McMoRan Exploration Co. Q2 2008 Earnings Call Transcript

Jul.25.08 | About: McMoRan Exploration (MMR)

McMoRan Exploration Co. (NYSE:MMR)

Q2 2008 Earnings Call

July 17, 2008 10:00 am ET


James Moffett – Co-Chairman

Richard Adkerson – Co-Chairman

Kathleen Quirk – Treasurer and Senior Vice President of Finance and Business Development


George Foley - Foley Investment

Gregg Brody - JPMorgan

William Dobbs – Merrill Lynch

Michael Henzi - Sterne, Agee & Leach

Kent Green - Boston American Asset

Gary Nuschler - Jefferies & Company

Nicholas Pope - JPMorgan


Ladies and gentlemen, thank you for standing by. Welcome to the McMoRan Exploration second quarter conference call. (Operator Instructions) I would now turn the conference over to Ms. Kathleen Quirk, Senior Vice President and Treasurer of McMoRan Exploration.

Kathleen L. Quirk

Thank you. Good morning everyone and welcome to our second quarter 2008 conference call. Our results were released earlier this morning and a copy of the press release is available on our website at

Today’s conference call is being broadcast live on the Internet and anyone may listen to the conference call by accessing our website homepage and clicking on the webcast link for the conference call.

As usual, we’ll also have several slides to supplement our comments this morning. We will be referring to the slides during the call and they’re accessible using the webcast link at

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

Before we begin today’s comments, we’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.

Also on the call today are Jim Bob Moffett and Richard Adkerson, McMoRan’s Co-Chairmen.

I’ll start by briefly summarizing our financial results and then turn the call over to Richard who will review our recent performance and outlook. As usual after our remarks, we’ll open the call for questions and Jim Bob’s available to respond to any questions.

Today McMoRan reported net income applicable to common stock of $60.3 million, $0.75 per fully diluted share for the second quarter of 2008, which compared with a net loss of $6.5 million, $0.23 per share for the second quarter of 2007.

Our second quarter results were net of a loss of $43.2 million or $0.49 per share for unrealized mark-to-market charges associated with our open oil and gas derivative contracts.

These contracts have not been designated as hedges for accounting purposes, so they’re subject to mark-to-market fair value adjustments and unrealized gains and losses are recognized immediately in our operating model.

We also recorded an $18.9 million, $0.21 per share non-cash charge associated with stock option expense under applicable accounting rules.

For the quarter, our diluted net income per share reflected full conversion of McMoRan’s outstanding 6% convertible notes, our 5.25% convertible notes and our mandatory convertible preferred stock, and the dilutive effect of outstanding stock options and warrants into a total of approximately 31 million shares resulting in exclusion of $1.3 million in interest expense and $4.4 million in dividends in the diluted net income calculations.

As you’ll see from our press release and slide materials our results continue to benefit from last year’s acquisition of the Newfield, Gulf of Mexico shelf properties and the significant drilling success we’ve had recently, particularly at the Flatrock Field, which Richard and Jim Bob will be talking more about.

Our second quarter production in 2008 averaged 294 million cubic feet of equivalents per day, net to our interest. This was significantly above last year’s second quarter of 54 million a day.

Our second quarter production rates were higher than what we had estimated in April 2008, which was 285 million a day. That was despite a 5 million a day impact from the assumed loss of royalty relief.

Under the MMS regulations, if prices are above a threshold, and for 2008 that’s $10.38 per MMBtu, the royalty relief is lost and we’ve assumed in our estimates that prices will exceed the threshold of $10.38 and we’ve reduced our volumes for the assumed loss of royalty relief.

Our second quarter oil and gas revenues totaled $372 million. That was again significantly higher to last year’s $45 million and our revenues also included a reduction of $3.9 million associated with the reversal of royalty relief recorded in the first quarter of 2008.

Oil and gas prices before hedging in the second quarter have averaged $12.11. That was 50% higher than the year-ago average and oil prices averaged $123 per barrel. Those were nearly double the year-ago period.

We generated strong cash flows. Our earnings before interest taxes, depreciation and exploration expenses for the quarter totaled $269 million and our operating cash flows were $209 million.

We’re continuing to use capital expenditures to expose our shareholders to the significant potentials from our exploration program. Our CapEx approximated $60 million during the second quarter; year-to-date, was $111 million.

We took steps to reduce debt. Our total debt approximated $305 million at the end of the second quarter. That was excluding the convertible notes that are significantly in the money and several of those have converted subsequent to the quarter. The debt was $280 million lower than at the start of the year and notably our debt is nearly $900 million lower than at the time of the acquisitions last August.

A couple other details: our basic shares outstanding currently approximate 63.8 million and reflect full conversion of our 6% convertible notes, which were due to mature on July 2, 2008. If we assume conversion of the mandatory preferred stock and 75 million in remaining 5.25% senior convertible notes, we’d have approximately 85.6 million shares outstanding.

I’ll now like to turn the call over to Richard who will be referring to the slide materials and commenting on our recent drilling success and outlook.

Richard Adkerson

Thanks, Kathleen. The first slide on Page 3 reflects the record quarter that we’ve had in the second quarter of 2008 and Kathleen just reviewed the details of that with a comparison with the prior year’s quarter.

I’d like to point out specifically the level of operating cash flows that our company earned in the second quarter of over $200 million and almost $400 million for the first half of 2008 during which time we had a total for the first half of $111 million of capital expenditure. The company is generating substantial excess cash flows at a time when we’re adding to our reserves and our production level.

In Page 4, the chart demonstrates the success that we’ve had and the achievement that we’ve had in achieving our objectives of reducing the debt that we incurred last year in connection with acquiring the properties from Newfield.

At the time of the acquisition we had $1.2 billion of debt excluding the convertible notes; now we’re down to just $300 million. As the insert at the top right-hand corner of the page shows, pro-forma for the conversion of our notes, just after the end of the quarter, we have our debts down to senior notes that we issued in connection with the acquisition as well as convertible debt which has a conversion price of $16.57, and of course is included in all of our fully diluted numbers.

Page 5 shows the profile of our production on MM equivalent on a daily basis. It has been adjusted as Kathleen noted for the assumed loss of royalty relief because of the strong level of natural gas prices during the year. During the second quarter, we’re just under $300 million a day.

We have a total of 144 fields. A majority of our production comes from the 18 fields that are listed on Page 6. You can see the contribution of our legacy exploration successes that we had in McMoRan before the Newfield deal, as well as the Newfield production which is concentrated in the central part of the Gulf of Mexico.

Page 7 summarizes our recent Flatrock results. The Flatrock No. 2 well, which had 8 sands, almost 290 net feet of pay commenced production in early July. We have now ramped up that production level to 90 million per day and 2,000 barrels of oil gross. That’s well over a 100 million a day, and 19 million a day to our company.

The No. 3 delineation well, drilled to the deeper Operc Pay, also had 8 sands with 256 feet of production pay. We expect to bring this well into production during the third quarter.

The No. 4 well, is a well that we drilled which is seen two sands in the Rob-L section that we reported in June with 112 feet of net pay. We’re now drilling to just below 17,000 feet towards a targeted depth of 18,500 feet.

Our No. 5 development well was commenced drilling on July 1. We’ve made very significant progress in the short period of time because we’re now below 9,700 feet drilling towards the depth of 18,400 feet.

As we have mentioned in the past and based on our recent drilling success, we expect to have multiple opportunities to drill well in this area to further delineate this very large structure, as well as develop the significant sands that we’ve discovered in our previous well.

We do benefit as part of our feature of our deep gas, deeper pool exploration strategy of being able to bring this production on line quickly using the existing infrastructure from the very significant amounts of production that occurred at shallower depths historically.

On Page 8, we have a summary of the wells that have been drilled to-date. In the Flatrock Field our discovery in mid-2007 well, and now No. 2 well are producing. As I’ve said, the No. 3 well is expected to come on production in the third quarter.

Two development wells drilling and we have a delineation well which will be spud during the second half of the year, and we’ll be evaluating future drilling activities to be undertaken in the area.

Page 9 shows the location of these wells in a schematic of where they are on Blocks 212 and the Blocks to the south of 217, and how this area relates to the previous discoveries we’ve had that are Hurricane and Hurricane Deep prospects.

We did have an update from our independent reservoir engineers, Ryder Scott Company to evaluate our reserves as of mid-year, and we’ve reported that. We now have 400 Bcf growth reserves with 74 Bcf reserves net to our company’s interest.

The chart on Page 10 shows a cross-section of this prospect and the Hurricane Deep wells that we drilled earlier. As those of you who have been following us know that we’re drilling these wells to the upper Miocene sections that lie below roughly 15,000 feet.

They’re set off by a regional fault that then allows us to test three sand sections in the upper Miocene, Rob-L, the deeper Operc and Gyrodina. Throughout this area, the JB Mountain and Mound Point area, we’ve been able to establish through the drilling that we’ve done to-date, well-developed sands in all three of these sections.

This is what gives us the opportunity to have such significant producing wells by having stacked sands of significant stability to flow at very high rates.

The total reserves and how they relate to changes that we had during the first half of the year is illustrated as a roll-forward on Page 11. At year end we had 364 Bs of equivalence.

We had 53 Bs of production in the first half of the year and we were able to replace significant amounts above that to end up with 400 Bs, based on a PV-10 approved reserves at prices at the end of June, discounted 10%, ending up with a PV value of just under $4 billion.

We talked about, at the time of the Newfield deal and as we were doing our financing to take out the bridge that was provided by the investment banks, that our objective would be to seek to replace the inherent decline that was in the Gulf of Mexico type production that we acquired from Newfield with our exploration.

Now, with our success at Flatrock we have been able to do that during the early stages of this production. We have significant reserves, or probable and possible reserves in addition to our proved reserves, the total 3P reserves, based on the Ryder Scott analysis, was over 700 Bcf of equivalence.

At the time that we are replacing the reserves, it reflects the very strong and positive production results that we’ve been able to sustain from the Newfield properties. We’re meeting our targets and that’s what’s generating the very significant cash flows to achieve our objective of reducing the debt we incurred in the acquisition.

So all the things that we have set out to do over the past year since we did the Newfield deals are really coming together in a very positive way for our company.

Page 12 shows the analysis of our reserves. The reserves are just under 70% natural gas. Oil includes the oil from our Main Pass production facilities. The 400 Bs include approved reserves include significant non-producing reserves.

A big part of this is the non-producing reserves associated with the Flatrock discovery and we’ll be able to bring those into production very rapidly, but it also includes behind pipe and undeveloped reserves associated with the former Newfield properties and our operating team is doing an excellent job of taking those non-producing reserves and transferring them into the producing category on schedule to sustain our production profile.

The chart on Page 13 shows the entire Mound Point, JB Mountain area and this area that had the very significant historical production that came from the Tiger Shoal in Mound Point fields. You can see the north south alignment of the Flatrock wells in the northwest section of this 150,000 acre position.

Our original well was drilled in the Mound Point area to the northeast and we have significant additional exploration opportunities there. The success of the JB Mountain wells in the southern part of the prospect of this prospective area is the one that really set off the series of successful drilling that we have to-date and we have significant new wells to be drilled, as we go forward into 2008 and beyond.

We’ve used the chart before on Page 14 to show this area again in terms of where the location of the historical shallow production was. You can see those structures were in the northern part of the area. Tiger Shoals in Mound Point that’s in the red. The lined area shows the proven deep areas that we’ve been able to establish through our exploration and delineation drilling to-date.

I’ll really point out the pink areas which we used to illustrate areas within this 150,000 acre lease position where we have significant potential. So even though we’ve done drilling, we’re building up production, the point here is that there’s additional areas of significance to explore, as we go forward.

Page 15 talks about the well that we will be drilling called Mound Point East. This well was spud at the end of March of this year. We drilled it to 17,000 feet. We had mechanical issues, bypassed those in July. We’re drilling again to a depth that is roughly 1,000 feet below where we are today.

This well is targeting similar geologic features seen in the Flatrock discovery. We may decide to drill this deeper to test the Gyrodina Sands and this is an area of where we have a 32.5% working interest with a net revenue interest of 23.2%.

Page 16 again shows how these features and subsequent wells that we’ll be drilling to test them relate to the overall geological structures and the sands sections that we have seen productive throughout this area and it just gives us an excellent opportunity to further determine what this prospective area holds for us.

Page 17 shows how the JB Mountain, Hurricane Deep and the Mound Point area tie in, and again, illustrating the opportunities we have of seeing significant sand sections at different horizons within this upper Miocene, set off by the major structures that end up providing the trapping mechanism for us to test.

Our acreage position is shown on Page 18. As we go through time, of course, we will deal with expiration of leases. We’ve seen some expirations during the second quarter, but we structure our exploration program to test prospective areas based on the timing of the lease holdings that we have.

We have rights in the Gulf of Mexico to 1.3 million gross acres today; 280,000 of those acres are in the ultra-deep trend, and that is an opportunity that came to us through the Newfield deal that really is exciting.

It gives us a chance to use the exploration expertise that Jim Bob and his team have in drilling these Miocene age sands, and the ability to apply the drilling experience and technology that we’ve been able to gain for our company through this deep gas exploration program that we’ve been pursuing since 1999.

Of course, there’s a lot of focus on the well that we are drilling in the South Timbalier area; the well that Newfield and his partners call Blackbeard. This is at South Timbalier Block 168. It’s in 70 feet of water on the shelf of the Gulf. The previous consortium of companies had drilled this well to just over 30,000 feet.

We acquired the rights to a working interest in the property and are operating the drilling to deepen this well. Since we have reentered the well we have drilled roughly 2,500 feet of new hole since April of this year. During the course of that drilling we encountered potential hydrocarbon bearing zones that we will require further evaluation.

We’re focused today on drilling the well deeper to test the prospective horizons at depth. We are currently at roughly 32,550 feet. That makes this the deepest well ever drilled in the Gulf of Mexico below the mudline.

We set seven-inch protective casing to just above 32,000 feet in June. We have now received the permit and authorization to drill this well to 35,000 feet, and we’ll be making determinations on drilling as we gain information as we continue to drill. We have a working interest of 32.3% of the well, so we’re drilling forward.

Page 19 shows the nature of this prospect. It’s drilling to Miocene age sands that have been deposited in the shallow waters of the shelf of the Gulf of Mexico, but which have been drilled in a productive fashion in the deepwater where the same sands were deposited.

Previously the industry just had not drilled wells from the shelf but there had been significant drilling to the same age sands and same prospective areas using deepwater drilling technology. Of course, costs are different to drill in the deepwater and development costs are much more significant and the timing to bring production online is much longer.

The opportunity we have here is to drill a deepwater type prospect from the shelf and achieve the benefits of the lower development costs and the shorter time horizon to bring it on production.

Page 20 shows the information that I’d presented earlier, the location of this well. As I said, we’re permitted to 35,000 feet. We have seen some interesting sands that we’ll evaluate once we complete our drilling activities.

In summary, our exploration strategy that we had been focused on before the Newfield deal continues in the same way that it did before. We’re still looking for the Miocene age sands and the 15,000 to 25,000 depth horizon.

We’ve had success at Flatrock. We’ve got additional significant opportunities that we had in that 150,000 acre; we’ve seen other prospects that we have the opportunity to pursue.

Our strategy that was in place before the Newfield acquisition continues, and in fact, the success that it occurred concurrently with the Newfield acquisition is really what gives our company such a positive setting today.

Coming with that acquisition, of course, is now this ultra-deep play, which gives us more exciting exploration opportunities.

We feel very good about integrating our existing business with the Newfield properties. We have a team that’s focused on generating cash out of those assets, and we’ve been successful in doing that, which has allowed us to achieve our objectives in a very timely fashion.

Reducing debt, of course, benefited by the very strong prices for natural gas and oil that we’ve benefited from the last year.

Talk a bit about Main Pass. Page 21 we show a picture of the remaining facilities that we had at our former sulphur mine there. This was, at the time it was developed in early 1990s, the largest production facility in the Gulf of Mexico. Predecessors of our company and its partners spent $1 billion to co-develop oil production and sulphur production.

We operated the sulphur mine from the time of its development in the early 1990s until August of 2000. At that time sulphur prices dropped to low levels and natural gas prices rose, and we ceased production of sulphur. The sulphur resource is still there. We had a remaining recoverable sulphur tons of 60 million tons.

The chart on page 21 is a very interesting chart showing after years of sulphur prices being depressed, economic conditions related to the uses of sulphur in the fertilizer, mining industry and other industries and supply issues have caused the price of sulphur to rise to dramatic levels.

Currently the price of sulphur is $450 a ton. There were times that we can all remember at Freeport when the price of sulphur dropped below $30 a ton. That’s a feature of today’s commodity markets, and we retain the rights to this sulphur. We are currently pursuing the opportunity to develop it at various levels of production, if we can find the right market.

It was $450 a ton when the price per years was in roughly the $50 range, as you can see by the chart. So we’re looking at this opportunity to see how we develop it. We have dismantled our sulphur mining facilities in large part, but we still have platforms there that would allow us to develop this and consider it if market conditions and opportunities arise for us.

We’re continuing to pursue, to look at the opportunity for using the facilities for other energy uses. We call this now the Main Pass Energy Hub, and on Page 22 we have the summaries of our permitted LNG receiving facilities. We’re continuing to monitor that market. The market is currently not there for its development, and we won’t go forward with the development until we have opportunity to develop supply contracts for it.

But it is a potential future business opportunity for our company and it has a number of positive aspects that would allow it to be effectively used as an LNG port. We’re also looking at the possibility of using it as a storage facility for natural gas liquids and other petroleum products. This is potential assets of future significance to our company.

Page 23 shows our 2008 outlook. We’re currently providing guidance on 2008 production for an average of 285 million cubic feet of equivalence a day, with 280 during the third quarter of the year. This is significant because we’re using our new production to offset the declines that were inherent in the properties that we acquired.

We continue our active drilling program, as I mentioned, at OCS 310/State Lease 340 with the Flatrock development delineation wells, as well as new exploration opportunities there. The South Timbalier ultra-deep project will continue, of course, and we have a new exploration project that we’ll be drilling in St. Mary Parish, where we’ve had success in drilling on-shore in the Gulf Coast region.

Current estimate capital expenditures are estimated $260 million. That’s $90 million for exploration/exploitation at Flatrock and elsewhere, and $170 million for development. But with the dynamic nature of our company, our spending on both exploration and development could well change, is likely to change, based on what we have going forward.

We have significant amounts of cash that allow us to take advantage of all the opportunities that come to us. You can see on the chart on Page 24 the strength of our cash flows.

2008 EBITDAX, using the forward pricing curve for oil and gas, would be $1.155 billion, and that would leave us with excess cash flows over our requirements for capital expenditures and financing of almost $650 million, roughly.

Our financial policy, as we go forward, is to maintain a strong balance sheet to fund our future growth. We’re going to commit capital to high potential opportunities; aggressively develop the successes that we have so we can turn the reserves and resources into cash flow.

We will continue to work with partners to be able to spread risk among a number of different properties, these high potential, high risk properties, and we’ll continue to reduce our debt using our cash flows.

That is a summary of where we are; where we’re going. We’ll now turn the call over so that we can answer questions, and Jim Bob is here to respond.

Question-and-Answer Session


(Operator Instructions) Our first question comes from the line of Nicholas Pope - JPMorgan.

Nicholas Pope - JPMorgan

First question. I wanted to get into this sulphur facility. What kind of production capacity are you all looking at if that thing came on line; like in a daily or annual rate?

Richard Adkerson

That would depend, Nick, on how we develop it. The original project had very significant amounts of production in it. It ranged from 1,500 to 3,500 tons per day, and it could have gone up to 5,000 tons per day. But that was on the basis of developing the entire salt dome.

We have the opportunity here of looking at a major development which would require significant amounts of capital, or perhaps there are sections of the dome that could be developed with lower amounts of capital and could end up with ranges of 1,000 to 1,500 tons per day.

This is at an early stage. The sulphur market has changed so much. Many in the industry expect these prices not to be sustained because of the amount of sulphur that’s available in the world, but people have said that about all commodities. So this is something that’s developed just in recent months, and we’re at the early stages of looking at how we might take advantage of it.

Nicholas Pope - JPMorgan

Just looking at the excess cash flow you’re talking about, what are some of the opportunities that are available? What are you looking at? Are acquisitions potentially on the table or an increase in the drilling profile? What could you potentially do with this excess cash?

James Moffett

Let’s look at our history. We built the company with our exploration expertise. Obviously the Newfield acquisition was an unusual opportunity for us. So we never rule out either course of action, as far as creating the company, but we look for in an acquisition, not just an acquisition of production but of exploration potential.

I think that’s been borne out by the way the Newfield deal has played out. But to answer your question simply, Nick, we drive our values by being successful explorers.

Nicholas Pope - JPMorgan

Just to clarify something here, the Tom Sauk/Gladstone/Northeast Belle Isle, are those all spudding in 2008?

James Moffett

Those wells are in the queue. We have partners. Everybody is taking a look at how we go from this point. The major challenge we have is really shown on slide 16. When you look at the Flatrock field and see the amount of production that we’ve been able to find under the 3.4 Tcf Tiger Shoal Field, Mound Point was where we drilled our original deep well and found Operc and Gyrodina production, but we’ve never seen any Rob-L production at Mound Point just to the east.

The reason why that’s a challenge for us is the geology is similar. As a matter of fact, Mound Point is bigger and (inaudible) is higher structurally, that’s why we drilled it first. And there’s got to be a sweet spot that we have to prove, frankly, that is not there.

With all the Rob-L production at Tiger Shoal and knowing that we have Operc and Gyrodina and several wells at Mound Point, we’ve got this – I don’t know how to explain it other than huge structure that’s a twin structure shallow and then we just got to go find the sweet spots in these three Rob-L, Operc, Gyrodina lithofacies that we’ve seen all our success in.

So these proposed wells will get drilled at some point in the next 12 months. We’ll let the success of each well and the success at Flatrock guide us to find those sweet spots by drilling the best wells first.

Nicholas Pope - JPMorgan

Okay. And looking at Mound Point East, you are doing low well drilling on this well, right?

James Moffett


Nicholas Pope - JPMorgan

Are you in the Operc at this point?

James Moffett

We’re in the Operc. We haven’t seen any significant hydrocarbons. We’ll see what happens as we drill deeper. As you can see, it’s on the very far east of the structural play. We had an acreage situation where we had the State of Louisiana with a well commitment. So we jumped.

We played leap frog. We leaped over some of the Gladstone and Tom Sauk locations that were closer to Flatrock, but we had some expired leases that we had to go drill. But we’re just into the upper Operc. We’ve got the lower Operc and Gyrodina. So let’s see what we get; use the data to try to zero in on where the sweet spots are. So stay tuned.

Nicholas Pope - JPMorgan

All right. Thanks a lot.


Your next question comes from the line of Gary Nuschler - Jefferies & Company.

Gary Nuschler - Jefferies & Company

Thanks. Good morning. First question over back to the sulphur mine, I realize you still have to conduct your feasibility study, but do you have a rough idea of what operating expenses might average at this point?

Richard Adkerson

That is something that will vary depending on the size of the project that we’re looking at, and it’s just really too early to make any kind of comment on that.

Gary Nuschler - Jefferies & Company

Okay. Will the largest component of that be what; is it natural gas?

Richard Adkerson

Natural gas would be the largest element of the operating cost.

Gary Nuschler - Jefferies & Company


Richard Adkerson

Because natural gas would be used to heat the sea water to be used in fresh mining.

Gary Nuschler - Jefferies & Company

Okay. And then my last question is back to South Tim 168. I believe the original AFE in this was around $32 million. Can you update us where you stand relative to that original cost estimate?

Richard Adkerson

The current cost that we have to-date on that is about $55 million, because of the original drilling and issues that we faced in drilling. That’s the cost that we’ve incurred to-date on it.

James Moffett

The $30 million AFE was to get us basically 1,500 feet below the TD of the existing Blackbeard well. We’ve since pushed that target down another 1,000 feet and have permitted another 2,500 feet of drilling. So we actually drilled the original AFE down to the 1,500 feet; twelve 1,500-foot depth that we had AFE’d, for just about the AFE.

So the over expenditures are because we’ve drilled deeper than the original AFE. I keep telling people, they say how is the drilling going? I say, for a well this deep it’s been fairly routine.

Gary Nuschler - Jefferies & Company

Okay. I appreciate it. Thank you.


Your next question comes from the line of Kent Green - Boston American Asset.

Kent Green - Boston American Asset

A great quarter fellows. I had a question about Flatrock No. 3. You’re currently producing from the Operc pay in that particular well, and you bypassed several Rob-L sections. Have you released any information as to what other production sections could be available at Flatrock at various stages of these wells?

James Moffett

Let’s see, you’re asking about the No. 3 well?

Kent Green - Boston American Asset

Yes, you’re producing from an Operc pay, which is lower.

James Moffett

Yes, we went deeper on that well, and we found below the Rob-L pays that we’d already drilled. And the Operc, of course, is very well developed, got four different zones. So we started at the bottom of the hole. Mechanically, from an engineering standpoint, that’s where you go.

The other sands up the hole and the Operc will be taken in order as we complete the depletion of each of these reservoirs. Of course Rob-L is above that.

We’re studying as we go how many wells we want to drill to each of these horizons so that we end up with the best economical development program. We have to first pick our choice of how many Bcf per well we want to deplete in the various zones, and that’s why we’ve made the comment about our reserves to-date.

If you look at our reserves to-date, the evaluation of the first four boreholes is not completely down through the Operc. That’s the well we’re currently drilling, called the 231.

So as we get the fifth and sixth well drilled, we’ve got some room to the south, a couple of miles that we don’t really have any data to look at the southern extent of the Operc and the deeper Gyrodina.

So to answer your question, we’ll take these things mechanically, as I say, usually start at the bottom zone and work up to the top. In the case of the No. 229 well, we had this Rob-L 10-4, which is the thickest sand of the eight sands, and that’s where we completed over a hundred million a day.

We should have at least four or five completions in that zone alone, and in the other zones we’ll decide how many wells we drill as what we call acceleration wells or whether we wait and take plug backs. So that’s going to unfold here in the next several months.

Kent Green - Boston American Asset

Very good. Jim Bob, just a more broader question. You have a whole lot of acreage out here in the Gulf outside of the Flatrock/Mound Point area. What priorities will you use to drill those acreage, and have you got a team starting to evaluate those priorities, even though it looks like you’ve got a lot of years of work still around Flatrock?

James Moffett

Great question. We’ve been focusing, since we made the Newfield acquisition, on all of the acreage that we control. We’ve got different teams working different parts of the Gulf of Mexico. Obviously I’m spread across all of that.

We’re looking for the best opportunities that are available, and we used the examples that we’ve used from the beginning of this deep wedge play in the pressured section, and we put no priorities on who and how we got the acreage.

We’ve just thrown all the acreage into the pool, and as you know, after we made the Newfield acquisition, there were two major lease sales where there were several hundred shelf leases acquired in both the lease sales and all the activity that that’s created.

So to answer your question, we’re looking at the entire spread of the acreage, and we’re going to ferret out the best opportunities. As Richard just showed you, we’ve got the cash now to take advantage of the opportunities if they fit our model, and so far our model is working pretty good.

Kent Green - Boston American Asset

Yes, I’ve got your success ratio at 53%, which is, in exploratory wells, much higher than the historical level. And this is a result of your teams working on formation drilling, primarily?

James Moffett

I used the word a model. A geologist has to have a model to set up a trend. In this Miocene, what we’ve proven is, as you go from north to south, whether you’re on-shoring the primary line where we have the Long Point and Liberty Canal big wells, or to the south where you get into Rob-L, Operc, Gyrodina, as long as you stay in those fault wedges, we have this dynamic structural situation that creates, we call them, wedges of sand in the pressured areas, you’ve got this opportunity to find these big pools of pressured hydrocarbons that’ll flow back at high rates.

The answer is, that’s a model we’ve used to get the success rate. Since it’s working so well, we’re just going to stick to the niche we have. Of course now we’ve got this ultra-deep play which is below the so-called trapdoor fault wedging that we talk about. It’s more of a sheet sand in a compressional environment.

You’ve seen the slide that showed the full belt under the so-called trapdoor geology, and those big structures are anywhere from 5 to 15,000 acres big. They are big, broad, flat structures as opposed to the sharp salt domes that we’ve seen above the listric in the traditional drilling of the shelf.

But the fact that they’re so big and flat, like the deepwater plays, if you find a production on them, they cover huge areas. So as I say, everybody stay tuned, because it’s going to be an interesting ride both on the traditional shelf and the ultra-deep drilling. Let’s see where we go.

Kent Green - Boston American Asset

Thank you very much.


Your next question comes from the line of Michael Henzi - Sterne, Agee & Leach.

Michael Henzi - Sterne, Agee & Leach

I’ve got a number of questions. In the press release about Blackbeard West No. 1 there’s a statement that says that ‘logs indicated that the well has encountered potential hydrocarbon bearing zones that require further evaluation.’ Are the logs to which you are referring recent logs, or is this the original thing? My question is, have you gotten any logs since you’ve been drilling below 32,000 feet?

James Moffett

No, not below 32,000 feet. We have some additional logs since the original statement was made, that we had a potential hydrocarbon zone. We continue to get additional zones that appear to be hydrocarbon bearing.

The problem while you’re drilling, Michael, you can’t flow test these things, and we’re drilling at deeper depths than people have seen. The porosity and permeability that we’re seeing with the 30,000 pounds of bottom hole pressure, there’s no go-by as to what kind of flow rates you can expect from the sands that we are seeing in this well yet. So we need a flow test, more than likely, to tell.

Complicating the answer to your question, if you’re following some of the recent announcements in the deepwater, there’s a field that Anadarko has been talking about called K2 field. And if you’ve looked at the data that they’re putting out, which is available to everybody, the first wells they drilled on this big structure encountered some sands on top that were of x thickness.

As they went off to flank of this structure, the sands became 4-, 5- and 10x thickness, and that field has gone from 0.5 billion barrel potential to, I think, their last numbers are 2 to 4 billion barrels.

What this has proven is that these structures that are in this full belt, the ice pack we see off the flank does, as it has traditionally indicated, give you an opportunity that you’ll have much thicker sands on the flank of these structures than you do on the very top.

Now the location that was drilled here at Blackbeard is right in the bull’s eye of the big 10,000-acre structure. The question is, how far down dip do these sands go? And are they going to thicken the way they do in the few wells that have been drilled off structures looking for the down dip limits of these big fields in the deepwater?

We’ve got that in front of us. But since the similarities in these fields to the deepwater fields are what we’re playing, we have to assume that that’s likely to happen. If you take the area that these sands could cover and add any thickness to them down dip, that’s the kind of information we’re talking about when we’re saying that they’re potential hydrocarbon reservoirs.

We’ve drilled; we’ve seen porosity; we’ve seen hydrocarbons. Now we’ve got to just prove what their flow rates will be and how much area they cover.

Michael Henzi - Sterne, Agee & Leach

Do you know if it’s oil or gas down there?

James Moffett

Do not know. We’ve tried everything we can to analyze; the cuttings are so badly beat up on. But frankly, the data we have, because of the depths and the pressure, it could be either.

Michael Henzi - Sterne, Agee & Leach

I talked to John Schiller and a couple of your partners, and they indicate that from what you’ve seen so far on Blackbeard West No. 1, that you are fully justified in drilling Blackbeard East. Are you going to drill Blackbeard East?

James Moffett

I don’t know what John Schiller has told you.

Michael Henzi - Sterne, Agee & Leach

What he said exactly was that from what they’ve seen in the well, you’re justified in doing it.

James Moffett

The answer is we’re looking at all of our options. We have a number of plays in this trend. Whether Blackbeard East would be the next well to be drilled or whether it’s one of seven or eight big prospects that we have, there are a lot of things to be considered.

Some of them shallower than others. Some of them have more information than others. I don’t want to commit us right now to which is the next location. I think that it’s well No. 2.

Number one, we’ve proved that we drilled it deeper and that the formations can be drilled as we have drilled our deeper wells on the shelf in the shallower formations. That’s the first thing we’ve proven.

Number two, we appear to have sands. We appear to have hydrocarbons. We can prove they’re commercial. We’re making great strides every day. Every foot we drill out here, Michael, is new territory. The good news is, we don’t know what’s down there; the bad news is, we don’t know what’s down there.

So we’ve got to get this well drilled on down to the next 2,500 feet; see how many more zones we have, if any; look at how they relate to the stuff that’s been drilled offshore in the deepwater; use every geological talent that we have; pick the best of these other features.

The most important thing is the other features are big; they’re very defined by seismic, and whatever we prove here as a model, as we’ve discussed about our traditional drilling in the shelf, deep gas plays above 30,000 feet, everything we can do to prove these models work will give us that much less risk on these other prospects.

I hope, Michael, that that gives you where my exploration thinking is today.

Michael Henzi - Sterne, Agee & Leach

It does. A question on the sulphur. I’m no sulphur analyst; I’m an oil and gas analyst. I was wondering if you could give us some guidance about how much bottom line profit per ton you make at $450 of ton?

James Moffett

Can’t tell you until we finish the analysis. But what’s got us stimulated, Michael, is that we originally went forward with this project at $125 sulphur. That was what the feasibility was when we first built the first sulphur, when we found this in ‘88.

So 60 million tons of sulphur is the largest remaining reserve in North America. It’s in an area where we’ve already got some infrastructure. If the prices of sulphur can be predicted in any fashion, if we could build this thing at $125 sulphur in the early ‘90s, we have to determine what kind of price can we project? You can do the numbers yourself.

At $100 a ton of profit, you can run the numbers out on 60 million tons of sulphur. It’s an opportunity we can’t take lightly, because that’s a lot of money. Remember, the reason why prices are up is because people all are squeezed. The sulphur suppliers, when biofuels exploded and everybody started planting every acre they could around the world to make biofuels, the price of fertilizer has tripled and quadrupled.

Sulphur and phosphate rock and nitrogen, ammonia are the three components, and all these components all of a sudden are in great demand. There are other uses for sulphur. Sulphur is used for extracting copper in the copper business.

So there’s just a new paradigm in this sulphur industry. Any time you see prices jump over $450 a ton, some of these prices have spiked on the spot market above that, we’ve got to take a look at this 60 million-ton resource we have out here where we already have some metal in the ground and can use this metal for multi uses.

You say you’re not a sulphur analyst; you’re a financial guy. You sit down and play the game; it’s a significant potential for us, and we’re going to make sure we take advantage of it.

Michael Henzi - Sterne, Agee & Leach

How much capital expenditure will be required to bring it on?

James Moffett

Under different scenarios, depending on how much sulphur you want to try to develop in the quadrant. The way you develop these big sulphur deposits is you actually move around. In the old days they used to have a platform that swung around like the hands on a clock.

Today, with all the horizontal drilling techniques, which is what we used to develop and produce the sulphur in the ‘90s, you just set up on a platform and you just drill these horizontal wells.

You produce this sulphur in quadrants, like slicing up a pizza. You get in and you develop a part of it, and as you heat the dome, it starts to affect other areas, and you just go in there and pop these little wells down in a horizontal fashion. The sulphur is at 1,200 feet by the way in the cap rock on top of the dome.

Michael Henzi - Sterne, Agee & Leach

My back of the envelope calculations indicate to me that you’re probably going to be doing 500 million cubic feet a day exit rate this year from Flatrock, gross, which would indicate that you’re going to be getting about 100 million cubic feet a day net to McMoRan.

Yet, the guidance on the production would imply flat without any uptick, say for example, in the fourth quarter.

James Moffett

The reason we’re being cautious about that is Chevron is the operator of the production, and they’re going to upgrade their facilities. They’re trying to stay out in front of this thing, and we just don’t know by the end of the year, Michael, whether they’re going to have the facility expanded enough to be at the rates that you’re mentioning.

We clearly have the well that we can drill and complete and have ready to produce those kind of volumes. But the only thing you’re seeing in our projections is that we don’t want to have any overstatement of what we can do by year end that might be facility constrained.

We can get the wells drilled and completed. It’s just a question of whether in these two quarters we can get them all on production. You follow where I’m coming from?

Michael Henzi - Sterne, Agee & Leach

I understand. You’re basically going to be facility constrained rather than the ability of the wells to produce.

James Moffett

That’s correct. And of course the big facilities are in 10 feet of water, and it’s just a question of getting them upgraded because they all were first built to produce normal-pressured wells.

As you might imagine, as we start to drill these wells, we predicted early on that the pressures and the porosities and the permeabilities were going to flow these high rates. I’m trying to see how I can say this very politely. Some other people needed to be convinced with these flow tests. Now that they’ve seen them, you see a lot of activity with people jumping around trying to get caught up with this facility thing.

But big wells, as you know, in the shelf have been 15 to 25-million-a-day wells. Some people incorrectly thought that the only place you got wells that flow 100 million a day were in the Tuscaloosa and Mobile Bay or in the deepwater where they had to flow these wells at high rates because of the cost of the facilities.

What we’ve proven is the rock quality that we’ve been predicting has turned out to be exactly as we predicted. Now that people see these wells can be produced at rates of 50 to 100 million a day, you can start adding up these completions.

The facilities will get built; it’s a question of whether or not by the end of the year, into the first quarter or the second quarter of 2009. It’s coming, Michael; your numbers are correct. It’s just a question of us trying to be sure that we aren’t facility constrained. You guys are great followers of our story, and you get mad at us when we give you projections that we don’t meet.

Michael Henzi - Sterne, Agee & Leach

I’ve got one final question for you, Jim Bob. I asked you at the first quarter conference call if Mound Point/Gladstone area could be the size of Flatrock, and you said yes. You’ve gotten more experience drilling in that area. Is the answer still yes?

James Moffett

The answer is we haven’t done enough over at Mound Point. All we’ve done at Flatrock is prove that Flatrock is Flatrock. If you try to create new beauties today, you want to find another Flatrock.

As I said in my earlier answer, Michael, the Mound Point structure was a twin structure shallow; produced 2.6 Tcf of gas. It’s bigger from an area standpoint; is higher structurally. These sands are so thick what we have to do is find the sweet spot.

In other words, we have Operc and Gyrodina production established at Mound Point. We have not seen one hydrocarbon show in the Rob-L. That doesn’t make sense to me geologically. As we try to get these projected seismic amplitudes tied into the existing production, we’re even trying to see if we can see some signatures that would put us in the right fault block at Mound Point.

But to answer your question specifically, the sands should be deposited over there. They’re thick. If we can fill up some areas and figure out the structural and stratigraphic trap, we got to go over there and prove that it’s not as big as Flatrock. It’s so much of a comparison just across the syncline, as you can see from the cross section we’ve drawn, you literally got to go over there and prove that it’s not there.

Michael Henzi - Sterne, Agee & Leach

That’s wonderful news. Thank you, Jim Bob.


Your next question comes from the line of Bill Dobbs - Merrill Lynch.

William Dobbs – Merrill Lynch

Just a quick question about the sulphur assets; the old Freeport sulphur stuff contained some railcars and a lot of the infrastructure assets. Are those still part of the company, or are they mothballed or did we trade those on to someone else?

James Moffett

They’ve been sold. But those transportation facilities would be available if the sulphur market stays the size it is, Bill, all of that’ll get built into the model. The people that own those facilities now, are in the ag-minerals business, are some of the first people that obviously we’re going to be trying to marry up with this sulphur, since they’re the people that are getting squeezed.

William Dobbs – Merrill Lynch


James Moffett

Let me just say once again. Prices don’t go up because people aren’t squeezed. To see this kind of an elevation of prices, the industry is squeezed right now. They’re constrained by facilities and transportation. There’s sulphur in parts of the world, but they can’t get to it, or these prices wouldn’t be where they are.

William Dobbs – Merrill Lynch

Yes. So are those assets in use by, would be Mosaic at this point?

James Moffett

To our knowledge, they have to be using them because it’s the only thing they have to transport the sulphur.

William Dobbs – Merrill Lynch

Yes. Okay.

Richard Adkerson

Bill, there’s a joint venture that Mosaic has, and a lot of the assets that you referred to was part of our merchant business that we were involved in.

William Dobbs – Merrill Lynch

Yes, with the refiners, right?

Richard Adkerson

Right, from refiners. Actually, the transportation from Main Pass would be a simple ocean-going barge to Tampa. So a lot of those other assets are engaged in a different business that we were in then, that we would not be in now if we find a way to develop this resource.

William Dobbs – Merrill Lynch

Okay. Thank you very much. I just wanted to get a refresher there.


Your next question comes from the line of Gregg Brody - JPMorgan.

Gregg Brody - JPMorgan

Just a couple of quick questions. The feasibility study for the sulphur, when do you expect to have that completed by?

Richard Adkerson

We are right now in the process of evaluating this. We haven’t even initiated a feasibility study at this point.

Gregg Brody - JPMorgan

So it could be a little while until you have a view on this?

Richard Adkerson


James Moffett

With these kind of prices here, we aren’t going to tarry. Once again, the partners that are squeezed, that have caused these prices to go up are the first people that we’re going to be looking at as to possible financing, et cetera. So when we say feasibility, we’re talking about engineering feasibility and the financial feasibility, and the two of those will drive this model and determine how quickly we get going.

Gregg Brody - JPMorgan

That’s great. As just a refresher, where does the (inaudible) stand as of quarter end?

Kathleen Quirk

It’s just under $280 million at the end of June.

Gregg Brody - JPMorgan

Thank you very much.


Your next question comes from the line of George Foley - Foley Investment.

George Foley - Foley Investment

Great morning. I’m looking at the chart with the deep shelf and the deepwater showing the zones. We should now, at 32,550, be in the lower Miocene. Is that right, Jim Bob? What does it look like?

James Moffett

We think we’re in the lower Miocene. The cuttings have been so horrible, George, that we’re not even really sure, paleo-wise, where we are in the last 1,000 feet we’ve drilled, because all we get back is basically a powder that this turbine is grinding up.

Every once in a while we get lucky and get some little forams or nanofossils. So we’re either in the lower Miocene or someplace in the upper Oligocene. But based on correlations, we think we’re probably in the lower Miocene time with the seismic. There’s some big events that marked the pre-Miocene. So we think we’re still above the ties to the offshore.

But frankly, George, now that we’re below 32,000 feet, as I said earlier, everybody stay tuned, because every evaluation tool we have is going to be the deepest effort to try to do that. So we’ll sharpen our wits here and figure out exactly where we are.

Importantly, George, it doesn’t matter where we are. If you look at the deepwater, you’ve got production from the Miocene down to the base of the Wilcox. So this structure is draped across what we believe where the carbonates are. Anything that’s over the top of that is an objective section, and that occurs at about 35,000 feet. That’s why we’ve set the depth for this well for 35,000 feet.

George Foley - Foley Investment

Okay. Yes, that’s that [inaudible] section.

James Moffett

All of the above.

George Foley - Foley Investment


James Moffett

As I say, we’re on top of one of the biggest structures we’ve ever drilled in the Gulf of Mexico, and any reservoir rock we see porosity or permeability has got a chance to produce based on what we’ve seen in the deepwater.

George Foley - Foley Investment

That’s great. Then just a quick one. Aubrey the other day made a joke, apparently, that he’d see so much gas coming from his shale plays and stuff that he’s thinking about regasification and selling it in the export market.

Could the Main Pass facility be an alternative for us to turn it around and sell gas up a couple of dollars an Mcf in the export market?

James Moffett

I’ll tell you we haven’t even thought about it. I hope that Aubrey’s right. I hope people can find that much gas and get the country out of the jam that it’s in.

George Foley - Foley Investment

Wouldn’t that be something. Thanks a lot. Appreciate it.


At this time there are no further questions. I would now turn the call back over for any closing remarks.

Richard Adkerson

I want to thank everyone for their interest. As always, we’re here to respond to your questions and looking forward to reporting our results as we go forward in 2008. Have a good day.

James Moffett

Thank you for being on the call, everybody.


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

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