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McMoRan Exploration Co. (NYSE:MMR)

Q4 2008 Earnings Call

January 21, 2009, 10:00 am ET

Executives

Kathleen L. Quirk – Senior Vice President, Treasurer

Richard C. Adkerson – Co-Chairman

James R. Moffett – Co-Chairman

Analysts

Joseph Allman – J. P. Morgan

Richard Tullis – Capital One Southcoast

Noel Parks – Ladenburg Thalmann & Co.

Kent Green – Boston American Asset Management

Gregg Brody – J. P. Morgan

Gilbert Alexander – [Darfield] Associates

George Froley – Froley, Revy Investment Company

Dan Mcspirit – BMO Capital Markets

Jeff Davies – Waterstone Capital

[Christine Parsons – Clarion Rhode Assets]

Operator

Welcome to the McMoRan Exploration fourth quarter conference call. At this time all participants are in a listen-only mode. Later we will conduct a question-and-answer session. (Operator Instructions). I would now like to turn the conference over to Ms. Kathleen Quirk, Senior Vice President and Treasurer. Please go ahead, Ma’am.

Kathleen L. Quirk

Thank you and good morning. Welcome to McMoRan Exploration’s fourth quarter 2008 conference call. Our results were released earlier this morning and a copy of the press release is available on our website at McMoRan.com.

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

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

Before we begin today’s comments I’d like to remind everyone that today’s press release and certain of our comments on 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 Moffat and Richard Adkerson. I will start by briefly summarizing the financial results and then turn the call over to Richard, who will be reviewing our recent performance and outlook using the slide materials on our website. After our formal presentation we’ll open up the call for questions.

Today McMoRan reported a net loss applicable to common stock of $309.2 million or $4.39 per share for the fourth quarter 2008 compared with net income applicable to common stock of $9.7 million and $0.20 per share for the fourth quarter of 2007. For the 12 months ended December 31st, 2008, McMoRan reported a net loss of $233.6 million, $3.97 per share, compared with a net loss of $63.9 million, $1.86 per share in the 200 period.

McMoRan’s 12-month 2007 financial and operating results include the results from the acquired Newfield properties beginning on August 6th, 2007, acquisition date.

There were a number of special items in our fourth quarter 2008 results as the fourth quarter results from continuing operations total loss of $304 million which included $292 million, roughly $4.14 per share, in impairment charges for certain fields to reduce their net carrying value to fair value.

An unrealized gain of $43.2 million or $0.61 per share for mark to market accounting adjustments associated with our open oil and gas derivative contracts. About $16.8 million, $0.24 per share, of additional charges associated with damage to certain properties from Hurricane Ike last September. And a $9.5 million charge, $0.13 per share, to exploration expense for the Northeast Belle Isle exploration well that was determined to be non-commercial in the fourth quarter of 2008.

Our production in the fourth quarter of 2008 averaged 162 million cubic feet of natural gas equivalence per day net to McMoRan. Production continues to be impacted by shut ins associated with Hurricane Ike in September 2008. For the full year period 2008 our daily production averaged 245 million cubic feet equivalent to date net to McMoRan compared with 152 million in 2007.

Our fourth quarter 2008 oil and gas revenues totalled roughly $112 million compared with $248 million during the fourth quarter of 2007. Realized prices in the fourth quarter of 2008 were $6.77 per MCF. That was 7% lower than the year-ago period which was $7.27 per MCF, and realized prices for oil and condensate averaged $54 per barrel in the fourth quarter of 2008 and was 40% lower than the year-ago period of $89 per barrel. The realizations do not take into account the gains or losses we have on derivative contracts.

Operating cash flows for the year were strong at $623 million. Cash flow in the fourth quarter used in operations totalled $12.8 million and that was net of a $24 million requirement for working capital during the fourth quarter.

The capital expenditures totalled $49.5 million for the fourth quarter and for the year were $236 million. We ended the year in a strong cash position, $93 million, and had no amounts borrowed under our bank credit facility. The debt at the end of the year totalled $375 million and that includes $75 million in convertible senior notes. Our shares outstanding on a basic basis currently approximately $70.5 million and assuming conversion of the remaining mandatory convertible preferred stock and the 5.25 senior convertible notes we would have approximately 88 million shares outstanding.

I would now like to turn the call over to Richard, who will be referring to the slide materials.

Richard C. Adkerson

Thanks, Kathleen. Turning to the slides, when we look back at the year 2008 and also where we are going into 2009 the real success story has been the development of the Flatrock Field. That discovery came in mid-2007. At the time we were doing the Newfield transaction. Since that time we’ve logged pay in six wells; four of those are now producing with the other two expected to come on stream in 2009. We have future potential that we are continuing to evaluate in that area and have two exploration wells drilled in that area and another with similar characteristics to the south of the area. So it’s really key validation of the deep gas exploration strategy that we started a number of years ago and continues to provide great opportunities for our company.

That was focused on wells drilled between 15,000 and 25,000 feet looking for large structures and our exploration philosophy has been validated by Flatrock and other successes. We have three wells currently in the process of being drilled as part of that strategy.

Two-thousand-eight was also exciting because of our opportunity that came to us with the Newfield transaction to test the ultra-deep plays on the shelf of the Gulf of Mexico. At South Timbalier Block 168 we drilled the deepest well in the Gulf of Mexico that’s been drilled below the mud line. It was to roughly 33,000 feet. We saw sands that we are currently in the process of ordering equipment to allow us to complete the well and test it. We’re also looking at the subsequent opportunities that we think have great significance in drilling in this ultra-deep trend.

We set out at the time of the Newfield transaction to reduce debt. We made significant progress in that area. We reduced total debt during 2008 by $426 million, including $141 million in our convertible securities. We ended the year with $93.5 million of cash and nothing drawn under our bank credit facility.

Our 2008 production averaged 245 million a day; our production volumes were very strong until the interruptions we experienced as a result of the hurricanes that have delayed restoration of production because of principally damages to downstream facilities. Our fourth quarter production was lower than we had anticipated because of that factor at 162 million a day, but we’ll continue to work with the pipeline companies and operators of facilities to restore production and we’ll make progress on that in 2009.

We ended the year with 345 BCF equivalents based on Ryder Scott’s estimates of our proved reserves that represented a replacement of 80% of our production and that’s a big positive considering the rapid production declines experienced from the properties we acquired from Newfield.

Slide four has a summary of the information that Kathleen just reviewed to you. I want to talk a bit about the write-off situation on page five. I think most of you know what accounting rules apply here and that requires us to go through and evaluate properties on a field-by-field basis. We first look to see if undiscounted future cash flows based on current prices. We used future prices for our analysis and Ryder Scott reserve estimates. If the undiscounted cash flows exceed the book values then you don’t have a write down. If they’re less than book values you do. Because of prices and other factors we had several fields that we then had to write down to fair values again using year-end futures prices and year-end Ryder Scott reserves. That’s what resulted in the write down. That is, it includes $247 million on properties with proved reserves and $45 million of unevaluated properties. The Mound Point South and JB Mountain Deep properties, where we still have the opportunity to go back and consider what we’re doing with that, but because of the change in our cash flow outlook we wrote off those unevaluated wells as accounting rules require. These write outs have no cash impact. They have no effect on our financial covenant, so they don’t affect our liquidity. And they really don’t affect the way we’re going to approach operating our business as we go forward. It’s just a reflection of the situation that we ended up year end with prices in our reserve estimates. These amounts will be reflected in our DD&A going forward, of course. We won’t have, we’ll have lower depreciation charges.

Looking back on the Newfield transaction because it did significantly change the scope of our business, on page six. We generated significant cash flows. We’ve ended up with properties that have high quality reserves. It gave us expanded scope of operations in the Gulf of Mexico where we were focused on our previous exploration program and where we continue. And it brought to us the high potential ultra-deep opportunity which we’re very excited about. The bar charts show just what the progress we’ve made in reducing debt. Of course we’re really pleased that we were able to do that in light of the current situation in the financing markets.

Since we made acquisition 17 months of operation through the end of 2008 we’ve generated $720 million of operating cash flows. This is better performance than we had anticipated. We had some higher prices, but the production held up. And we’ve been able to maintain increased reserves. At the time of the acquisition we reported proved reserves of 320 BCF equivalents. When we look at what we produced in terms of volumes, production volumes, plus the remaining proved reserves of 231 million BCFs you can see that we actually have higher volumes than we had estimated at the time that we made the acquisition.

Page seven shows our producing, our major producing fields. You can see the South Marsh Island 212 area in the OCS 310 JB Mountain stayed at least 340 area. With the Flatrock wells, the wells that we drilled on shore may pass us to the east. You can see in red the significant fields that are shut in since the hurricane that we’re working to restore. But we do have a spread of properties now that reduces the risk for our company from where we were previously.

Fourth quarter production, as I mentioned, continues to be impacted by the downstream facilities. I’m on slide eight now. We’re currently, while we averaged 162 million a day in the fourth quarter we’re currently up to 200 million a day. Still have significant amount, roughly 60 million a day, offline because of the damages to the downstream facilities. We have a fourth quarter estimate in the 200 million range. We’re working with these third party operators to restore production. We have some costs that we’re incurring as a result of damage to our properties and we are actively pursuing insurance recovery. These costs will be spread over a number of years and we’ll get insurance recoveries as we resolve our claims with the insurance company. Nothing’s been accrued for the insurance recoveries in our results and that will be reported as offset costs as we get the claims resolved.

At Flatrock, as I mentioned, we have now logged pay in six wells. We have a seventh well to schedule to spud during the first half of 2009. We’re completing the number five well, the number 232 well, and we have a well being drilled. And you can see these involved stacked pays and significant pay intervals. This is, as I said, has been confirmed now as a major discovery with ongoing implications for us.

On page 10 you can see in the bottom left the Ryder Scott reserve reports at year end 2008 in accordance with SEC requirements proved reserves were over 350 BCF equivalents gross, 66% to our interest. We have significant behind pipe reserves, only 25% of the reserves are end zones that are currently producing and you can see we have significant behind pipe and undeveloped reserves. The physical location of the wells are shown on page 10. The number 228 well was the first well that we drilled. And then subsequent extensions, delineations, exploration wells have seen significant amounts of pay intervals. The number 7 well will be further test to the south where we’ve had previous commercial production established with our hurricane properties in the past.

Page 11 gives an illustration to really what we’re looking at here. This of course was in the area of the Tiger Shoal/Mound Point shallow production where over 6 trillion cubic feet were produced historically by Texaco. That production is shown in the red outlines. The areas we have currently proven with our own drilling at depth are shown with the lined areas. And then we show areas based on our understanding we gained of the geology that are prospective for us that will give us opportunities to do further drilling if we go forward. There’s still major potential here for us that we’re pursuing.

Our reserve analysis is shown on page 12 starting with 2007. Showing our productions, the additions that we have, and the fact that we replaced 80% of our production, as I said. Given the rapid decline curves inherent in the Newfield properties we were pleased with our reserve replacement activities during 2008. PV 10 based on year-end prices is over $700 million, but if you look at forward pricing of reserves it would be $1.2 billion and there’s significant probable and possible reserves at 3P total is 630 BCF equivalents for the year.

As an illustration of some of the issues you face when you consider reserve data, as all of you know, reserves are not just simply a physical determination of recoverable oil and gas in the subsurface, but it’s also an economic factors. And this was particularly true at our Main Pass 299 oil facility. This was a facility that we developed in conjunction with the development of the sulphur mine in Main Pass 299 in the early 1990s. It had significant early production of over 40,000 barrels a day. Significant reserves have been produced. At year end, based on SEC requirements, the year-end reserves were 10 BCF equivalents. You can see that’s substantially down from mid-year 2008 and end of the year 2007 and that’s because of the significant changes in prices that occurred. That affects, with a property like this, a mature field, the economic limits of that field.

We continue to have exposure to additional significant values if prices were to rise from year end levels. At $100 barrel oil the reserves would increase from 10 BCF equivalents to 23.8. The PV at year end 2008 forward prices would go from roughly break even to over $100 million and if prices were to go to the highs they reached that would be over $200 million at PV. So we’re leveraged to that and it has had an impact when you look at our reserve volume analysis for 2008.

Our reserves are shown on page 14. We have significant non-producing reserves. Not only at Flatrock but at other fields. An important part of our Newfield properties is to convert over time as zone deplete. Convert these behind pipe and pud reserves into producing reserves. We’re 70% gas and 30% oil.

We have three wells being drilled. The Tom Sauk exploration prospect is located on Louisiana State lease 340, which is part of this 150 acres we control that has Flatrock, JB Mountain. Hurricane discoveries previously is less than 10 feet of water. We have 14.5% net revenue interest. We have a planned total depth of 19,000 feet. We drilled the well to 17.7. This lies below the significant shower production at Mound Point. Significant pre-drill attention on this well, we have, we’re in the process of logging this well and based on the results of that log we’ll determine our future plans for where we go with it.

We’re also drilling a well in Louisiana State lease 340, the Gladstone East exploration prospect. We have a 24.5% net revenue interest in this. It was [scrud] in the fourth quarter of 2008 drilling at 15,600 feet roughly targeting a depth of 18,000 feet. It’s five miles east of Flatrock. Again, it lies below the shallow production of the western flank of the old Mound Point field. Significant unrisk potential for this property.

Then we have a very significant potential prospect that’s to the south, 15 or 16 miles south of the production that we had at the JB Mountain Deep well. You can see where it’s located on the map on page 17. It’s just south of [Marshall Island] 251. This has what we believe to be one of the largest undrilled structures below 15,000 feet on the shelf. Its position on the southern part of the structural ridge that extends from Flatrock to JB Mountain, very significant unrisk potential. We have a 21.1% net revenue interest. The well commenced drilling in November 2008. We’re currently just below 8,000 feet with a targeted depth of 24,500 feet. Those three prospects that I just mentioned are the type of prospects that fit within our strategy of drilling for these deep gas wells in the shelf of the Gulf of Mexico.

We have a significant acreage position. We have rights to 1.2 million gross acres, including 227,000 acres in the ultra-deep trend. You can see on the map on page 19 our acreage position and aqua coloured blocks are part of this ultra-deep potential that we acquired in the Newfield transaction in August 2007.

We re-entered the well that had been drilled by the previous partners on this. It’s South Timbalier Block 168. The well is called Blackbeard. It’s located in 70 feet of water. As I mentioned, we drilled it to right at 33,000 feet and have temporarily abandoned it. We’ve logged four potential hydrocarbon sands and these sands need to be tested. To do that we have to work on the design and order special tubulars to allow this well to flow. We’re in the process of doing that now. We operate the well and have a 32.3% working interest.

The cross-section that we’ve talked about before in our previous presentation is shown on the slide on page 21. The well was drilled at the top of the structure and that’s where we saw the sands that we’ll be testing. Our geological analysis of the property indicates the potential for significant thickening of these sands as you go off the structure. In the wedge type analysis that’s shown on the right side of the slide. This is consistent with what others have seen in drilling the Ammazzine sands in the deep water and that’s where we’ll be focused in terms of our subsequent drilling activity to test this theory. This is something we’re very excited about.

Page 22, turning to the financials, again shows what we’ve done with our debt since the acquisition. With the debt offside of the convertible debt we had $1.2 billion roughly at the acquisition. We cut that in half in 2007 and then half again roughly in 2008. So we’ve made very significant progress with deleveragings from the transactions. As you can see on page 23, we have the $300 million is bond debt that’s due in 2014. We have significantly reduced our convertible debt through incenting conversion for that. And we have $75 million of our 5.25% convertible notes remaining outstanding. So the company in these tough times has a good liquidity position.

In 2009 we expect our production to average $220 to $230 million a day. As I mentioned, roughly 200 a day for the first quarter. We’ll be continuing our active drilling program, both in the OCS 310 state lease 340 area as well as Ammazzo. And then focused on our future operations in the ultra-deep related to our drilling of the South Timbalier Block 168 number one well.

Our current outlook for capital spending, and always qualify this by saying that capital spending will be driven by the opportunities we have, the successes we have in our exploration, as well as our steps we’re undertaking to manage our cash flows in light of the lower oil and gas prices. Our current outlook for capital is $230 million in total; $100 million on exploration. Our spending will be driven by opportunities and by our steps we take to spread risk by bringing partners into wells and we’ll continue to evaluate how this fits together in light of the cash flows.

Page 25 gives a sensitivity of those cash flows to changes in oil and gas prices. Earnings, EBITDAX forward pricing is $330 million. If you adjust gas down a dollar in MCF from the forward pricing at $5 a barrel you go to $260 million and increase it by those variances it goes up to $400 million.

Our financial policy will be managed in a way to maintain a strong balance sheet so that we’re in a position to grow in the future. Our capital spending, as I said, will be driven by opportunities and we will manage the capital spending prudently within our cash flows availability. We’ll continue to commit capital because we’ll have the cash flow to do it. The high potential opportunities as we manage our capital. And we will also spread our risks through bringing partners in at appropriate times to give us exposure to more properties.

So our company’s investment opportunity remains intact, even with all the changes that have gone on with commodity prices. We have significant reserves, strong production profile, continue to have exposure to high-impact exploration opportunities, very large acreage position. WE continue to pursue opportunities with our Main Pass energy hub facilities. Our exploration team lead by Jim-Bob has a strong track record over many years of success and with our success at Flatrock and our successful drilling of the ultra-deep well continues to point toward future success for our company. We believe our opportunity has an attractive risk-reward profile with the high potential exploration opportunities that we have.

Jim-Bob is here to answer questions about our exploration activities and we look forward to your questions.

Question-and-Answer Session

Operator

Ladies and gentlemen, we will now begin the question and answer session. (Operator Instructions). One moment please for our first question.

Your first question comes from Joe Allman – J. P. Morgan.

Joseph Allman – J. P. Morgan

Yes. Good morning, everybody. Hey, Richard, you talked about the impact of the change in year-end pricing on the reserves for Main Pass 299. So overall for the company what was the impact on the change in reserves starting off with the revisions? I mean, it looks like you just had a small net revisions, so it seems like maybe you had kind of a decent size positive revision that offset some of the negative revisions.

Richard C. Adkerson

We did and that was the point we wanted to make because the Main Pass was obviously a significant negative revision. The positive revisions really were spread among a large number of properties and principally based on production history. The fact that, well, we went into our properties with significant probable or possible reserves. A lot of that had to do with the way reservoirs performed. So we had the negative revision cost by prices at Main Pass that was offset by really a group of smaller but positive additions from other properties based on performance.

Joseph Allman – J. P. Morgan

Okay. Do you have handy the total negative revision that you had for the company?

Richard C. Adkerson

Well, let’s see. We have it here, but outside of Main Pass there was nothing that approached that. You know, it looks like 10, 13, maybe 15 BCF of total. Total negative.

Joseph Allman – J. P. Morgan

Okay. Gotcha. Okay. And then in terms of the additions, any sense of the, you know, like, the impact on the lower pricing on the additions. I imagine that you weren’t able to add as many reserves because of the lower prices versus what you would have added at 2007 year-end price levels.

Richard C. Adkerson

Well, most of the additions came at Flatrock. And because of the, pricing affects properties like Main Pass where you have high lease operating expenses in relation to the selling price of the properties. With Flatrock, because of the significant volumes, the average unit lease operating expenses really are not a limit, they’re not limit to reserves. So really prices wasn’t a major consequence there. It had to do with our drilling, the success we had with drilling.

Joseph Allman – J. P. Morgan

Okay. All right. That’s very helpful. Thank you very much.

Richard C. Adkerson

Of course, the PVs are another thing, but reserve volumes really weren’t a constraint at Flatrock.

Joseph Allman – J. P. Morgan

Okay. That’s great. Thank you very much.

Operator

Your next question comes from Richard Tullis – Capital One Southcoast.

Richard Tullis – Capital One Southcoast

Good morning. Just following up on the last question a little bit. Looking at the mid-year 2008 reserve number it looked like additions and revisions were about 88 BCFE and now we’re looking at about 55 BCFE. Were there some things that were taken out of the end-of-the-year numbers that were in the mid-year numbers in addition to the impact of mainly Main Pass?

Richard C. Adkerson

Well, there were some down revisions that offset, but that would have been just the normal updates of reserves based on production performance in drilling activity. I think one thing to note is reserves have, you know, our reserve definition is changing. Next year, with the new SEC reserve revisions, revisions to their definitions, there’s going to be the opportunity to take into account technology and other factors related to undeveloped reserves which, for a company like ours, could have the potential to allow us to recognize certain reserves earlier than we could have under the old rules. But this year we were constrained by the SEC reserve definitions that have been in place for 30 years.

Richard Tullis – Capital One Southcoast

Sure. The Rowland, Mississippi, that you contracted for two years, I guess you got it towards the end of last year, how is that performing for you so far on the Ammazzo?

James R. Moffett

This is Jim-Bob. I’ll take that question. The row has had its start-up problems. When he came out of the yard there was some hurricane damage by a rig that was hit. It broke loose in the river and hit the Rowland, Mississippi. So there’s been some down time which Rowlands had to eat. But we are going to get it lined out as usual with these new rigs. Especially this big rig. You always got some problems. But the Rowland people have recognized the problem and all the commissioning and things that would have normally been done before the rig was released is going to be on their time. Anyway, we’re below 8,000 feet on that row. I had [inaudible]. So it’s a big rig. It’ll, the bugs and rugs that you always have with the rigs coming out of yard work are exacerbated by this hurricane damage it sustained when it was hit, when it was being finished. So that’s sort of a general statement.

Richard Tullis – Capital One Southcoast

Thank you, Jim-Bob. From here on out you expect it to perform as it would have prior to the damage.

James R. Moffett

Absolutely. We’ll hold them to the standard that we do all the rest of these rigs.

Richard Tullis – Capital One Southcoast

Okay. Very good. On the 2009 CapEx I know it’s still early in the game. The $100 million in exploration planned for 2009, how many wells do you see that drilling? I know you have Ammazzo, Gladstone, and Tom Sauk right now.

Richard C. Adkerson

We have included in that additional drilling at Blackbeard.

Richard Tullis – Capital One Southcoast

Okay.

Richard C. Adkerson

Although now that’s going to be based on timing as we continue to do our analysis and the timing of the testing of the sands that we’ve seen already.

Richard Tullis – Capital One Southcoast

Okay. Nothing in addition to those four?

James R. Moffett

We have several wildcats that we may or may not [inaudible] in 2009. A lot of these things are being delayed. We’ve already moved a couple of things into 2010 just to let these properties get on production that have been held off the line and let the Flatrock ramp up.

In general, as you say, we spent this year really delineating the reserves that we thought we had at Flatrock. As you remember at mid-year, Ryder Scott numbers were bigger than we’ve ever had on any single property. When you enter a drill, as Richard pointed out, we’ve had six wells that the pay is confirmed. You sort of, when you outline a big area because you have a big sand it looks like it covers a big area. We’ve done two things. All the wells have fit the model and the production history that we’ve had from the wells has [inaudible] based on the well performance as indicated [inaudible] as our people around here refer to it as a big tank. There’s a big tank in the Rob-L and a big tank in the Operc with Rob-L being the biggest, of course. But as the report showed, Ryder Scott’s booking at almost 350 BCF and we think that now that we can go to the south and delineate the southern part of this thing we still believe we’ve got significant potential. Ryder Scott has got a number of resources. Richard wondered if they’re still in the probable and possible category. I think it’s several hundred BCF. That’s just in the Rob-L, the deeper portion of the Flatrock Field. As you remember, the cartoon is the deep Operc and the Gyro data. We could double the number of proven reserves by moving south with the additional wells and having [inaudible] deeper as we have the shallow.

But again, overall with the 3P reserves that Ryder Scott has, generally with the kind of drilling, other drilling we’ve had, you can just about predict that some more of those 3P reserves in the probable and possible are going to be added in significant numbers. We still believe that this is going to be [inaudible] by the time we get through drilling all the additional wells and getting some more production history and delineation on the Rob-L and Operc in [inaudible] reservoir.

Richard Tullis – Capital One Southcoast

Thank you, Jim-Bob. That’s all for me. I’ll jump back in the queue.

Operator

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

Noel Parks – Ladenburg Thalmann & Co.

Good morning. I just wanted to get your sense as we head into the rest of 2009. What are you seeing on the cost side? You know, lower prices, lower activity. Do you think we’ll start to see some improvement on the service cost side?

James R. Moffett

All the rigs are going to come down in rates. Rigs that have been drilling are all finishing their contracts. There’s a lot of rigs being stacked. You’ll read in your general reports that there’s a lot of rig camps that are going to be reduced. A lot of that will be on shore. The number of the shoal gas plays that were hotter than a pistol are all starting to shut down with lower prices. So you have, in general you’re going to have a lot of pressure on the third party sources. As usual, though, if that’s the case they’re going to start bidding lower prices for the work they get from us and everybody’s aware that with the lower oil and gas prices that the activity level is going to go down. So we’re going to have to start trading hard to get these service companies to reduce their bids. It will follow if these prices stay down through the year we’ll see a significant reduction in the cost of third party services.

Noel Parks – Ladenburg Thalmann & Co.

I mean, would it be fair to guess what you were talking about somewhere in the, say, by year end 10% to 15% lower, you think, than 2008?

James R. Moffett

Oh, listen, some of this stuff is depending, if these prices hang around, and who knows. We’ve always said we’re not predictors of pricing. If these prices hang around it could be much more significant than that.

Noel Parks – Ladenburg Thalmann & Co.

Great. And just looking at the drilling that’s on deck for the rest of 2009. Do we, can you give us any sense as to how the exploration expense might shake out? I’m just thinking that maybe because you’ve got a few particularly big projects going that it might be a little lumpier this year than it has in the past.

James R. Moffett

Might be a little what?

Noel Parks – Ladenburg Thalmann & Co.

A little lumpier. A little bit more irregular from quarter to quarter.

Richard C. Adkerson

You know, that all just depends on the success of drilling. We’re under successful efforts, so if we drill to our holes they’ll be charged to expense. If they’re successful they won’t be. So that’s just, you know, that’s just the way the situation is and we can’t predict success. We can set ourselves up for success, but this is exploration. So there’s always the possibility that we’ll drill some dry holes as we go forward.

Noel Parks – Ladenburg Thalmann & Co.

Oh, sure, I understand that. I guess I meant if you have, you know, with Ammazzo and the other couple, you know, Tom Sauk, big projects under way, I just wondering if we could expect in the second half of the year maybe the activity level, I mean, assuming prices don’t rebound in a big way, it might be a little lighter the second half of the year compared to the first half. Or do you think that the extra work at South Timbelier would make that more or less even?

James R. Moffett

Well, let’s just put it this way. We say we’re going to live within our budget. We got to get the rest of these wells back in production. We’ve got some 60-something BCF, 66 million a day. Equipment is not on production yet, so with our 200 million a day number that we’ve gotten to we hope to get all those on production in the first or early second quarter. Then of course we’ve got to get the wells on production that we’ve drilled at Flatrock and those are going to add significant numbers because of the big flow rates. As we get these rates on production and get our income up we said we think it’s prudent to continue to live within our cash flow. So we’re trying to match off those things.

But let me just put the year of 2009 in perspective with the Ammazzo prospect which we’ve discussed to the south of Flatrock. We’ve got a huge potential there because the structure is so big and such a big vertical window of opportunity. We have the same [inaudible] some 9,000 feet of objective there. And if we have sands developed and can stack pays, as we’ve said, our Flatrock discovery has validated that as a model. We left a deeper part of Mound Point, as you said, to continue to see if we can find some Flatrock-type production under that. The problem with that thing is it’s about three times the size of Flatrock and then we got shallow production that we’re trying to drill beneath and see if we can image and repeat what we’ve got a t Flatrock. If all that continues of course that generates additional wells and a bigger part of our budget becomes sort of harder to find whether you’re talking about it being exploration or [inaudible] development when we drill in these areas that we just discussed.

And of course the potential for the Blackbeard well, as we’ve talked about. We sort of have to restrain ourselves when we talk about it because it’s clearly with the fact that we’ve been able to put the missing link between the on-shore and the deep-water Ammazzine plate at Walker Ridge and with the big discoveries at Thunder Horse and K2 and all the places we talked about, we control a huge part of the central Gulf of Mexico with the acreage that we have. Plus the fact that we’ve got one of the only rigs that can go to 40,000 feet. We’re going to be turning up the heat to try to tie up as much acreage as we can now that we believe that plate has been validated. Obviously the flow test that we’ve got to make on the Blackbeard well is very critical to being able to get these reserves into proven status, as we said in our numbers. We weren’t able to book any proven reserves on the Ryder Scott type numbers because we don’t have a flow test. So that’s going to be, we have as big a potential there as we’ve ever had to really being a major play. That’s probably one of the biggest new frontier type plays in the middle of a well established major oil and gas province that exists.

Noel Parks – Ladenburg Thalmann & Co.

Okay. Great. The last questions couple questions I had were just around the former Newfield properties. If I read the table you have in the press release right it looks like about 53% of the fourth quarter volumes actually came from the Newfield properties. I think there was a comment earlier that the volumes from the properties at this point were higher than you had expected them to be at the time of the acquisition. I just wanted to know if there were any particular areas that were more successful than you expected and also if at this point, you know, you’ve had the properties a while and certainly evaluated more of what’s there, if there’s anything from those former Newfield properties that might be moving up the priority list that we might be hearing about and looking into late 2009 or 2010.

James R. Moffett

Well, as Richard said, most of it is based on production history. As we just said, about a big sale like a big [inaudible] for instance, Ryder Scott is going to give you numbers and assign various reserves to individual wells on the Newfield properties that we acquired. When you produce the wells sometimes until you produce the first half of the reserve the probable and possible reserves don’t get recognized until your production history says uh-huh. The reservoir was bigger than Ryder Scott was able to give with all the SEC definitions in the first place and we could go, the gas and water contact or all water contact is [inaudible] than we anticipated. But let’s just say that because of the diversity of properties there’s been in general a better performance than could have been predicted by proven reserves from Ryder Scott for just that reason. Of course as we had hoped to do when we had this nice coincidence of the Flatrock discovery coming right in the shadow of the Newfield transaction being closed we said at that time one of the ways that we could max out those two things that happened at the same time as Flatrock reserve were proven by additional drilling and production was increased it could offset the decline on the acquired properties. With the advent of both of those things that’s why we generally say that we’ve had the positive or replacing 80% of our production at a time when we’re producing 90 BCF. That’s a pretty good target to try to get in to prove category within one year. So I hope that gives you a feel that it’s a result of all of those things that I’ve just discussed.

Noel Parks – Ladenburg Thalmann & Co.

Okay. Thanks very much.

Richard C. Adkerson

I will just add, we were very pleased with the performance and unfortunately it was interrupted by the hurricane, which we knew was a risk of what we had. Now we’re working to get it back on stream. But the overall stories of the portfolio of properties we acquired are performing as we’ve anticipated. There have been ups and downs, but overall it’s doing very well.

Noel Parks – Ladenburg Thalmann & Co.

Okay. Great. Thanks.

Operator

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

Kent Green – Boston American Asset Management

Yes. I have a question pertaining to the test at Blackbeard. As I recall, there was some discussion about exchange of data and other things to get some technology to get a proper treat for the high pressure down there. Could you give us an update on that progress and then any estimate of a time schedule here?

James R. Moffett

Well, a lot of that chatter about saying the data was a little bit overblown. The fact is that the treat, for instance, all of the information that had been assimilated by the group that drilled the original well became the property of the people who continued the well as part of the operating agreement. Suffice it to say that all the equipment is moving along. We still think it’s about a year timeline. The only hiccup that’s developed is one sub-surface safety valve that is sort of going to have to go through some tests that the MMS are going to require just because it’s new. But at this point there are no show stoppers on us being able to get the pipe and all of the well head equipment in the one year fashioned time and hopefully we’ve been working with the Halliburton people and other third party people to get this sub-surface safety valve accepted by MMS and then we can go to work.

Kent Green – Boston American Asset Management

Thanks, Jim. That’s a good update. Another question about Flatrock. Has there been any disruption in Flatrock production? I know that you have a very prolific Rob-L sand that you’ve been producing from, where you get your bigger flow rates, but you’ve also been out testing in some of the wells and producing from the Operc. Is there a bit of, is there any merit to putting more production wells down into this Rob-L sand or are you comfortable where you’re at now?

James R. Moffett

Well, frankly that’s a great question. We’re still trying to look at the success of the six wells. When you end up with these stack pays, as we’ve said in the past, you try to be sure you don’t over drill the field. With the big reservoir performing as well as it has in the Rob-L and in particular one Operc sand that’s been performing, we’re trying to assess where to take completion [inaudible] in the 232 well, which is going to be perforated later this month. We have the big sand that we talked about in our release, and then we drilled into some Operc sands that are deeper than that. Well, we decided we have to take the Operc completion in this well because it’s the best bore hole to get the deep Operc that’s going to leave the Rob-L sand behind pipe. Those Operc sands may flow 25 to 50 million a day if you look at the Operc in the 228, which is substantially less than the big Rob-L pay flows that flow as high as 100 million a day with several thousand barrels of distillate. Frankly the number six well is currently drilling. As we just announced, we had some Rob-L pay in it and, as we had predicted, the Rob-L gets better to the south as we reach the up lid shale out of that big Rob-L pay which is trapping all the down production in the big sands. And underneath that we’ll have the Operc which we haven’t drilled yet and we’ll also get a look at the big Gyro data same.

So to answer your question specifically, we need to look and see when we really know how much of this Operc that we’ve got to take that leaves the other sands behind pipe, how much, many more [inaudible] we want. And of course the whole reason for doing that is since we’re in 10 feet of water and these wells are going on stream as fast as they are, I think we’ve already produced 30 or 40 BCF from the field in just the short time it’s been on production. We need to look at how we can maximize the money that we’ve already spent. These wells cost $40 million to $50 million to complete and then the big southern facilities. And if we can take these sands and water and still be satisfied that we’re tapping the big high flow rate saying to get out production to the levels that we wanted you could have a well that produces three years at an Operc sand and you plug back and produce four to five years in Rob-L sand. That’s getting that kind of a reserve out of a well maximize the profit through all the money we’ve already spent. That’s really the key to this field is to not only find the reserve, but to maximize the profitability of the gas and oil that you produce out of the field. The field is producing right now just over 200 million a day equivalent and that’s ramping up quickly. The 231 well that’s being ramped up is producing about 60 million a day and by the end of this month it will be at 90 million a day and be producing two or three barrels of distillate.

So we’re just going to have to look at these things because these are terrific wells, the most prolific wells ever drilled on this shelf. There’s only been maybe 5% of the wells that drill on the shelf have ever produced more than 50 million a day. So we’ve got an excellent opportunity here to have high flow rates and a long well life in these bore holes that we spend the money on.

I hope that kind of, without rambling on, I hope that tells you the challenge that we’re looking at as we assess not only the success of our drilling, but the ability to gauge the performance of the reservoirs and to confirm the size of these reservoirs.

Kent Green – Boston American Asset Management

Thank you.

Operator

Your next question comes from Richard Tullis – Capital One Southcoast.

Richard Tullis – Capital One Southcoast

The $55 million in CapEx for 2009 that was kind of shifted from 2008, what’s the details on that one, Richard, if you can?

Kathleen L. Quirk

Richard, this is Kathleen Quirk. That’s just really costs that we incurred during 2008 that wil be funded in 2009 when we report our capital expenditures on a cash flow statement. Those are on a cash basis, so we’ve got costs of exploration development costs that have been incurred that will fund in 2009.

Going back to the question about the timing of our capital spending of the 230, it’s slightly more weighted, at least at this point, to the first half. It’s probably 60% or so to be spent in the first half versus the second half. But that will continue to be reviewed. We will have the funding required related to the 2008 costs that we incurred. In the first half of the year.

Richard Tullis – Capital One Southcoast

Is the $55 million predominantly for one project?

Kathleen L. Quirk

No, it’s a whole host of capital spending that is the timing of which we don’t find until 2009.

Richard Tullis – Capital One Southcoast

Okay. How much Blackbeard cost, expected cost is in the $100 million 2009 CapEx?

Richard C. Adkerson

Let me check on that.

James R. Moffett

I think it’s about, my recollection is about $35 million.

Richard Tullis – Capital One Southcoast

Okay.

Richard C. Adkerson

Good recalling, too, Jim-Bob. It’s $32 million.

Richard Tullis – Capital One Southcoast

And what’s your expected DD&A rate for the first quarter of 2009?

Richard C. Adkerson

Excuse me?

Richard Tullis – Capital One Southcoast

Expected DD&A rate for the first quarter of 2009. I know it’s going to go down because of the –

Kathleen L. Quirk

We averaged roughly $4.50 per MCFE in 2008 excluding the impairments. The rate in 2009 will average roughly $3.50.

Richard Tullis – Capital One Southcoast

Okay. Okay. I think that’s all I had. Thanks very much.

Operator

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

Gregg Brody – J. P. Morgan

Good morning, guys. Just a question with respect to the accelerated timing of the future abandonment costs. Do you have to post any letters of credit for that?

Richard C. Adkerson

No.

Kathleen L. Quirk

No. We have a letter of credit $100 million in favour of Newfield that was related to the acquisition, but we don’t have any bonding requirements with MMS.

Gregg Brody – J. P. Morgan

Okay. And do you have any sense of timing of when you’ll incur those expenses?

Richard C. Adkerson

Well, that’s something that is subject to how we actually contract to get the work done, how we design the plans. We try to do this in the most efficient way. We obviously want to get things down before we have another hurricane season, but while we have that budgeted our historical practice is that, our experience has been it takes longer to get these costs expended than we anticipated. That was the case in 2008. We’re going to try to get as much of the work done in 2009 as we can. This is our, you should treat the number we gave you as our best estimate of where we are right now. There is a likelihood, possibility that the costs will take longer than that to incur.

Gregg Brody – J. P. Morgan

That’s helpful. And then just checking, your borrowing base stepped down to $400 million this quarter?

Kathleen L. Quirk

Right.

Gregg Brody – J. P. Morgan

Yeah. That’s right. All right. That’s it for me.

Operator

Your next question comes from Gilbert Alexander – [Darfield] Associates.

Gilbert Alexander – [Darfield] Associates

Hi. Getting back to your DD&A, do you have a figure for the year? Would it be something like around $770 million?

Kathleen L. Quirk

Yeah, you could just multiply the guidance we gave you on the average production rate.

Gilbert Alexander – [Darfield] Associates

Right. That’s what I’ve done. Thank you.

Operator

Your next question comes from George Froley – Froley [Short].

George Froley – Froley, Revy Investment Company

Hi, gentlemen. How are you guys doing?

James R. Moffett

Good morning, George.

George Froley – Froley, Revy Investment Company

How are you all? When you say $200 million for the first quarter is that just gas or is that equivalents?

James R. Moffett

Gas equivalents.

George Froley – Froley, Revy Investment Company

What’s the breakup between gas and oil?

James R. Moffett

Oh, boy. Let’s see. I think it’s....

Richard C. Adkerson

Gas and oil. Core production. Hang on just a second, George.

James R. Moffett

Yeah, George.

George Froley – Froley, Revy Investment Company

Because I’m noticing there’s a tremendous drop in the table on the handout on page Roman numeral three. There’s just a huge drop in production from the fourth quarter of 1 million barrels in 2007 down to 608 this year. Is that just the depletion of the Newfield field or is it because of the pipeline problems?

James R. Moffett

Something about, George, that’s why I’m hesitating to give you the numbers off the top of my head. The 66 BCF [inaudible] shut in right now. A substantial portion of that is oil. And of course with, even with those things shut in it really boggles your ratio. That’s why it’s not on the tip of my tongue.

Richard C. Adkerson

George, let’s say it’s 70/30 and we’ll get back with you if it’s significant. But that’s what our reserves are and that’s what our history’s been. As Jim-Bob said, it’s knowing which properties are curtailed or not could have a change on that.

James R. Moffett

And you remember, George, that it’s hard, Flatrock where the wells are making 50 million a day out of the Operc and 1,700 barrels of distillate and then the bigger wells that flow 80 million, 90 million, 100 million a day, they average about 2,700 to 3,000 barrels a day. So that condensate, of course, is [inaudible] but when we talk about our daily production we talk about equivalents.

George Froley – Froley, Revy Investment Company

Okay. Is there a point here at these low prices it would pay just to shut in some of these big wells and not give away gas at less than $5 and oil at $30-something?

James R. Moffett

Well, that’s a path we always walk down. That’s part of the blessing and the curse of this doggone hurricane. The wells that have been shut in because of this rapid price drop that reserves are still in the ground. When they come on production, if there is an improvement in oil or gas prices we’ll get the benefit of that, George. Obviously on your properties that are cost sensitive you almost don’t have any choice to either not drill them or leave them shut in. But the facts are, with our stuff on the shelf, especially the big wells, the cost to produce those things is so low in comparison to the deep water production or other production that may be, has to be have advanced production so it wouldn’t have high sulphur and all the other things that drive up the cost of production. Those are the kind of things that will really have to be looked at as curtailed.

George Froley – Froley, Revy Investment Company

Okay. Now the hard question for you. Can we inject oil into the Main Pass storage thing? Can we put oil back into that sulphur cavern?

James R. Moffett

Oh, that is, you know, we can store anything. Oil, gas, liquefied gas. You can store just about anything in that big dome.

George Froley – Froley, Revy Investment Company

So why don’t we fill down one of these tankers that’s slow steaming with a load of oil, pay him –

James R. Moffett

Don’t worry. All of that’s being looked at in great detail. We don’t talk about it much anymore because we’re so busy with our exploration stuff. But the tanker companies are looking very hard to storage at Main Pass. Not just for oil, George, but there’s a huge amount of propane/butane that’s floating around too and people hear about these big giant tankers that are full of oil, but you got a lot of petroleum products. So those are in the offing and all that’s being studied and we’ve made progress looking at that since we have the only dome in the Gulf of Mexico in the water that’s actually capable of storing half a billion barrels.

George Froley – Froley, Revy Investment Company

We could sell the futures, you know, April $57 and we could pick up 20 bucks a barrel and lock it in for a year plus.

James R. Moffett

Well, that’s been the whole premise of the Main Pass energy hub to begin with. Unfortunately with the gas prices down so low all the LNGs going to other foreign ports. But the oil and other liquid products like propane/butane, that’s been the basis of our whole plan and while we’ve kept this energy hub sort of working toward being able to give people the option on prices just as you’ve described, clearly if you have in the tank and the oil is not being consumed put it in the big tank and you’ll recover 100% of it and play that option market as you just described. Especially when there’s a [contango].

George Froley – Froley, Revy Investment Company

Yeah. I mean, it’s just, we got something nobody else has. That’s what I was thinking.

James R. Moffett

All of the above, George. We don’t ever put a tank in. We’ve got great assets. We got to unite out of them all.

George Froley – Froley, Revy Investment Company

Last quick question. Is Ammazzo going to be Operc and Gyro? Is that what you’re expecting there or is there going to be something entirely different?

James R. Moffett

The Ammazzo is, we believe based on seismic projections that it will be the Rob-L, Operc, and Gyro down there. It’s the same objective we’ve been talking about for years now in this Mound Point, Hurricane, JB Mountain, Flatrock area. This is just to the south of it and it appears to be on the same structural ridge with similar type closure. So if the sands are distributed that far down deep, which we believe is going to happen, we will have a window of opportunity that’s about, I think we measured the darned thing to be about 8,000 feet thick where you could get the Rob-L and Operc down there as you move from north to south just like the model we been playing at JB Mountain, etcetera.

George Froley – Froley, Revy Investment Company

So those things could all be hooked up. It could go Flatrock, Gladstone, all the way down to Ammazzo.

James R. Moffett

Ammazzo. All of it would go into the existing facilities. I think Ammazzo is in 25 feet of water; the rest of them are in 10 to 15 feet of water. But they’re all immediately off the crows line in the vicinity of that big production facility that Texaco had in there that is now Chevron controlled.

George Froley – Froley, Revy Investment Company

So of our 345 BCF by Ryder Scott only 20% are attributable so far to Flatrock. And you think even if we did nothing this year besides picking up these southern wells our reserve would go up significantly because they’re picking up more zones in the south.

James R. Moffett

If our lower Operc, you’re talking about Flatrock now. If these Operc zones continue to the south and then the Gyro does lie underneath them that’s when we’re hoping to be able to add the other half of this shoe. If you just, I always compare it to us using the shoe and lay it and say it’s the big sleeping giant and the Rob-L was in the heel part of the shoe, and then the Rob-L/Operc is in the centre of the shoe, and then the Operc/Gyro would be in the toe of the shoe. So we’re walking right down the shoe trying to see if we can fill up that shoe.

George Froley – Froley, Revy Investment Company

Okay. That’s good.

James R. Moffett

And Ammazzo will have exactly the same model. It’s just a duplicate model. If you look at the cartoons that we’ve been working with it lays in there and it’s another big shoe, we hope.

George Froley – Froley, Revy Investment Company

Oh, that’s good. Well. Thanks for answering my questions. I appreciate it, you guys. Have a good day.

Operator

Your next question comes from Joe Allman – J. P. Morgan.

Joseph Allman – J. P. Morgan

Yeah, sorry about that guys. Just one quick one. In terms of the impairments, can you talk about the field that’s suffered the biggest impairments?

Richard C. Adkerson

You know, it’s really spread equally among, you know, in terms of the biggest top 10 fields, you know, it ranges from 10 million to 30 million and that includes the write off of JB Mountain and Mound Point south wells which were deferred, actually, as unevaluated properties. But it includes Garden Banks 625 and then there were four Newfield properties that were in the $15 million to $25 million range. So it’s not like there was any one big field, but it was spread over a number of fields.

Joseph Allman – J. P. Morgan

Okay. Very helpful. Thank you very much.

Operator

Your next question comes from Dan Mcspirit – BMO Capital Markets.

Dan Mcspirit – BMO Capital Markets

Folks, good morning. On Ammazzo, I recognize it’s early innings in drilling the well, but can you speak to the timing of additional data points of setting string to TD to lobbying, recognizing again however far out in the future those data points may be.

James R. Moffett

I got you. The intermediate string will be the first big string and we’re doing the same, we’re drilling below 8,000 feet. We should be at 11,000 feet without any, if we have no more mechanical issues. We should be at 11,000 feet here in the next couple of weeks. But among that intermediate string, that’s the big string which gets you the ability to get through those oil pressured sands. Then we’ll start writing up our mud and going into the deeper section. We sort of, we’re probably a long way away to pick our pipe point, but there will be one and possibly two more pipe points being what you have to do there is look at say a month to drill to the next drilling and set casing at the next pipe point. If you get that casing set and you get what we call a leak off test where you basically just pressure up your mud system to find out how much mud rate your can hold, if you get lucky and get and 18.5 or 19 pound leak off test on that second string then you can drill maybe all the way to the bottom with that sort of a casing design. But let’s just put it this way, the next 60 to 90 days we’ll start to get deep enough in the shoe, since I’m using that as an example today, we’ll start getting deep enough into the shoe that we’ll start seeing the top part of that objective section and within the next 120 days we’ll be really in the middle of that shoe and going to start to be confirming whether the sand are deposited on the far south and whether they’re trapping.

Dan Mcspirit – BMO Capital Markets

Got it. Thank you.

Operator

Your next question comes from Jeff Davies – Waterstone Capital.

Jeff Davies – Waterstone Capital

Thanks. Your cash flow sensitivities slide, is there any basis assumptions in there that is typically realized right on top of annex?

Kathleen L. Quirk

Yeah, it’s pretty close to that.

Richard C. Adkerson

And what’s up for the Main Pass production where we have, because of the high sulphur content and we have a discount from the oil for Main Pass.

Jeff Davies – Waterstone Capital

Right. Okay. And what specific third party downstream facilities are you waiting on?

James R. Moffett

Oh, there’s three pipelines. I don’t know if they have lab production people on there. I hate to say the names of the pipelines. I might get somebody mad at me for talking about their pipeline. But there’s three major pipelines that have had the big problem and rather than come off the top of my head with their names we can get that for you.

Jeff Davies – Waterstone Capital

Okay.

James R. Moffett

I think everybody’s bottlenecked by some of the same pipelines. The repairs that they’ve had to do are just unprecedented. Even after Ivan it was just amazing how these two storms whacked the pipelines and a lot of it is lines that were just severed. Then there’s other problems with the so-called plants that are along these lines that remove the liquids. A lot of them went underwater. They’re rebuilding and moving them higher. They keep moving them higher and Mother Nature keeps trying to see how high she can reach. Hopefully they’re going to get that resolved. The other thing that’s been kicking their tail has been the winter season weather. The season’s been so rough that they haven’t been able to stay on schedule. What happens in that situation, you know, we and other companies are held hostage. Pipeline companies go out there and try to work with some of that equipment in these blue northern and they get so expensive because they have so much down time waiting for the weather to calm down that they just finally pull off and say we’re going to wait and let these seas calm down. That’s just the hazard of being in the offshore, even on the shelf.

Jeff Davies – Waterstone Capital

You talked about –

Richard C. Adkerson

The major pipelines though in the system, it’s ANR Stingray, Hile, and Sea Robin.

Jeff Davies – Waterstone Capital

Okay. And you just talked about Main Pass a couple minutes ago. You guys have been spending anywhere from a million to two million bucks a quarter on that. Do you see that number going up or down significantly?

James R. Moffett

Well, we’ve been looking at everything that we can do to continue. When we made the Newfield purchase we were able to combine a lot of the boats and helicopters out there. We’re still looking at that. We’ve been trying to get the barging cross down. Barge it all out of there. And of course we look at the penalty, the sulphur penalty which can go anywhere from $3 to $8 a barrel depending on which refineries have space. There is a way to continue to push your savings. The thing about Main Pass that’s important, that’s why we put the sensitivity slide in there, is you can see the value of Main Pass has been affected severely by the $40 oil range as opposed to the $100 range as you might expect. The field is still on the same decline curve it’s been on, but the number of barrels you can book this year because of the economic lines cut off with these higher production costs has a major impact on the field. But you run a model based on the projected reserves and the number of barrels that we think we can produce I’ll bet you haven’t really changed. It’s just a case of when you apply the economic shut down of the field. So we will work hard to try to keep moving that cost curve down as you suggested to be able to make money at these lower prices.

Jeff Davies – Waterstone Capital

Sure. And last one for me. I don’t know if you touched on this, but looking on some risks it looked like you may have had some mechanical problems at Tom Sauk. I’m just curious if there’s any colour there or kind of how much down time you’ve had there in drilling that well.

James R. Moffett

Well, we’ve had one uncontrolled flow where we had drilled and set pipe, as I was talking about getting the leak off. We were barrelling the head thinking we had gotten the leak off and it would let us go deeper. And we had it flowed and we had to basically see that off the whole and sidetrack from about, I guess we went from 16, we were down at 16,000 feet and we had gotten down to close to 17. We had to plug back and re-drill the hole and set another ladder at 16,000 feet and did a 19 pound leak off. But we’re making progress and we’re below 17.5 heading for 19,000 feet. We ought to be able to finish that up and assuming we don’t have any more problems they’ll finish that one up in the next three to four weeks.

Jeff Davies – Waterstone Capital

You’re going roughly how many feet a day there then?

James R. Moffett

Oh, at those depths you average anywhere from 10 to 20 feet per hour. When you get to the bottom and get grooves you can average maybe 12 feet a day.

Jeff Davies – Waterstone Capital

Okay. Appreciate it.

Operator

Your next question comes from Kent Green – Boston American.

Kent Green – Boston American Asset Management

Just a couple housekeeping questions. Since you were profitable, Kathleen, in the first part of the year did you accrue any taxes in that year and have you reversed them? And then do you capitalize interest at all or are you just expensing interest expense?

Kathleen L. Quirk

We did not accrue any taxes during 2008. We do capitalize some interest. It’s not a huge amount, but we do capitalize some interest consistent with the accounting rules.

Richard C. Adkerson

Yeah, you don’t really have a choice, Kent.

Kent Green – Boston American Asset Management

Yes, I understand. Thank you.

Kathleen L. Quirk

Just back in the housekeeping category, I just wanted to clarify the depreciation question that Gil had about the total dollar amount. The unit rate is $3.50 and if you use our production, the mid-point of our production you have guidance for the year of $225 million a day you get roughly $290 million total for the year, which I think he had a different number in his calculation. But it’s roughly $290 million for the year.

Operator

Your next question comes from [Christine Parsons – Clarion Rhode Assets].

[Christine Parsons – Clarion Rhode Assets]

Hi. My question relates to your cash position and possible uses of that. You have $93 million on the balance sheet. If you look at the forward curve you could possibly generate free cash flow even in 2009 with your preliminary budget. So would you look to increase capital spending or would plans possibly include repurchase of debt with some of your debt trading here in the mid-70s?

Richard C. Adkerson

You know, if you put it all together we would show using our cash for our capital expending. But we’re continuing to review our program. We’re looking to bring partners in and that’s going to be a dynamic thing. But we’ve got enough opportunities in our business that we believe investment of that cash and the cash flow that we generate makes sense for us.

[Christine Parsons – Clarion Rhode Assets]

Okay. Thank you very much.

James R. Moffett

Let me just add to that as sort of a summary of our thoughts about exploration in 2009 and beyond. We think that it’s prudent to take these revenues that we’re fortunate enough to be able to generate and save them for the big hit. We’ve been successful in outlining several different areas on the shelf, both in the deep gas play and the ultra-deep play. As a result of the information we’ve gotten from the Blackbeard well and from the drilling and production of the Flatrock area, this model which has really now been verified gives us the opportunity to sit back and try to pick out the five or six big plays for the year that we’re going to be looking at and try to keep exposing our shareholders to the real opportunity to the 100 trillion to bigger fields. We’re not going to go for any small shots. We think we’ve got the model plus the techniques and experience drilling deeper wells that appears to be unique in the industry right now. Therefore, we’re going to go to our strong suite and try be sure that we preserve as much capital as we can so when we swing for the fences we’ve got the money to be able to do it. To be successful even at $5 gas and $50 oil on the shelf and the deep road or the deep play because of the fact that we can put them on production in such a short fashion and spend 10% of the money that you’d spend putting production on deep water gives us a huge opportunity here since we are playing the shelf and sort of have a play ground that we are defining the rules in.

Richard C. Adkerson

And Christine, we do recognize that our view is our debt is a good value right now for investors. So we recognize that. It’s just that for the reasons Jim-Bob laid out we’re looking to create assets with our program.

[Christine Parsons – Clarion Rhode Assets]

I appreciate that. Thank you.

Richard C. Adkerson

All right, Operator, I think that completes our question-and-answer period. We appreciate everyone’s participation and interest in our company. As always, we’re available for follow up questions that you may have after you review our press release and data.

James R. Moffett

Thanks for being on the call, everybody.

Operator

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

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Source: McMoRan Exploration Co. Q4 2008 Earnings Call Transcript
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