show to indicate where our production comes from. You can see its’ concentrated in the central part of the shelf of the Gulf of Mexico and the fields that generate that production.

Page 9 shows the Flatrock discovery located in OCS 310 at South Marsh Island Blocks 212/217 in very shallow, 10 feet of water. We’ve had six productive wells drilled on production to date. We have previously found productive sands to the south in Block 217 and we’re now testing that with a side track on one of those wells. Gross reserves assigned by Ryder Scott at the end of 2009 were 258Bcf gross and 48 Bcf net to our interest.

The Flatrock production history during 2008 and 2009 is shown on Slide 10. We have produced 115 B’s equivalent of gross production to date. In the early part of the year we went through a program to re-complete wells. These are stacked production so as one zone gets produced or our production falls off, we re-complete it and that’s what happened during the second half of ’09 and is the reason for the increase in production currently over 300 B’s per day.

Our proved reserves at December 31, 2009 are shown on the pie charts on Page 11. You can see that we have reserves of 272 Bcf equivalents that are two-thirds gas, one-third oil. As typical of production at these levels, we have producing reserves as well as reserves behind pipe and [PUD] which we then bring in to production as their scheduled to produce based on the production from existing wells.

I want to point out that there are no Davy Jones reserves included in these reserves. With just having the recent data we’re working on reserve data and working with Ryder Scott to evaluate where we stand right now in terms of being able to assign proved reserves under the SEC rules from there. We do have some proved reserves from Blueberry Hill, but that prospect is not evaluated and success would add significant additional reserves there. So we expect significant reserves to come from Davy Jones over time and then from our other successes including Blueberry Hill as we go forward.

The reconciliation of our reserves from ’08 to ’09 is presented on Page 12. It includes additions that we’ve had during the year as well as kind of normal ups and downs from revisions, as you get production histories from properties, but totaling 272 Bcf equivalents.

Our current exploration activities as I indicated include the continued drilling at Blueberry Hill. That’s at Louisiana State Lease 340, part of the Mound Point Tiger Shoal lease position that we acquired from Texaco a number of years ago, around 2000, which has involved the drilling at Flatrock as well as JB Mountain and now Blueberry Hill. Included in that is the well that I mentioned, the Hurricane Deep Sidetrack at South Marsh Island, Block 217.

Davy Jones along with the Blackbeard prospects represents our initial drilling in the ultra-deep prospect, which is drilling below salt and below 25,000 feet, again on the shelf of the Gulf of Mexico, currently deepening that well. As I mentioned, we have a number of other prospective wells to test this ultra-deep concept and Jim Bob and his team are continuing to identify opportunities from that. We have a very significant lease position, the experience in drilling these wells and now the success that we’ve seen by seeing the very significant sands at Davy Jones along with the sands with indicative productivity at Blackbeard.

The differences between our deeper pool, deep gas shelf play and the ultra-deep shelf play are outlined on Page 14. Many of you have heard us talk about this over time but we began getting involved with this deeper pool concept in the 1999, 2000 feet, a very small number of wells have been drilled to those depths on the shelf of the Gulf of Mexico. These target very large structures, typically following the migration of structures that have been known to be productive at shallower levels down to these depths. Wells are drilled at a range of 15,000 to 25,000 feet, typically near existing infrastructure from historical production and so while drilling these wells are expensive development costs are much lower than they would be for prospects of this size because of the availability of existing infrastructure.

The ultra-deep shelf play is really tying into all the geologic and drilling experience that’s been done in the deepwater, targeting sections below the salt weld, very large structures with very large potential wells and this ultra-deep play go below 25,000 feet to 35,000 feet or more. And we’re tying in the geology with the deepwater discoveries, along with the experience of these sands depositions on shore. And now for the first time we’re seeing high quality sands accessing these sand sections from the shallow waters of the Gulf.

Blueberry Hill is one of the prospects in our deeper pool concept. It is shown on Page 15 where it’s located in state waters, State Lease 340. This is the Mound Pont; tiger shoal area that straddles state waters and federal waters, just offshore the coast of South Louisiana. We began drilling this appraisal well in early November of 2009. Now we’re drilling below 17,000 feet with a depth targeting just below 22,000 feet. And this has very significant potential and also is in an area of where there would be, with success, significant different additional exploration expectation and development opportunities. The structure is shown on Slide 10. We’ve seen hydrocarbon bearing sands to date in the initial well that we drilled there and that well was side tracked and bypassed because of drilling experience, but we’ve seen this common sand on Slide 16 in all three wells, a significant column over a large area. So this appraisal well is being drilled in a position to allow us to test our theory about how these sands develop off this very large structure.

Slide 17 shows the location of this Hurricane Deep Sidetrack well. This is again part of the extension of the Flatrock field to the south, where we have previously drilled wells that had productive sands and also some very significant wet sands. We’re currently at just over 16,000 feet with a targeted depth of 21,750 feet and a well that has very significant potential, testing sand sections that we’ve seen to be productive in this area. These sand sections are shown on Page 18. With this well we are targeting gyro sands which we did penetrate in 2007 with the Hurricane Deep well where we saw an enormous sand section, 900 feet, with hydrocarbons on top of water. And we believe the well drilled with this Sidetrack well has a potential to encounter a thicker, hydrocarbon column of productive sands, as well as targeting the deeper gyro sands. And you can see how the wells that we drilled at Flatrock, Hurricane Deep, JB Mountain tie in to testing the Rob-L, Operc and Gyro sand sands. Again all this is part of this deeper pool concept above the salt.

The basis for our ultra-deep concept was tying in to the deepwater discussions in the Miocene and Eocene/Paleocene Sands that are productive below salt in the deepwater. Now in order for those sands to be deposed in the deepwater, they had to travel across the shelf of the Gulf during deposition and the shoreline of the Gulf changed over time. We found Miocene aged sands in the Blackbeard West on top of a very large structure in 2008 and then now from Davy Jones we’ve confirmed that the older aged, Wilcox Sands are present and can be accessed from the shallow waters of the Gulf at depths. We have a number of prospects at our very large structures in the shallow water of the Gulf that gives us a great opportunity to test this concept.

Jim Bob will talk about this obviously in more depth and with a lot more knowledge than I can, but this is shown on Page 20 that shows what I was mentioning, the tie in of these Miocene and older aged sands as they are deposed going from the Shelf in the deepwater, going from onshore to the deepwater and how we see the opportunities to access these sands that are known to be productive in the shallow waters of the Gulf of Mexico. The Miocene/Eocene and at further depths we believe there will be opportunities to test the Tuscaloosa Trend as well, which we have not yet penetrated but which in concept should be there just as we’ve seen these Miocene/Eocene aged sands.

Now for 2010 from our production standpoint because of declines in this production from our wells from the traditional part of the Gulf, we expect annual average production to be 180 million a day, 200 million in the first quarter. Our capital expenditures always will be depending on our success in our program and information that we gain, decisions that we make. We will manage our capital spending prudently, using our cash that we have on our balance sheet, our cash flows and drilling arrangements through partners to allow us to manage our exploration program. But going into the year, we expect to spend about $240 million in total, $170 million in exploration and $70 million in development capital. This will be subject to change and we will be talking with you as those changes occur.

We have reclamation costs that are attributable to our producing properties and we expect to spend about $100 million in P&A expenditures during 2010. We have an obligation under the Newfield deal to also place $15 million annually into escrow. As I mentioned, we’ll continue to pursue reimbursement under our insurance programs for hurricane related claims as we go forward.

On Slide 22 we show what our cash earnings would be using current forward prices and using the production profile and our current outlook for costs. At today’s forward prices we would expect to generate EBITDAX of $335 million. You can see how that would vary using different oil and gas prices.

In summary, what we will do in terms of the financial strategy of this company is we’re going to continue to manage our spending, our production operations, our partner arrangements to maintain a balance sheet that will have the strength to allow us to pursue these exciting exploration opportunities that we have. Spending itself is going to be driven by opportunities and managed within our cash and cash flows and the drilling arrangements with partners. And we’re going to be able, through that program, to commit capital to these high potential opportunities while maintaining capital discipline.

So that is an overview and Jim Bob I will now turn the call over to you to talk about our exploration program.

James R. Moffatt

Thank you very much. Good morning everybody.

You have some slides which are noted as Geological slides. I’d like to look at Slide 25 and start there. Cross referencing if you will, and you may want to click back and forth to your Slide 20 and Richard briefly mentioned, most important point that we would just reiterate, especially now with the results at Davy Jones, is that we’ve been talking for about two years ever since we began the drilling of the deepening I should say of Blackbeard. You’ll notice that we focus on Slide 25 on the ultra-deep Wilcox which is shown as Eocene/Paleocene in the large circle. Its further south in the Gulf of Mexico. And of course everybody’s familiar with the Pliocene trend that we have at Thunderhorse and it’s shown in blue.

As is obvious to everybody and I know all of you that have been following the company, you understand that these east-west alignments just basically follow the old fossil coves and the current day coves of the Gulf Coast in Texas and Louisiana. The premise that we need to really focus on is when we drill Blackbeard we’ll be able to tie it to the deepwater and confirm what our velocities were. Geophysical data had been showing us. We were relying on this 200 square mile area of geophysical interpretation to basically map the landscape in the shelf. As you know the shelf is a current [geomorphological] feature that the Pliocene shelf and the Eocene shelf work harder back on shore at the time of deposition. And the model on Page 20 clearly shows those locations.

I was going to say if you’ll just click back to 20 on your slides, you start on the left with the False River, Fort Hudson to the Tuscaloosa Trend which is onshore and you go south, first you run into JP Jones which is a prospect we have with Wilcox, and Tuscaloosa is northwest of Davy Jones. And we’ve noted our Flatrock discovery. If you’ll notice the Flatrock discovery has the oil and gas [ticks] as shown in the Miocene. Now what’s important about getting started on that cross section is the purple area that looks like a dancing octopus is the salt weld. You will notice that salt weld goes all the way to the onshore underneath the Tuscaloosa Trend onshore and then it heads out over the shelf. It’s much thinner on the shelf. When you get to deepwater, a so called canopy which is a very common term for it, is a result of the fact that we have all the sediment from basically the surface to the TD. We have sediment onshore and we have sediment on the shelf and we have that replaced by four to ten feet of water in deepwater, and therefore the canopy overlies the deepwater is much thicker than the so called salt weld on the shelf.

But what’s important for you to note now is that just south of Flatrock on Page 20, you have Davy Jones and then Blackbeard and Shenandoah as you go to the south and Tahiti and Jack. This looks like a very busy Slide but I hope you’ll take a minute if you’re interested to study and see that what’s really going on here is everything under the salt weld is related to what we call a full [belt] and that full belt [tectonic] is completely different than what we call a trap door tectonic above the purple salt weld. And that’s very well noticed if you look at the cross section ending in the JP Jones, Flatrock, Davy Jones, where our Flatrock discovery is noted as being above the salt weld and the Davy Jones clearly is below the salt weld.

So this phenomenon I’m going to pursue for just a little bit to tell you why we have attached so much significance to first Blackbeard and now Davy Jones, in terms of the hydrocarbons and the Miocene and Wilcox production that we appear to have penetrated. So if you go back to your Slide 25 now for looking at that cross section, that cross section is north-south across all the areas that we show here. It’s across the so-called Davy Jones Complex. It then goes south across the Blackbeard Complex and goes into the Lower Miocene and then goes into the so-called Eocene Wilcox, which is the [southern] trend as out. Once again notice how east-west oriented from the Thunderhorse and the Miocene to Jack and the Eocene, all these trends are doing exactly what the other trends are on shore and what the [phytoplycene] have done. That is they basically parallel the present day coastline. So we expect that [inaudible] will do exactly the same.

Okay, let’s go on to Slide 26. All that 26 is a blow up of that Slide we just discussed on number 20. And that shows you the cross section of what we consider to be this 20,000 acre structure that we penetrated with Davy Jones well, penetration shown with our current TD and our discovery in the so called Eocene. Then you’ll notice below that we have the cretaceous which we have not penetrated. We believe it represents another great opportunity to stack some [pays] in the Tuscaloosa. Everybody knows how prolific the Tuscaloosa is and of course, by the way, I know you all know that the cretaceous/Tuscaloosa in Louisiana is known as the Woodbine Sand in Texas which is the productive zone for the huge, historical east Texas field. So we have some really petroliferous units that we have as targets around this whole strike part of this what I’ll call the Davy Jones trend.

The appraisal well is shown on here and we can tie geophysics around this whole 20,000 acres. It appears to be a very uncomplicated structure as opposed to structures that we see above the salt weld. Some of the largest structures we saw there were salt dome that had salt piercing in the center of them, and that piercing salt and generator resulted in a lot of what we call radial fault. If you just kind of put your fingers out and notice how your fingers project away from your hand in a 360 degree nature of so called fracture or radio fault, busted up in many of these different domes, these big structures that we’ve seen in the deep water. And now they’re vibrating in Davy Jones. They’re uncomplicated. They’re just big roads and mountains with anywhere from 3,000 to 5,000 feet of vertical exaggeration.

And of course what you don’t see on the cross section in 26 is we haven’t gone out to where the inclines are, but what you’ll see in that is that these big mountains in this sub salt are below the salt weld, are big and the valleys in between them at the same time are just as big, which gives you tremendous saturated area for the hydrocarbons. So the vertical elevation of the mountains and the big fetch areas from the valleys or inclines, what’s given us the opportunity for the big columns which have been demonstrated out in the deepwater. So that’s a very simple diagram of what just appears to be a large, continuous structure across the 20,000 acres of Davy Jones.

As Richard said, we haven’t been able to get reserves assigned to this because we didn’t get it drilled by December 31, or I should say logged. We drilled it and had information as you know from our last press conference before we got the resistivity curve. We had a good log of information that indicated that it was a gas effect. So we’ve confirmed all that now. These diagrams, I know you wonder why we draw these colors. If you’ll look at Page 27, what that really shows is the four MMS blocks that we believe comprise the 20,000 acres and of course the structure we show is a very simple, four way dip closure.

The red area is what we think is a reasonable true reserve area because of the simplicity of this four way and across that red area is what we consider a good approach to what the possible reserve may be. And then the rest of the circle, which is in a lighter color, would be the three P reserves. So you’ve got proven, probable category across that, and then you have the possible reserves in the lighter color. I should caution you and tell you that we do not know what Ryder Scott is going to come up with. They are of course our auditor on our reserves. But we believe this is a very simple approach to what appears to be an uncomplicated four way closure.

Now, why do I keep referring to the uncomplicated four way closure? If you know the history of the drilling and the confirmation code in the ‘30’s, in 1930’s, 1940’s, 1950’s, 1960’s, especially in this area, there were a number of fields drilled. Slide 28 highlights that. You’ve seen this concept before, though, if you’ve been following the company. Now you kind of have to look at this like you were looking, I wish I could [inaudible] but the solid red are the oil fields that were drilled beginning back in the late ‘30’s and early ‘40’s. You’ll see some familiar names for those of you who have been following us. You’ll see the Tiger Shoal field and then the cross hatch structure with the stars in it is our Flatrock field. As you’ll recall, Tiger Shoal produced 3.2 Tcf. Just a great big old four way dip closure.

And we chased that deep. The deepest production was at 12,000 feet. We chased that deep on the deeper pool concept above the salt weld. And that’s where we found the significant Flatrock field. And then of course if you go east of that is the Mound Point, the dark red. That produced 2.5 Tcf so just those two four ways, the darker red Tiger Shoal and Mound Point, produced almost 6 Tcf. And the rest of the red are some older fields and they’re also some significant fields that were developed in the ‘40’s, ‘50’s and ‘60’s.

The pink area, which is much lighter and across that area, are the areas that we think are the deeper pools. And the deeper pools are divided into two categories. We’ve got the Blueberry Hill type of prospect that we’re pursuing and of course JP Mountain has been on production now about eight years. And then in the south Flatrock area that Richard just mentioned is our pursuit of the [inaudible] on the south end of Flatrock.

Then you’ll see nestled right in there amongst these old fields is the Davy Jones cartoon that we just showed you. And once again look at this as a 3-D with the red being the shallower, old field that we developed and four way dips that were drilled when all we had was conventional seismic to just basically identify four way closures. Those were drilled because they were all above pressure and were prolific and most of these fields were developed completely by the middle ‘50’s. Now if you go one Slide further it’ll accentuate this even more. This is a very important concept for you to grasp. I’ve blown this up and now the area that we were just looking at is in the middle center of this screen. If you’ll notice Davy Jones is shown at the very bottom center and there’s Tiger Shoal, north of it. Mound Point is just north of that, 3.6 and 2.5 Tcf field. John Paul Jones, another one of our ultra-deep structures, is sitting right in between those two.

The rest of these areas, just take a minute later to look at them. What we’ve done is to highlight the structures that were drilled in the ‘30’s, ‘40’s and ‘50’s and into the ‘60’s. That sounded over a half a Tcf. And once again people say well, why were those structures drilled? Because they were identified on conventional seismic of four way dip closure; all that means is you’ve got dips to the north, east, and west and south there you see by conventional seismic. Once they got on top of these four way dip closures, some of the infamous ones were Cote Island onto almost 2 Tcf and Vein 14 over 3 Tcf. You can go to the east and you can see Bayou Sale almost 3 Tcf, Lake Sand, all the Week’s Island, Cote Blanche Island structures. Some of these are salt domes, some of them are four way dip, but the important thing is notice the 40 or so four ways that were drilled, all drilled up and found by conventional seismically above pressure down to 12,000 foot depth and showed all these primary structures.

Now what we’re doing now is we just lifted the sediment above the salt weld. If you’ll just strip all that off, if I were to click on to another Slide and say okay, let’s take off all of the fields that produced over 0.5 Tcf above the salt weld, every one of these red areas would disappear. And nothing would be left but Davy Jones as an area that’s been drilled on a deep four way.

So I hope in some way that gives you an idea of what we’re talking about when we’re talking about four way closures. And of course if you take the Slide that we’ve been through and look at the complexes out in the deepwater where you have all the deepwater trends very well designated as either Miocene or Eocene, and that Slide once again you can make cross reference if you look back to Slide 25. You’ll notice that all those deepwater structures are all four way dib closures. Everything out there. There’s nothing that is known as being above the salt, especially out in the deepwater. And you don’t have a lot of these little fields on top of deepwater because if you’ll recall, you got water from 4,000 to 10,000 feet deep and you’ve got the 10,000 to 20,000 foot salt canopy. So there was no exploration period carried on in deepwater. They didn’t have the technology to begin with. But the shallow, major producing belts that I’ve just shown here, onshore and near shore shelf, they didn’t exist because the sediments weren’t deposited out there in the deepwater. It wasn’t until they got below the salt canopy and saw the Miocene and then Wilcox, but I’ll just mention again that if you go back to Slide 25, notice how once that first discovery was made at Thunderhorse or the first Wilcox Eocene at Cascade and Jack, the fields that had a string of wells that go east to west, parallel on the present coastline.

That should be a precursor for you and what we would say that that portends is there will be an east-west play in the Davy Jones complex that will parallel the coastline. The same will happen in the Blackbeard area. So somehow the four way dib closure concept, which is what we’ll be looking at now, says that all these big four ways on the shelf that aren’t drilled, we’ll drill two of them and it’s not a coincidence that both of them have indicated hydrocarbon. Blackbeard on Page 30 has indicated multiple Pliocene sands. We did not test those sands but we waited to drill Davy Jones to the north to get the information on the Wilcox. And as we’ve proven, the Wilcox sand will underlie the Blackbeard and we have a prospect on Blackbeard East that we’re pursuing.

There’s a cross section on Page 31. Very important once again for you to notice the salt weld, the purple area that more or less over lies these two big structures. The Blackbeard West as you can see with the Miocene shown indicated with the potential to deepen to the Wilcox which we have seen. And the Davy Jones, of course they’re drilling at it in the deepwater, Cascade has the biggest, significant, [inaudible] well has just been drilled. All of that wasn’t there when we had drilled back there west. That’s why we wanted to wait and let that sand unfold. So we believe there’s a strong indication that the Wilcox sand will underlie the Blackbeard West prospect. Blackbeard East to the east, as you see in the cross section on Page 31, is a very big four way. And you might notice that the salt weld, the purple area shown is the salt weld, starts off the top of some of the lower, middle Miocene. And over at Davy Jones once again on good seismic, those sediments are still in place and weren’t scarfed off by the salt weld.

So we’re considering at this point drilling Blackbeard East which would give us another look at the lower Miocene sand. And another potential if that’s successful is deepen onto the Wilcox to try to see what the Wilcox looks like in this depth position. The primary targets for the Blackbeard East would be to see the Miocene zones that were scarfed out of the Blackbeard West by the salt weld and also see again the sands that we saw at Blackbeard. Frankly, this prospect was originally mapped as one big, broad, 35,000 acre area and we’re now going to prove whether those structures are brothers and sisters, and may even be linked together at depth as one big, 25,000, 30,000 acre ridge that runs through there. So this is part of what we’re calling the Blackbeard shelf, Miocene trend, south of the Davy Jones Eocene Wilcox trend.

There’s another couple of reference slides. I’m going to kind of let you have a moment to digest my geological comments and rather than going on, you have those illustrations and exhibits that we’ve just been through. I’ll save some time here and let you ask some questions and see if we’ve properly explained the impact of the Davy Jones Prospect.

Kathleen L. Quirk

Thanks Jim Bob. Operator, we’d like to open the call for questions.

Question-and-Answer Session


(Operator Instructions) Your first question comes from Nicholas Pope - Dahlman Rose & Co.

Nicholas Pope - Dahlman Rose & Co.

I was trying to reconcile the reserves here. It looked to me like we went from 16% PUDs to 21% PUDs and I was under the impression that a couple of the Flatrock wells were kind of in that PUD category that I guess the two wells that were brought online in 2009. So I was just trying to understand like where those PUDs are and I was expecting to see some more reserve additions, I guess, or at least converting PUDs to prove developed. Can you help me out with that reconciliation certainly with Flatrock?

James R. Moffatt

Well, the PUD that you’re talking about includes some of the Flatrock stuff that we’re doing right now in the [Jaradonna]. And that’s going to be the most significant that we’ve got to prove. We have a column down there. We’re trying to drill that prove area and the rest of the prove PUD that you saw were behind pipe and are locations that can be drilled. There’s a lot of changes in that taking place on our acquired properties. But we can go over that in detail with you after the call if you would like to get some more specifics.

Nicholas Pope - Dahlman Rose & Co.

The reclamation costs that you’ll have in for 2010, I guess that your expectation of $100 million, is that part of the CapEx budget or is that a separate line item?

Richard C. Adkerson

That’s a separate line item, Nicholas. That’s not included in CapEx.

Nicholas Pope - Dahlman Rose & Co.

Just in terms of the interest and some of the new prospects that we’re talking about in the ultra-deep with John Paul Jones and Blackbeard East, do you have a sense what kind of working interest you all are going to ultimately have? Or is that something that’s still being worked on?

James R. Moffatt

Well basically the group has been drilling these ultra-deep, the plains and [engine] 21 and the [inaudible] group are all part of that program and have indicated a desire to continue the program. So our finances if the group pursues these as we move forward will be similar to what it is in Davy Jones.

Nicholas Pope - Dahlman Rose & Co.

Do you have a sense with the deepening with the Davy Jones, now that you’re back to drilling, what kind of timeframe we’re looking at to kind of complete that well? And I guess look at the deeper sands?

James R. Moffatt

As we speak we’re logging it in. We’ve drilled from 28,250 down to 28,600. The bit wore out. There’s so much new section that we’ve seen. We logged down to 28,150 so we’ve got 450 feet of unlogged to go. And of course all we have is a mud log. We don’t have an LWG. As you know the LWG’s burn up at this depth. We’re still in the Wilcox by Paleo. We expect to have more layers of this Wilcox sand that is similar to what we have seen in the first log run that we described to you. Obviously until we log the well, we’ll have to wait and see. But if the sands continue, we’ll report that to you and see how much thickness if it’s there exists. As you know correlating to the deepwater, the lower part of the Wilcox sitting on top of the Miocene, that’s Cretaceous on conformity, is always the sandier part of the section in deepwater. So we expect that we may have a chance to see some additional sands and possibly a thicker group of sands. All these things are deposited from the bottom up and we just drill them from the top down.

But that’s just the kind of sense that we get, looking at the way the sand package is developing, that we may have an opportunity. So obviously every foot that you drill out here below 28,000 feet is near and dear to us, once you establish that you’ve got hydrocarbons in that area between 27,000 and 28,000. So hopefully we now have got a better technique after [scrambling] in for four or five weeks to get the last log, but as soon as we get that log we’ll take a look at that. If we have more to pay, we’ll report it to you. If not we’ll also report that to you. And then we’re strongly contemplating, depending on what the actual amount of net pay is, possibly getting more evaluations such as up over core on the bottom of that well and then possibly taking it as a completion.

We’ve already started a fast track, Indy 500 group that’s going to be acquiring the pipe and tubing and surface equipment, tree and safety valve. If it’s necessary to flow test this well, we’re going to go into did I say a full court press to get that done. We hope to be reporting to you very quickly what those flow tests are. And then of course we’ll move to drilling an appraisal well in the Davy Jones. Following up on the information that we said indicates that this big area on this 20,000 acre structure seems to be all connected.

Once again, since we don’t have reserves on it, we just take what we think is a reasonable approach as to how you sort of size this up, much like we did at Flatrock when we drilled our reserves up there. But as a point of information, the Tiger Shoal field which I showed you on a couple of these exhibits just to the north of Davy Jones is a good example of what I’m talking about. That’s a four way above the salt weld. Davy Jones is right below the salt weld. But the reason for bringing that up, that 3.2 Tcf field had Miocene sand and two reservoirs that the Tiger Shoal field are two of the biggest reservoirs in Louisiana. One is called the T Sand and one is called the Y Sand. T Sand produced 1.2 Tcf from one level of production, below 11,000 feet and the Y Sand produced almost a Tcf. Against those two sands that were over that huge area but it was all less than half of what the service area looks like at Davy Jones. So that’s why we’re so interested to follow up on these zones that we’ve penetrated and zones that we might penetrate. They cover this whole area. The production industry from the four ways above the salt weld are very intriguing.

So that’s our approach to how we would explain our follow up.


Your next question comes from [Brian Hoosma] – Weiss Multi Strategy.

[Brian Hoosma] – Weiss Multi Strategy

As you get deeper into the lower portions of the Wilcox, why do you guys think there’s a higher likelihood of sand there?

James R. Moffatt

Well if you tied all of the wells to the south and there has been that whole trend that we just discussed starting with Cascade going through Shenandoah to [Skita], the most recent well at [Tibor], you take the Paleo and you identify lower, upper and middle Wilcox and that’s what we’ve done with all the Paleo bugs. The Paleo bugs are matching right on which is why we’ve been enthused ever since we saw that we were running as we expected and had these similar not only Paleo bugs but the environment and deposition that these Paleo micro-fossils are indicating that we have a similar type of depositional [planner]. And if you look at those wells, the lower Wilcox is much thicker than the upper part of the Wilcox. And once again just Geology 101 remember that all this stuff is sitting on top of the Cretaceous unconformity and Cretaceous unconformity is about a 10 million year hiatus and its related to the big meteorite that hit awful close to the Yucatan and basically blew the water out of the Gulf of Mexico.

Imagine the first sands that got brought back into the Gulf of Mexico by the Mississippi River, plopping this stuff down and the thickest part of the section when you see a situation like that is you get your real coarse sand grains, and then as the water starts to clear up and go into the next [inaudible] stratographic unit where you have these deeper water sales come in and you go back into a sand package, well this sand package that we tried to describe to you before, finally we can see the resistivity of the shale’s going up from the top of the sand package at 27,000 feet to the bottom of our last log. The shale’s resistivity’s gotten up to 3 Ohms that were inter-bedded with these higher resistive sands that we saw. And that’s just an indication to us that we’re still in a big sand package that gives you ever aggressive pressure. The same like we had at Blackbeard, like we had at Flatrock. It’s just a textbook type of big sand package.

And that’s why we’re sort of in the top of that. So the Paleo supports it and the control that you have comparing it to the deepwater. But unfortunately that’s just the best that we can do. Remember we’re tying over 100 miles to the south and our data has been so good structurally by showing the fabric or the landscape of the various horizons. Now what we need to do is to get this point of control to confirm that the sequence of the definition of these sands is as is and has been seen in deepwater.

So that’s how we’re using it to project and end. I might add, which I know I’ve already said, but the Tuscaloosa if geo thinks it ties as well in the Tuscaloosa, the Cretaceous Tuscaloosa as it did on the Wilcox, that’ll be underneath the TD on this well and we’ll probably see it on the next phase of well up dip. But if you go up dip to the Fort Hudson trend and the Cretaceous, the Wilcox sands are productive up there but they’re not as well developed as the Cretaceous. So we’re very encouraged that we’re getting the quality of sands we have in the Wilcox which are some of the best Wilcox sands that we’ve ever seen, that the Cretaceous would be even a higher quality.

And that’s why we keep emphasizing this four way dip and almost all the four way dips above the salt weld and the four way dips that we’ve been seeing in deepwater, once you start stacking the sands up, these things load up from grassroots to TD. So those are two reasons why we think there may be some more Wilcox sands and why if we do have Wilcox sands and our Cretaceous sand deeper that we have a chance to keep loading up the hydrocarbons.

[Brian Hoosma] – Weiss Multi Strategy

You were talking about we know we have porosity but we obviously don’t know permeability characteristics yet. How prevalent is it in the Gulf that you could see porosities at this level and not have good permeability?

James R. Moffatt

Well, just based on what we said to you before and that’s why we said we have to obviously see what the flow rate will be. Just looking at the gamma ray [readistivity] and the neutrons [inaudible] process that we have, what that basically is telling you the highly resistive sands have 10 or better Ohms. If there was any shale in those sands, Brian, the [readistivitor] would be damped. Shale inclusion is the only thing that can plug off your porosity and sandstone. As I tried to explain in the last call, just going back to basics, if you put a room full of bowling balls and stack them on top of each other and then put the ceiling and the floor are starting to come together like a big vise, those bowling balls don’t crack. They basically hold up the fabric of the rock. And wherever those porosity units are, air spaces between those bowling balls, that determines how they flow from one floor space to another.

And because of the rounded nature of the bowling balls, you can’t get them all flat to each other. That’s what creates the so-called porosity model. And so if you notice that that means that if you took a giant water hose and then tried to flow it through those bowling balls, it’d go right through the air space. So the only thing you could have that would be blocking your porosity and does in the Gulf of Mexico are the shadier faces of the Wilcox and really involve the different age sands in the Gulf Coast is shale. Shale inclusions in the floor space dampen your redistributor because shale is 90% water and your redistributor log paints it is water in the sand. It lowers your water saturation. That’s what dampens the readistivity. So until we know more about the doggone thing, we’re giving you everything we can give you by evaluation of the logs and the feel we have for comparing it to other areas, but it’s an oxymoron to say that you have a high readistivity shady sand, if you understand what I mean.

[Brian Hoosma] – Weiss Multi Strategy

And the inter-bedded shale, within the sand grains, is the primary thing that would limit your permeability?

James R. Moffatt

You can have some [calcerous] material but generally in a sandstone like this it has this kind of response on the density and porosity logs, if these sands were tight you’d see a lot different indication of advanced neutron. As you remember before we got the resistivity on this log we had seen what we called a density to neutronic cross affect and if these sands had salicious or over growths of parts, that was sucking off the [frosting] then your frosting wouldn’t be there.

So it’s an oxymoron to say that you have a tight, fuller sand if you follow me.

[Brian Hoosma] – Weiss Multi Strategy

At Flatrock do you guys still think that you have like 200, 400 of these unbooked potential out there?

James R. Moffatt

Well, the biggest potential we have is twofold. First, what we’re drilling right now which is the south part of Flatrock, you know these [Jardina] Sands, we’ve been in there. We’ve penetrated the Jardina Sand. The 226 well had about 50 feet of Paleo water and 900 foot of sand. The well produced for some period of time and then watered out.

And we are now using that bore hole to go up dip. Based on all the drilling that we did at the Flatrock we have this area that we’ve served up for you for the last year, showing this other half of the shoe if you will, with the north half of the shoe being that [inaudible]. And now what we’re trying to do is get the third part of that shoe as the structured migration of this now. We know you’ve got your JD Mount and Jardina Sands to the south and it appears we can get high to this well. It’s one, 900 foot Jardina Sand, hopefully pull that section out of the water and then we think there may be other, at least one or two more Jardina Sands below this big sand by correlation to the JD Mount to the south. But that could add the biggest reserve to us, anywhere from 200 to 500 Bcf just depending on how many feet of that big sand you can pull out of the water and whether there’s more than one sand there.

So that’s been one of the big proven undeveloped areas that we have to get a well into to get full credit for the size of that one. And the rest of the reserves are going to come from as you produce these other zones and the Rob-L part that we’ve talked about. It’s very difficult to ever estimate exactly what these reservoirs are going to produce and when you have these engineered type reserves, all you can do, especially in these big reservoirs like the Rob-L 10-4 is to outline and then you have to use recovery factors and all be very conservative. The bigger the reservoir before its produced, the more conservative the reservoir engineer is going to be. Production history is the only thing that will give you a hint as to what the recovery per acre foot these sands are. And frankly, Brian, we just have to see how that goes. So far we’ve had excellent indications in the big reservoir that is bigger than we thought. Some of the other ones perform about as anticipated. Some of them are slightly less. So obviously there will be some that are going to flow more gas.

But after you have so many take points you can’t just keep doing take points. So as production history, Brian, is going to give you the best indication as to what the true reserve is and we need at least probably another year of production to see exactly how some of those curves are going to flatten out in some of your bigger reservoirs. So the jobs at the sites that we’re drilling right now and the reserves that you’ll get from the Flatrock and sands that we identified in the first part of the drilling in the north half of what we’re going to call the shoe will tell you what your ultimate recovery is going to be.

[Brian Hoosma] – Weiss Multi Strategy

And the stuff you’re drilling down south, Hurricane Deep and even Blueberry Hill, do you have anything in your production guidance for next year from those?

James R. Moffatt

That’s why we mentioned it rather than trying to predict production from new wells we just stuck to our plan of our current production and TD’s that we’ll bring on stream will be completed in our acquired properties. Because the Blueberry Hill prospect is just drilling the up dip well, once again when you really [look] at it you saw it took us three wells to finally find. We drilled Hurricane Deep and finally got over the Flatrock, but after three wells out there we got into the big part of the sand section. Blueberry Hill is the same kind of prospect. You’ve got the up dip well which the original hole that we drilled high on the structure that had sand shaled out. Then when we went down to it, the sands have blossomed out and we have that 600 feet of frosting. We had five sands and three of them had pay in them. But the aired extent of those sands when we drilled this well that we’re currently drilling it at below 17,500 this morning, it’s going to be critical to see if those five sands are going to hold up and how they’re going to be distributed.

We know it’s going to be a [stratographic] type trap around the west link of this big Blueberry Hill feature. Until we get this appraisal well down, it’s very hard to push big numbers into a situation because a conservative engineer has to assume that if you’ve got sand and shale out to the east, it might shale out to the south and north and west. We don’t think so, based on the seismic signature which we explained to you. But until we get this well down and see how many of these sands are going to thicken and thin as we go up dip, we’re confident that we’re going several hundred feet up dip of this well to try to pull some more of these sands out of the water.

We had one sand in the water. We had the other sand that appeared to be full, that should be full, going up dip. But we established there was a water level going down dip. So all of those things will go into the possible reserve and hopefully will define more significant areas so that we can the first quarter book those. And then of course we’ve got the Blackbeard well and the Davy Jones well where we have hydrocarbons in the bore hole and because we don’t have the flow test on them, we’ve got the potential for two big structures. We still think Blackbeard could be a Pcf or better, but depending on whether the sand is sticking off the flank. And then we’ve got Davy Jones to see how big that structure is going to be. The sand quality, etc., that we’ve discussed at Davy Jones, the log characteristics and our traditional knowledge of the sand quality is confirmed with the flow rate, there’s where we can add significant reserves and be looking. In 2010 for the most likely place to get new production that you talked about would be at Blueberry Hill because those pipelines that we’re using for Flatrock. Then of course the Jardine, if we’re successful there.

We’ve got capacity at Tiger Shoal to go on and take that above $300 million. But none of that’s in our production because we don’t want to count our chickens before they hatch.


Your next question comes from Anne Cameron - J.P. Morgan.

Anne Cameron - J.P. Morgan

Do you think you could break out that 4 B negative revision just a little bit more? Is there a price revision netted with a performance revision in that number?

James R. Moffatt

All of the above. When you take as many properties that we have, you just have some wells that over produce, some under produce, and then these gas prices have flipped back up and down are responsible for that. But its mainly that, Anne. We can give you a breakdown if you want to well by well, but it’s just taking all those completions. As you can see from that one Slide we’ve got a number of fields that are producing. Some are going to over produce, some are going to under produce and when Ryder Scott takes a look at that with our reservoir engineers at the end of the year that’s why those things go up and down.

Anne Cameron - J.P. Morgan

And how much of the negative revision is [pru] develop?

James R. Moffatt

Well, once you’ve revised it and the breakdown, I don’t know if I’ve got a percentage because there’s so many reservoirs involved. Once again we can get that for you and give you a more precise number.

Anne Cameron - J.P. Morgan

When you guys are looking forward and thinking about the ultra-deep shelf, is it going to be your priority to develop the Davy Jones field, you know, delineate it and start producing from it? Or are you going to try to prove up your concept with other exploratory wells?

James R. Moffatt

Well, frankly as I said on the last call, Anne, once we get the appraisal well drilled at Davy Jones, assuming its’ successful, assuming the big structure is uncomplicated as the seismic seems to indicate that it is, when we get a confirmation, if we can confirm some good flow rates on the first well and prove that there’s [inaudible] plus possible other sands on the appraisal well, then you take a look and see what is our budget for 2010? Our budget for 2010 is going to be pursuing the two basic areas, the ultra-deep we’ve talked about ad infinitum because of all these big structures that we control between Davy Jones now and all the way to Blackbeard. But we’re also going to continue above the salt weld the Flatrock, JD Mount, Blueberry Hill type prospects. We have a big area up there that covers a couple hundred thousand acres that we have in conjunction with our OCS 3 State Lakes 340 we’ve been drilling now for nine years.

We’ve got a number of plays up there, the chief being delineated by the information from the Blueberry Hill well for instance, and so what you’ll see us focusing on is trying to focus on continuing that very successful effort there where we’ve added Flatrock and had JD Mountain and now hopefully Blueberry Hill will be something that we’ll expand on that big structure. And we’ll pursue those things which are right above the salt weld. Those are generally 20,000 to 24,000 foot wells and can be up as high as 18. We think we can drill those wells somewhere between $25 and $30 million. So we’ll have four or five of those in our budget for 2010 and then we’ll look and see how the development of that goes because those are all exploration projects that if we are successful can go at the same quick development mode that we did at Flatrock and now hopefully at Blueberry Hill.

And then below the salt weld, if we have the Davy Jones confirmation well we can look at what kind of financing we want to look at to develop that field. There’ll be a lot of different kinds of money available to us for the development of Flatrock once it becomes an end field drill program and we’ll look at how we finance that as opposed to following up on Blackbeard East and we’ll see. John Paul Jones, I could name other prospects. We’ll just leave those alone for now for industry and intellectual rights. But remember that whole east-west trend that we showed that was the kickoff after the Thunderhorse discovery and after Cascade and Jack, all that Wilcox drilling that’s been done. That’s what we want to pursue and the development of the big Davy Jones structure and any other successes can come out of another type of financing pot.

And of course as you get those wells on production, if these reservoirs are anywhere where we anticipate them to be with recovering these big areas with these high pressures off of the salt weld, we anticipate that they’re going to have some high flow potentials. So with the size of Davy Jones, as I say depending on how big the reserve is, you could have 10 to 20 wells in the next several years that we would be drilling as an infield program or a multi-rig program with the production in proven reserves and proved undeveloped reserves, and giving you the ability to finance that and still to see your wildcat side of the program with the other cash flow.

Richard C. Adkerson

Hey, Jim Bob, we’ve been doing some aggregating here on some of the properties and there were 12 properties where we had these adjustments. There was actually an upward price adjustment because the oil had made it past $2.99 and that was offset by performance, failed re-completion and things like that. So it’s kind of normal things that happen as a result of having this kind of group of properties.


Your next question comes from Neal Dingmann - Wunderlich Securities, Inc.

Neal Dingmann - Wunderlich Securities, Inc.

I know in Blackbeard there was a discussion it would take about 12 months to get the necessary equipment to complete and flow test. Do you have an idea of how long it’s going to take to get to the Davy Jones and kind of where you are? Are you starting to maybe put out some feelers for bids or anything like that at this point?

James R. Moffatt

Excellent question. A lot of the equipment that we rely on now for Blackbeard, which as you know has been ongoing while we were also waiting to see whether we were going to deepen that well to the Wilcox and because of the Tide River discovery in Shenandoah, [Taskita], there’s very strong impulses to want to see what the Wilcox looks there. And then of course you confirm it to the north of the Davy Jones.

So what we’re basically doing is is Davy Jones is seeing the Wilcox basically 9,000 feet high and we would have seen it at Blackbeard. We’re going to be focusing on trying to get both those wells with the Blackbeard deepened and once we complete this run pipe and complete this Davy Jones, as I said we’re going to have an Indy 500 fast track type of approach, depending on what the service flow and pressure can be estimated at, as you know since we’re in shallow water, 20 feet of water, if we can secure all of the equipment and operate in the 20,000 pound surface pressure area, 20,000 to 22,000 pounds, most of that equipment can be available and that can go quick down the line. The pipe can be rolled, the tubing is available, the tree is not an issue. There will be one or two little stumbling blocks like a sub-service safety valve, which is a very important issue to us and of course to the MMS. And those are being worked on and have been being worked on really since we saw the pressures at Blackbeard.

So to answer your question, we’re going to try to get this thing flow tested ASAP. It’ll be nonstop and hopefully we’ll be able to give you some good news. As to exactly the procurement of the equipment, one of the things that we’re talking about doing at the Davy Jones well is to take a core of the rock which will give us some really good feel about this question about permeability and porosity. And why is that important, the permeability and porosity? We’ll give you some idea what the communication and the service is if you flow these wells and what the shut-ins would be. And the answer is we expect some high quality rock there. We’ll see what the rest of these sands look like if there are any below us, but bottom line we’d like to get the well completed and tested and start moving toward getting it on production this year.

So we’ll see. With all the suppliers being challenged now, knowing that this is opening up a brand new area of business for them, there’s already a buzz around the industry of people that are trying to pitch in and help us get this thing flow tested. Because they can see just like we can the multitude of wells that could flow out of this assembly line, if we can get this thing going and get a 20 to 40 well program going in these trends, it’s going to be to everybody’s advantage. So we probably are the most anxious to get the flow test, but I can assure you that the whole gamut of people out there that make all this equipment we’re talking about are just as excited as we are because they can see the multi-faceted development and exploration play that this thing could set off.


Your next question comes from Eric Anderson - Hartford Financial Management Inc.

Eric Anderson - Hartford Financial Management Inc.

I wondered if you could comment a little bit on the latest fleet status report that Rowan Companies put out a few weeks back where they indicated that they had lowered the price for the new Coffin Rig 2U I believe for a period of six months.

James R. Moffatt

Well, suffice it to say the anticipation of Rowan as I just said about the other suppliers, the rig count went to a low of 25 rigs down from 140 several years ago. They can all see that this is an opportunity to put the jack ups back in the shelf to work en masse. So it was just a series of sitting down and working out negotiations to try to get these rig rates as competitive as we could get them. Having said that, we’ve said it before, the big rigs that they have and some of the rigs that are coming out of the yard have a very important ingredient and that’s hook load. To drill these deep wells you have to be able to run these big intermediate string and you have to have these 2 million pound hook loads to be able to do that.

And so that and the big pumps and the big blow out venters, the whole gamut of things, it just makes the bigger jack ups more expensive than the smaller jack ups. Having said that, I think the rates we’ve ended up with are very competitive with what it takes to keep these rigs in the Gulf of Mexico as opposed to them going foreign. And of course the expenses, it’s a high cost to pay for a rig but compared to some of the floaters that are out in the deepwater, they go for $0.5 million a day, it looks like a bargain.

So we’ve got big rig capacity that has hook load, the pump capacity and all of the other things that are necessary for us to do all this deep, high pressure drilling and make these high pressure completions.

Eric Anderson - Hartford Financial Management Inc.

Is there a situation where you could envision you know possibly starting some of the well bores with a less sophisticated rig? You know, say down to maybe 10,000 or 15,000 feet then whipping that offsite and you know having either the Coffin or the Mississippi take over for the remaining 10,000 feet where the pressure is most severe?

James R. Moffatt

What I’d say is it’s going to be all the above. We’re taking a hard look at anything we can do and I don’t want to over promise or under promise here. When you look at the size of these four ways that we’re talking about and the kind of a program that could ensue in terms of the development drilling, and the exploration drilling, just look at what’s happened out in the deepwater and you’ll just see exactly where we think this is headed if this whole four way group of prospects on the shelf is as good as we think they are. It’s going to be all the above and we’ll do just what you’re doing mentally and think about how we can best utilize the rig fleet that exists here and how to reduce the expense of things.

I mean there’s all kind of things you can think about. You can drill to the intermediate depth, set the big intermediate string with the big expensive rig that’s got the hook load, move that off and move it to another well. You can set the big intermediate string and move a lesser rig on to drill deeper, move some of them off to do the completion. I mean there’s some really nice equipment that’s been used in the Gulf for wells that are above 30,000 feet and above 25,000 feet.

And of course some of these locations that we’re going to be drilling are going to be with barge rigs and that’s going to be a huge opportunity for us to reduce the cost of the rigs. The barge rigs are going for 20% of what it cost to take these big jack up rigs into some of our locations, and this Davy Jones complex are going to be with barge rigs.

So there’s all kind of combinations that we’re going through and that entered into the Rowan negotiation.

Eric Anderson - Hartford Financial Management Inc.

What is sort of the logic behind of while you’re logging the Davy Jones well again now as opposed to drilling to the planned total depth of 29,000 feet?

James R. Moffatt

Well, the logic is pretty simple. We drilled the well down to 28,600 and the bit quit drilling so obviously the bit was worn out. We pulled the bit and sure enough the teeth were all eaten up probably by drilling what we think is the lower part of this sand section. And you just have to kind of look at it this way, every time you go in that hole below 28,000 feet you want to make sure you get every bit of information because when you’re below this depth there’s nothing routine. You could twist off. You could drill into some kind of a high pressure formation that would have to raise your mud rate and make it more difficult to log at this depth.

Especially as you’ve heard my dialog about what we expect based on the correlation to other wells out in the deepwater since we think we may have drilled some more sand and are expecting to drill some more sand, this other 450 feet of log could be extremely invaluable to us. And you want to get it while you can, so whether we go back to drilling after we take the log or whether we take the completion is going to depend on what we see in the log. But this 450 feet of hole that’s unlogged is very near and dear to us now that it’s sitting below some of what we consider to be hydrocarbon play that we’ve already reported to you.

So you just take these things as they come. Some of these bits will drill for 500 feet, 700 feet. Sometimes when they quit drilling, they quit drilling and start spinning. At a foot an hour you just can’t afford to sit there and auger that hole and put on one of these cheaper bits gets compromised, and that’s why these things happen the way they do.

Eric Anderson - Hartford Financial Management Inc.

So you’re logging now with the drill pipe assist the way you did the previous one?

James R. Moffatt

Well, let’s hope after spending four or five weeks getting our chops busted by trying to use the LWD and wide line auger and then finally getting a drill pipe assisted and a technique that worked where we could basically circulate this log down. We’re headed in the hole and we’re using the exact same technique. Like I say, let’s hope we’re smart enough to learn by what we learned in time to get this thing logged before and see if we can get this information so we can get on and decide whether we’re going to deepen or take completion or just what we’re going to do, Eric.


Your next question comes from Joan Lapin - Gramercy Capital Management.

Joan Lapin - Gramercy Capital Management

So what are the biggest step production challenges here? And also, when I look at that cartoon you put up an hour ago and you were saying you were waiting with [Lackered] West to figure out what to do since you have those sands that have been productive at Davy right below where you are in Lackered West, is it likely that you’re going to take that well lower now?

James R. Moffatt

All of the above, Joan. We’re looking at all the information daily but we’re looking at the new Tiger well, there’s not a lot of information out on it yet. As you know it’s been announced as a giant, Eocene Wilcox discovery, but unfortunately when they announce these wells you can’t always get the data. The [Caskita] Field just to the east of it is just south of Blackbeard West, the Shenandoah well just east of that, all three of those wells have been drilled since we got off of that Blackbeard. And now with the Davy Jones to the north, and you know we throw these names around but look back at that map. We’re going 100 miles to the south to get information.

Joan Lapin - Gramercy Capital Management

How far is Davy from anything else?

James R. Moffatt

Davy Jones is I think the closest to Blackbeard it’s about plus or minus 90 miles, to Tiger it’s over 100 miles, to Caskita it’s over 100 miles. So you know our seismic database makes all this stuff look close but if you just sit down and look at the map, you’ve got all those wells, 40, 50 wells out there in the deepwater we’re talking about. And then you have this height until you get up to Blackbeard which is about 100 miles. And then you’ve got to go all the way up to Davy Jones. So there’s two wells on the shelf, Joan. On this 200 square mile area two wells that we’re using. And thank goodness our seismic database and the people and our team that’s interpreted it have been so spot on.

Joan Lapin - Gramercy Capital Management

How far is it from Davy to John Paul?

James R. Moffatt

Probably about six miles.

Joan Lapin - Gramercy Capital Management

So they’re pretty close together. I wanted to ask you, you have this huge acreage position now. Are there any time limits coming up on any of that that you have to be concerned about?

James R. Moffatt

Every day. Every day we’ve got the lease position. Some of them have longer periods to run. The John Paul you just talked about, we just acquired that lease. Other leases that we’ve owned for a year, others we have extensions from them and we’ve some on our SOO’s, but all of this lease position that’s why we’ve been trying to get the lease position established before we got all the information on these wells. Because as you can see there’s a lot more attention to the Davy Jones trend and the Blackbeard trend than there was six months ago and there will be a lot more assuming this thing unfolds the way we sort of see our crystal ball taking us.

So you bet you is the answer to your question. Every day is important for us to make certain that our lease positions are secure and that we’ve got enough time to get in here and drill the well before they expire.

Joan Lapin - Gramercy Capital Management

Now you said earlier that these wells above the salt weld, you’re going 20,000, 24,000 feet or $25 to $30 million so that’s a third of a million a thousand. When you took over Blackbeard you spent over $30 million to go another 5,000 feet.

James R. Moffatt

Let me be sure we get this apples and apples, Joan. All of the wells that I mentioned from 20,000 to 25,000 feet in OCS 310 and 340 are drilled from barge rigs. That water’s all 20 feet or less so those barge rigs are much less expensive. We have a barge rig on Blueberry Hill right now. I think the regulator on it is less than $30,000 a day compared to the $180,000 a day on the Davy Jones rig. And all the other equipment that we talk about, when you’re using those barge rigs and drilling and completing in 10, 20 feet of water, which is OCS 310, that’s been the magic of that whole thing. That’s why we were able to get Flatrock on production so quickly. And JD Mount and now hopefully Blueberry Hill.

So when you look at it by cost estimates for the Flatrock mini basin and the 10 to 20 foot water depth, you have to ratchet down and see that to go to these ultra-deep wells and drill below the salt weld and this big intermediate string, the pipe is more expensive, the drilling rigs are more expensive. So that’s why it’s three or four times the cost of drilling these wells in the mini basin. That’s what we like about our program now that we’ve got this Flatrock mini basin, plus it’s a balanced play where if we’re successful with our offset at Blueberry and some of the other things it generates in that area we can have three or four wells drilling up there that we can drill and get down and get on production in 2010 and hopefully move toward our production at Davy Jones and get some more evaluation at Blackbeard West, so we can move these reserves into proven category and get these things cash flowing.

Joan Lapin - Gramercy Capital Management

What are the biggest challenges about producing at these high pressures?

James R. Moffatt

Well, you know, producing at high pressure once you’ve produced things like the deep wells we have at Long Point, for instance, if you go to Long Point that’s a deep high pressured thing. The Jardine that we completed, the JD Mount, those were high pressure completions so the difference between 18, once you get over normal pressures say of 8,000, 10,000 pounds it’s all relative, Joan. You just have thicker steel in your tree, in your pipe, but you know we have wells that flow with 12,000, 13,000, 14,000 pounds of surface flowing pressure in the area right above the salt weld.

And the heat is not quite as hot but it’s still a challenge with the CO2 and the sulphur. So you know there’s techniques from deep, hot wells, like the wells over in Mobile Bay that set records, that were drilled, heck, I guess it’s been over 25 almost 30 years since Mobile Bay was found. Those are deep, high, over 125 million a day wells that had a lot of H2S in them, CO2, so frankly since we’re moving down the chain and the pressures aren’t as high but they’re completing wells below 30,000 feet every day, every hour out there in the deepwater. So fortunately this isn’t our first rodeo. We’ve done these high pressure, high temperature completions. These are just higher temperature and higher pressure. So there will be some new challenges.

Davy Jones is going to be a lot less challenging than the Blackbeard because its shallower. As we’ve said from the beginning we’re seeing that plate almost 9,000 feet up the shelf, which is why we chased it up there to be sure that we learned as much information about it before we got our design finished at Blackbeard West. So two wells on the shelf. Remember that. All this big trend going on south of us, all the known production to the south that I’ve showed you and fortunately we’ve been at this a number of years, producing high pressure completions. Nothing’s routine out here, Joan, but we’ve got a lot of experience and a lot of experienced people that are on board and we’ll get this done.


And no further questions or comments at this time.

Richard C. Adkerson

Thanks everyone. We appreciate your being part of our call and we look forward to reporting further to you as we progress.


Ladies and gentlemen, this does conclude our call for today. Thank you for your participation. You may now disconnect.

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